SUMMARY
This
summary highlights selected information contained elsewhere in this prospectus. You should read the entire prospectus carefully,
including the information under the headings “
Risk Factors
,” “
Forward-Looking Statements
”
and “
Management’s Discussion and Analysis of Financial Condition and Results of Operations
” and the financial
statements and the notes to those financial statements appearing elsewhere in this prospectus. The information presented in this
prospectus assumes (i) a public offering price of $ per
share of common stock (the midpoint of the price range set forth on the cover of this prospectus) and (ii) unless otherwise
indicated, that the underwriters do not exercise their option to purchase additional shares of common stock.
Carbon
Energy Corporation
Overview
Carbon
Energy Corporation, a Delaware corporation formed in 2007 and formerly known as Carbon Natural Gas Company, is a growth-oriented,
independent oil and natural gas company engaged in the acquisition, exploration, development and production of oil, natural gas
and natural gas liquids properties in the United States. Our acreage positions provide multiple resource play opportunities and
have been delineated largely through drilling by us, as well as by other industry operators. Our primary business objective is
to grow our reserves, production and cash generated from operations over the long term, while paying, to the extent practicable,
a quarterly dividend to our stockholders.
Our
assets, held through our majority-owned subsidiaries, are characterized by stable, long-lived producing properties in the Appalachian
Basin in Kentucky, Ohio, Tennessee, Virginia and West Virginia; the Ventura Basin in California; and the Illinois Basin in Illinois
and Indiana:
|
●
|
We
own 100% of the outstanding shares of Nytis USA, which in turn owns 98.1% of Nytis LLC. Nytis LLC holds the majority interest
in our operating subsidiaries other than Carbon Appalachia and Carbon California, including 47 consolidated partnerships and
17 non-consolidated partnerships.
|
|
●
|
We
hold a 53.92% proportionate share of the profits interest in Carbon California.
|
|
●
|
We
currently hold a 27.24% proportionate share of the profits interest in Carbon Appalachia. Effective upon the Old Ironsides
Buyout (which we intend to fund using proceeds from this offering), we will own 100% of Carbon Appalachia.
|
In
late 2016, we saw an opportunity to consolidate producing oil and gas properties in Southern Appalachia and the Ventura Basin
as larger E&P companies began abandoning legacy assets in favor of unconventional resource plays. We began acquiring mature,
producing conventional assets with long reserve lives and low levels of base production declines from the following types of companies:
|
●
|
large
companies that deemed such assets to no longer be consistent with their strategic objectives;
|
|
●
|
small
or undercapitalized companies; and
|
|
●
|
companies
seeking liquidity.
|
We
consider the properties that we acquired to be relatively low risk given their established production histories. We believe that
the acquisition prices for these properties were at attractive cash flow multiples and discounts to proved PV-10 values, reflecting
the reduced competition in the market for properties with these characteristics.
Moreover,
these acquisitions enable us to execute on the following operational improvements:
|
●
|
reduction
of per-unit operating costs through basin consolidation;
|
|
●
|
offset
of the natural decline of production from existing properties;
|
|
●
|
consolidation
and optimization of midstream assets; and
|
|
●
|
future
development drilling as commodity prices warrant.
|
To facilitate this acquisition strategy,
we formed, with the assistance of two institutions as part owners, two co-investment vehicles – Carbon Appalachia, which
is focused on acquiring gas-weighted mature properties in Appalachia, and Carbon California, which is focused on acquiring oil-weighted
mature properties in California.
We
formed Carbon Appalachia with Yorktown and Old Ironsides to capitalize on opportunities to acquire producing assets in Southern
Appalachia at a discount to total proved PV-10 and to subsequently create value through overhead and maintenance cost reductions,
field-level optimization and gathering system reconfigurations. Carbon Appalachia focuses on producing gas properties in Southern
Appalachia as economies of scale and efficiency gains from spreading fixed operating costs over a larger asset base are realized
upon integration with our existing asset base in the region.
We formed Carbon California with Yorktown
and Prudential to capitalize on opportunities to acquire producing assets in the Ventura Basin at a discount to total proved PV-10
and subsequently create value through recompletions, returns-to-production and infill development projects. Carbon California focuses
on producing oil properties in California as the production from the region often receives premium pricing relative to NYMEX strip
pricing as a result of increased demand for light oil from neighboring refineries along the West Coast.
Consistent with our acquisition strategy,
we, together with Carbon Appalachia and Carbon California, have deployed a total of $177.5 million of capital across twelve acquisitions
since October 2016. The Standardized Measure and PV-10 of these acquired properties at December 31, 2017 were $404.0 million and
$415.0 million, respectively, the difference from the purchase price reflecting in large part our strategy of buying assets at
discounts to PV-10 and our cost reduction and production enhancement efforts. PV-10 is a non-GAAP financial measure and generally
differs from Standardized Measure, the most directly comparable GAAP financial measure. See “
—Non-GAAP Financial
Measures
” for more information.
Of these twelve acquisitions, four were natural gas weighted and eight were oil weighted. For the
four natural gas weighted acquisitions, we acquired 388.5 Bcf at an average cost of $0.24 per Mcf. For the eight oil weighted
acquisitions, we acquired 30.8 MMBoe at an average cost of $2.79 per barrel. For this group of twelve assets, we have reduced
operating expenses by an average of approximately 30% through June 30, 2018.
We have grown through our acquisition
activities since October of 2016. As of June 30, 2018, after giving effect to (i) the increase in Carbon’s ownership of
Carbon California from 17.81% to 56.41% on February 1, 2018 in connection with the exercise of the California Warrant by Yorktown
and the resulting consolidation of Carbon California for financial reporting purposes; (ii) the completion of the Seneca Acquisition
on May 1, 2018 and the resulting decrease in Carbon’s ownership of Carbon California from 56.41% to 53.92%; and (iii) the
increase in Carbon’s ownership of Carbon Appalachia to 100.0% in connection with the Old Ironsides Buyout, we owned working
interests in approximately 8,960 gross wells (8,200 net) and royalty interests in approximately 1,080 wells and had leasehold
positions in approximately 1,110,000 net developed acres and approximately 540,000 net undeveloped acres directly and through
our majority-owned subsidiaries.
Moving forward, we will continue to evaluate
the use of co-investment vehicles as opportunities arise, with the goal of consolidating them into Carbon at a later date, similar
to the acquisition of the portion of Carbon Appalachia not already owned by Carbon as described under “—
Recent
Developments
.”
The chart below shows a summary of
reserve data as of December 31, 2017 and average daily production data for June 2018 for Carbon California, Carbon Appalachia
and Nytis USA and pro forma for Carbon after giving effect to (i) the increase in Carbon’s ownership of Carbon California
from 17.81% to 56.41% on February 1, 2018 in connection with the exercise of the California Warrant by Yorktown and the resulting
consolidation of Carbon California for financial reporting purposes; (ii) the completion of the Seneca Acquisition on May 1, 2018
and the resulting decrease in Carbon’s ownership of Carbon California from 56.41% to 53.92%; and (iii) the increase in Carbon’s
ownership of Carbon Appalachia to 100.0% in connection with the Old Ironsides Buyout. The below information was prepared pursuant
to the guidelines of the Securities and Exchange Commission for reporting reserves and future net revenue:
|
|
Carbon
California
(1)
|
|
|
Carbon
Appalachia
(2)
|
|
|
Nytis
USA
(3)
|
|
|
Carbon
Pro Forma
Including
Non-
Controlling
Interests
(4)
|
|
|
Carbon
Pro Forma
Excluding
Non-
Controlling
Interests
(5)
|
|
Proved Reserves (Bcfe)
|
|
|
183.3
|
|
|
|
334.8
|
|
|
|
87.2
|
|
|
|
605.3
|
|
|
|
517.8
|
|
% PDP
|
|
|
42.5
|
%
|
|
|
99.9
|
%
|
|
|
99.9
|
%
|
|
|
82.5
|
%
|
|
|
88.9
|
%
|
% Natural Gas
|
|
|
22.1
|
%
|
|
|
99.7
|
%
|
|
|
93.5
|
%
|
|
|
75.3
|
%
|
|
|
73.9
|
%
|
Standardized Measure
($MM)
(6)
|
|
$
|
172.3
|
|
|
$
|
169.7
|
|
|
$
|
59.3
|
|
|
$
|
401.08
|
|
|
$
|
307.50
|
|
PV-10 ($MM)
(6)
|
|
$
|
172.3
|
|
|
$
|
169.7
|
|
|
$
|
70.2
|
|
|
$
|
412.22
|
|
|
$
|
318.24
|
|
Net Production (Mcfe/d)
(7)
|
|
|
11,765
|
|
|
|
40,673
|
|
|
|
16,394
|
|
|
|
68,832
|
|
|
|
61,123
|
|
Reserve Life (Years)
|
|
|
42.6
|
|
|
|
18.9
|
|
|
|
15.8
|
|
|
|
22.0
|
|
|
|
20.4
|
|
(1)
|
Presents 100% of
Carbon California on a historical basis as of December 31, 2017 for reserve data and for June 2018 for average daily production
data.
|
(2)
|
Presents
100% of Carbon Appalachia on a historical basis as of December 31, 2017 for reserve data and for June 2018 for average daily
production data.
|
(3)
|
Presents
100% of Nytis USA and its subsidiaries on a historical basis as of December 31, 2017 for reserve data and for June 2018 for
average daily production data.
|
(4)
|
Presents 100% of Carbon on a pro forma basis including non-controlling interests in Carbon California and Nytis USA.
|
(5)
|
Presents 100% of Carbon on a pro forma basis excluding non-controlling interests in Carbon California and Nytis USA.
|
(6)
|
PV-10 is a non-GAAP financial measure and generally differs from Standardized Measure, the most directly comparable GAAP financial measure. See “—
Non-GAAP Financial Measures
” for more information.
|
(7)
|
Average
net production is provided for the month of June 2018.
|
During 2017 and the six months ended
June 30, 2018, our capital expenditures consisted principally of the Seneca Acquisition, oil-related remediation, return to production
and recompletion projects in California and the optimization and streamlining of our natural gas gathering and compression facilities
in Appalachia to provide more efficient and lower cost operations and greater flexibility in moving our production to markets
with more favorable pricing. Our current capital expenditure program is focused on the acquisition and development of oil and
natural gas properties in areas where we currently operate.
We believe that our asset and lease
position, combined with our low operating expense structure and technical expertise, provides us with a portfolio of opportunities
for the development of our oil and natural gas properties, including a large inventory of potential return to production, behind
pipe recompletion and proved undeveloped drilling projects. Our growth plan is centered on acquiring, developing, optimizing and
maintaining a portfolio of low risk, long-lived oil and natural gas properties that provide stable cash flows and attractive risk
adjusted rates of return.
Recent Developments
Investments in Affiliates
Carbon Appalachia
Carbon Appalachia was formed in 2016
by us, Yorktown and Old Ironsides to acquire producing assets in the Appalachian Basin in Kentucky, Tennessee, Virginia and West
Virginia. Substantial operations commenced in April 2017. As of the date of this prospectus, we own 26.50% of the voting interest
and 27.24% of the profits interest, and Old Ironsides holds the remainder of the interests, in Carbon Appalachia.
We intend to use a portion of the proceeds
from this offering to pay approximately $58 million to Old Ironsides in exchange for the sale, assignment and transfer by Old
Ironsides of all of its interests in Carbon Appalachia (the “
Old Ironsides Buyout
”). Following the closing
of the Old Ironsides Buyout, Carbon Appalachia will be our wholly-owned subsidiary. Our obligation to consummate the Old Ironsides
Buyout is conditioned on the completion of this offering. In addition, the purchase agreement contains certain closing conditions
and termination rights for each of Carbon and Old Ironsides if the closing of the Old Ironsides Buyout has not occurred on or
before October 15, 2018.
We currently serve as the manager of
Carbon Appalachia and operate its day-to-day administration pursuant to the terms of the limited liability company agreement of
Carbon Appalachia and the management services agreement between Carbon Appalachia and us, subject to certain approval rights held
by the board of directors of Carbon Appalachia.
As of June 30, 2018, Carbon Appalachia
owned working interests in approximately 5,200 gross wells (4,800 net) and had leasehold positions in approximately 851,000 net
developed acres and approximately 373,000 net undeveloped acres.
Carbon California
Carbon California was formed in 2016
by us, Yorktown and Prudential to acquire producing assets in the Ventura Basin in California. Prior to February 1, 2018, we held
17.81% of the voting and profits interests, Yorktown held 38.59% of the voting and profits interests and Prudential held 43.59%
of the voting and profits interests in Carbon California. On February 1, 2018, Yorktown exercised the California Warrant, pursuant
to which Yorktown obtained additional shares of common stock in us in exchange for the transfer and assignment by Yorktown of
all of its rights in Carbon California. On May 1, 2018, Carbon California closed the Seneca Acquisition. Following the exercise
of the California Warrant by Yorktown and the Seneca Acquisition, we own 53.92% of the voting and profits interests, and Prudential
holds the remainder of the interests, in Carbon California.
We currently serve as the manager of
Carbon California and operate its day-to-day administration pursuant to the terms of the limited liability company agreement of
Carbon California and the management services agreement between Carbon California and us, subject to certain approval rights held
by the board of directors of Carbon California.
As
of June 30, 2018, Carbon California owned working interests in approximately 540 gross
wells (340 net) and had leasehold positions in approximately 5,000 net developed acres
and approximately 11,800 net undeveloped acres.
Yorktown Ownership
Following the closing of this offering
and giving effect to the Pro Forma Adjustments, Yorktown will own %
of the outstanding shares of our common stock, assuming the conversion of the Preferred Stock (described herein) to shares
of our common stock.
Recent Acquisitions
Historically, we have made acquisitions
through Nytis LLC, Carbon California or Carbon Appalachia, including numerous acquisitions during 2017 and 2018. For acquisitions
by Carbon Appalachia or Carbon California, we typically contribute a portion of the purchase price based on our ownership interest
to fund such acquisitions. In 2018, 2017 and 2016, we contributed an aggregate of $23.9 million to Carbon Appalachia, Carbon California
and Nytis LLC in connection with our acquisition activities, including but not limited to the following:
Appalachian Basin
|
|
Cabot
Acquisition
|
|
EnerVest
Acquisition
|
|
CNX
Acquisition
|
|
EXCO
Acquisition
|
Date Completed
|
|
September 2017
|
|
August 2017
|
|
April 2017
|
|
October 2016
|
Purchase Price ($MM)
(1)
|
|
$41.3
|
|
$21.5
|
|
$20.0
|
|
$9.0
|
Acquiror
|
|
Carbon Appalachia
|
|
Carbon Appalachia
|
|
Carbon Appalachia
|
|
Nytis USA
|
Net Acres
|
|
701,700
|
|
320,300
|
|
142,600
|
|
411,400
|
Gas Wells
|
|
3,000
|
|
864
|
|
181
|
|
2,250
|
Miles of Pipeline
|
|
3,100
|
|
310
|
|
180
|
|
1,120
|
Net Production (Mcfe/d)
(2)
|
|
36,500
|
|
7,600
|
|
4,178
|
|
10,105
|
PDP Reserves (Bcfe)
|
|
279.4
|
|
35.6
|
|
19.3
|
|
51.8
|
Proven Reserves (Bcfe)
|
|
279.4
|
|
35.6
|
|
19.8
|
|
51.8
|
Ventura Basin
|
|
Seneca
Acquisition
|
|
|
CRC
Acquisition
|
|
|
Mirada
Acquisition
|
|
Date Completed
|
|
|
May 2018
|
|
|
|
February 2017
|
|
|
|
February 2017
|
|
Purchase Price ($MM)
(1)
|
|
|
$ 43.0
|
|
|
|
$ 34.0
|
|
|
|
$ 4.5
|
|
Acquiror
|
|
|
Carbon California
|
|
|
|
Carbon California
|
|
|
|
Carbon California
|
|
Net Acres
|
|
|
6,500
|
|
|
|
8,900
|
|
|
|
1,400
|
|
Oil Wells
|
|
|
310
|
|
|
|
191
|
|
|
|
43
|
|
Net Production (Boe/d)
(2)
|
|
|
915
|
|
|
|
666
|
|
|
|
110
|
|
PDP Reserves (MMBoe)
|
|
|
6.7
|
|
|
|
5.6
|
|
|
|
0.9
|
|
Proven Reserves (MMBoe)
|
|
|
17.3
|
|
|
|
11.3
|
|
|
|
1.9
|
|
(1)
|
Purchase prices do not include certain closing purchase price adjustments.
|
(2)
|
Average net production
is provided for the month of June 2018.
|
Liberty Acquisition.
On July
11 2018, Nytis USA signed a Purchase and Sale Agreement to acquire 54 operated oil and gas wells covering approximately 55,000
gross acres (22,000 net), the associated mineral interests, and gas wells and associated facilities in the Appalachian Basin for
a purchase price of $3.0 million, subject to customary and standard purchase price adjustments (the “
Liberty Acquisition
”).
We contributed the full amount of the purchase price to Nytis USA to fund the purchase price. The Liberty Acquisition closed on
July 11, 2018 with an effective date as of January 1, 2018. The Liberty Acquisition is not reflected in our pro forma financial
statements.
Our management’s review of the
estimated proved reserves relating to the Liberty Acquisition indicated estimated proved reserves of 0.306 MMBoe, with an estimated
proved reserve life index of approximately 39 years, as of December 31, 2017, which estimated proved reserves were determined
using $51.338 per barrel of oil and $2.976 per MMBtu of gas. Such prices were determined using the average of the historical first-day-of-the-month
prices for the twelve months ended December 31, 2017 in accordance with SEC guidelines. Approximately 86.3% of these reserves
were oil, approximately 100% were proved developed and approximately 83% were proved developed producing at December 31, 2017.
Management’s estimate of the average daily production for June 2018 from the Liberty assets was approximately 86 Boe, which
was comprised of approximately 85% crude oil and 15% natural gas.
Seneca Acquisition
.
In
October 2017, Carbon California signed a Purchase and Sale Agreement to acquire 309 operated and 1 non-operated oil wells covering
approximately 6,800 gross acres (6,500 net), and fee interests in and to certain lands, situated in the Ventura Basin, together
with associated wells, pipelines, facilities, equipment and other property rights, for a purchase price of $43.0 million, subject
to customary and standard purchase price adjustments, from Seneca Resources Corporation (the “
Seneca Acquisition
”).
We contributed approximately $5.0 million to Carbon California to fund our portion of the purchase price, with the remainder funded
by Prudential and debt. We raised our $5.0 million through the issuance of 50,000 shares of Series B Convertible Preferred Stock,
par value $0.01 per share (the “
Preferred Stock
”), to Yorktown. Upon the completion of this offering,
the Preferred Stock will automatically convert into shares of common stock. The conversion ratio at which the Preferred Stock
will convert into common stock is equal to an amount per share of $100 plus all accrued but unpaid dividends payable in respect
thereof (together, the “
Liquidation Preference
”) divided by the greater of (i) $8.00 per share or (ii)
the price that is 15% less than the price per share of shares sold to the public in this offering. See “
Description
of Capital Stock—Preferred Stock
” for more information on the terms of our preferred stock. The Seneca Acquisition
closed on May 1, 2018 with an effective date as of October 1, 2017.
Our management’s review of the
estimated proved reserves relating to the Seneca Acquisition indicated estimated proved reserves of 17.3 MMBoe, with an estimated
proved reserve life index of approximately 47 years, as of December 31, 2017, which estimated proved reserves were determined
using $51.34 per barrel of oil and $2.976 per MMBtu of gas. Such prices were determined using the average of the historical first-day-of-the-month
prices for the twelve months ended December 31, 2017 in accordance with SEC guidelines. Approximately 77% of these reserves were
oil and NGLs, approximately 66% were proved developed and approximately 39% were proved developed producing as of December 31,
2017. Management’s estimate of the average daily production for June 2018 from the Seneca assets was approximately 915 Boe,
which was comprised of approximately 70% crude oil, 8% NGLs and 22% natural gas. In the six months ended June 30, 2018, the price
per barrel of oil for our production from the Seneca assets represented an approximately 107% premium to the NYMEX West Texas
Intermediate (“
NYMEX WTI
”) benchmark price.
Reserve engineering is a complex and
subjective process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact way, and
the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation
and judgment. As a result, estimates prepared by one engineer may vary from those prepared by another. Estimates of proved reserves
for our oil and gas properties as of December 31, 2018 will be prepared by CGA using the information available at that time.
Upon completion of their review, the estimate of the proved reserves for our oil and gas properties as of December 31, 2018
will be different from the estimate of the proved reserves for our oil and gas properties as of December 31, 2017 shown above,
and the estimates of proved reserves relating to the acquisition of oil and gas properties referred to above as the Liberty Acquisition
and the Seneca Acquisition as of December 31, 2018 will be different from our management’s estimates of such reserves
as of December 31, 2017 as described above.
Old
Ironsides Buyout
. We intend to use a portion of the proceeds from this offering to complete the Old Ironsides Buyout. Following
the closing of the Old Ironsides Buyout, Carbon Appalachia will be our wholly-owned subsidiary. See “
—Investments
in Affiliates
” for more information on the terms of the Old Ironsides Buyout. The consummation of the Old Ironsides
Buyout is subject to certain closing conditions, including a financing condition that we anticipate being satisfied by the application
of the proceeds from this offering. There can be no assurances that the Old Ironsides Buyout will be consummated in the anticipated
timeframe, on the terms described herein, or at all.
Business
Strategies
Our
primary business objective is to create stockholder value through consistent growth in cash flows, production and reserves through
drilling on our existing oil and gas properties and the acquisition of complementary properties. We focus on the development of
our existing leaseholds, which consist primarily of low risk, repeatable resource plays. We invest significantly in technical
staff and geological and engineering technology to enhance the value of our properties. We intend to accomplish our objective
by executing the following strategies:
|
●
|
Capitalize
on the development of our oil and gas properties.
At the closing of this offering, our assets will consist of oil and
gas properties in the Appalachian, Ventura and Illinois Basins. We aim to continue to safely optimize returns from our existing
producing assets by using established technologies to maximize recoveries of in-place hydrocarbons. We expect the production
from our properties will increase as we continue to develop and optimize our properties by capitalizing on new technology
to enhance our production base.
|
|
●
|
Acquire
complementary properties.
A core part of our strategy is to grow our oil and gas asset base through the acquisition of
properties in the vicinity of our existing properties that feature similar reserve mixes and production profiles. During 2017
and 2018, we partnered with Prudential to finance the acquisitions of producing properties in the Ventura Basin through Carbon
California and with Old Ironsides to finance the acquisitions of producing properties in the Appalachian Basin through Carbon
Appalachia. We own a majority interest in Carbon California and, upon completion of the Old Ironsides Buyout, will own 100%
of Carbon Appalachia, and we plan to continue to aggregate complementary properties through these entities, Nytis USA or
other co-investment vehicles.
|
|
●
|
Reduce
operating costs through the aggregation and integration of acquired assets in our expanding operational footprint in both
the Appalachian and the Ventura Basins.
We plan to continue to realize economies of scale and efficiency gains from spreading
our fixed operating costs over a larger asset base. Historically, we have targeted overhead and well maintenance cost reductions,
field-level optimization and gathering system reconfigurations.
|
|
●
|
Acquire
and develop reserves in the form of a diverse mix of commodities with crude oil the primary objective in California and natural
gas the primary objective in Appalachia.
We believe that a diverse commodity mix will provide us with commodity optionality,
which will allow us to direct capital spending to develop the commodity that offers the best return on investment at the time.
|
|
●
|
Manage
commodity price exposure through an active hedging program.
We maintain a hedging program designed to reduce exposure
to fluctuations in commodity prices. As of June 30, 2018, we had outstanding natural gas hedges of approximately 1.7 MMBtu
for 2018 at an average price of $3.00 per MMBtu and approximately 2.6 MMBtu for 2019 at an average price of $2.86 per MMBtu.
In addition, as of June 30, 2018, we had outstanding oil hedges of 35,500 barrels for 2018 at an average price of $53.23 per
barrel and 48,000 barrels for 2019 at an average price of $53.76 per barrel. In addition to our hedging program, we also maintain
active hedging programs at Carbon California and Carbon Appalachia.
|
Competitive
Strengths
We
believe the following competitive strengths will allow us to successfully execute our business strategies and achieve our primary
business objective:
|
●
|
Significant
diversified portfolio of long-lived, low-decline reserves largely held by production.
As of December 31, 2017, after giving
effect to the Pro Forma Adjustments, the estimated proved oil, natural gas and NGL reserves attributable to interests in our
underlying acreage and that of Carbon California and Carbon Appalachia were 605.3 Bcfe (82.5% proved developed producing,
75.3% natural gas). For June 2018, our average daily production and that of Carbon California and Carbon Appalachia was 72.08
MMcfe/d, resulting in an average reserve life of 22.0 years. As of June 30, 2018, we, Carbon California and Carbon Appalachia
owned interests in approximately 1.9 million gross (1.7 million net) acres in the Appalachian, Illinois and Ventura Basins,
of which over 73% was held by production with no capital obligations.
|
|
●
|
Experienced
and proven management team.
The members of our management team have an average of over 25 years of oil and gas experience
and an extensive track record of creating value for stockholders and business partners. Our management and operational teams
have extensive knowledge of the Appalachian, Illinois and Ventura Basins. We believe our management’s experience in
managing capital programs at major oil and gas companies, regional knowledge of our assets and ability to identify accretive
acquisitions will allow us to continue to grow our production, reserves and dividends.
|
|
●
|
F
inancial
flexibility to fund expansion.
In connection with the closing of this offering, we intend to enter into an amended and
restated credit facility (the “
New Revolving Credit Facility
”) to replace our Existing Credit Facility
and the CAE Credit Facility (each as defined herein). The New Revolving Credit Facility is expected to be a $500 million,
four-year senior secured credit facility with an initial borrowing base of $100 million. We believe that we will have sufficient
borrowing capacity under our New Revolving Credit Facility and access to other sources of liquidity to possess the financial
capacity to grow the company. Subsequent to the closing of this offering, we expect to use our New Revolving Credit Facility
for general corporate purposes, including drilling and completion activities and acquisitions.
|
|
●
|
Benefit from low cost operations.
The
shallow nature of our drilling activities and producing wells results in relatively low
lease operating costs. Lease operating costs for the six months ended June 30, 2018 averaged
$1.11/Mcfe, $1.10/Mcfe and $16.70/Boe for us, Carbon Appalachia and Carbon California,
respectively, compared to the period ended December 31, 2017 when the lease operating
costs averaged $1.13/Mcfe, $0.98/Mcfe and $16.71/Boe.
|
|
●
|
Scalable
business model.
We believe that our business structure gives us a relative advantage to grow through acquisitions without
significantly increasing our cost structure. Our land, accounting, engineering, geology, information technology and business
development departments have a scalable business model that allows us to manage our existing assets and absorb additional
acquisitions at minimal additional costs.
|
|
●
|
Benefit
from favorable realized commodity pricing in both the Appalachian and Ventura Basins.
In the Appalachian Basin, we and Carbon Appalachia averaged a minimal pricing differential of $0.249/MMbtu and $0.407/MMbtu
during the six months ended June 30, 2018 and the period ended December 31, 2017, respectively, as we and Carbon Appalachia
targeted delivery of our and their gas to interstate pipelines that exit from the southern region of the Appalachian Basin.
In the Ventura Basin, the price per barrel of oil during the six months ended June 30, 2018 and the period ended December
31, 2017 for our production yielded approximately 106% of the NYMEX WTI benchmark price as a result of its proximity to the
southern California refining market and the API gravity of its produced oil.
|
Our Relationship with Yorktown
Upon completion of this offering, affiliates of Yorktown Partners
LLC (“
Yorktown Partners
”) will own shares
of our common stock, or approximately % of our outstanding common stock. Please see “
Security
Ownership of Certain Beneficial Owners and Management
.” We have a long-term relationship with Yorktown Partners,
a private investment firm investing exclusively in the energy industry with an emphasis on North American oil and gas production,
midstream and oilfield service businesses. Yorktown Partners has been our and our predecessor’s sponsor since 1993. Yorktown
Partners has raised 11 private equity funds with aggregate partner commitments totaling over $8 billion. Yorktown Partners’
investors include university endowments, foundations, families, insurance companies, and other institutional investors. The firm
is headquartered in New York.
Risk
Factors
Investing
in our common stock involves risks that include the speculative nature of oil and natural gas exploration, competition, volatile
commodity prices and other material factors. For a discussion of these risks and other considerations that could negatively affect
us, including risks related to this offering and our common stock, please read “
Risk Factors
” beginning
on page 11 of this prospectus and the other information in this prospectus before investing in our common stock. Please also read
“
Forward-Looking Statements
.”
Principal
Executive Office
We
are a Delaware corporation. Our principal executive office is located at 1700 Broadway, Suite 1170, Denver, Colorado, 80290, and
our telephone number is (720) 407-7030. Our website address is http://carbonnaturalgas.com. We make our periodic reports and other
information filed with or furnished to the U.S. Securities and Exchange Commission (“
SEC
”) available
free of charge through our website as soon as reasonably practicable after those reports and other information are electronically
filed with or furnished to the SEC. Information on our website or any other website is not incorporated by reference into, and
does not constitute a part of, this prospectus.
Organizational
Structure
The
following table depicts our ownership structure at the closing of this offering, after giving effect to the Pro Forma Adjustments.
The
Offering
Common
stock offered to the public
|
|
shares
( shares, if the underwriters exercise in full their option to
purchase additional shares).
|
|
|
|
Common
stock to be outstanding immediately after this offering
|
|
shares
( shares, if the underwriters exercise in full their option to
purchase additional shares).
|
|
|
|
Underwriters’
option
|
|
We
have granted the underwriters a 30-day option to purchase up to additional
shares on the same terms as the initial shares.
|
|
|
|
Use
of proceeds
|
|
We
expect to receive approximately $ million
of net proceeds (assuming the midpoint of the price range set forth on the cover
of this prospectus) from the sale of the common stock offered by us after deducting the
underwriting discount and estimated offering expenses payable by us. We intend to use
approximately $58 million of the net proceeds of this offering to fund the Old Ironsides
Buyout, $ million to pay down a
portion of our debt and the remaining $
million for general corporate purposes, including to fund potential expansion capital
expenditures and acquisitions. We may temporarily invest the net proceeds in short-term
marketable securities until they are used for their stated purpose.
If
the underwriters exercise their option to purchase additional shares in full, the additional net proceeds to us would
be approximately $ million, after deducting the
estimated underwriting discount. We will use any net proceeds from the exercise of the underwriters’ option to purchase
additional shares from us for general corporate purposes.
|
|
|
|
Dividend
Policy
|
|
We
have not to date paid any cash dividends on our common stock. We have historically retained
our earnings to support operations and to finance the growth of our business.
At or prior to the closing of this
offering, our Board of Directors will adopt a policy pursuant to which we intend to pay, to the extent practicable, quarterly
dividends that grow as we grow our reserves, production and cash generated from operations. The amount of our dividends will be
based on the amount of cash we have available each quarter, after reserves for (i) debt service and other contractual obligations
and fixed charges and (ii) future operating or capital needs that the Board of Directors may determine are appropriate. Pursuant
to our dividend policy, we initially intend to maintain a targeted payout ratio of approximately 40% of cash flow from operating
activities (excluding cash flow from Carbon California), subject to the factors described in “
Dividend Policy and
Forecasted Cash Available for Dividends
.” Based on our forecast for the twelve month period ending September 30,
2019 and the related assumptions, and assuming that concurrently with the closing of this offering we close the Old Ironsides
Buyout, we expect to pay dividends of $ , $ ,
$ and $ per
share for the quarters ending December 31, 2018, March 31, 2019, June 30, 2019 and September 30, 2019, subject to the actual declaration
of the dividend by the Board of Directors in accordance with the dividend policy stated herein. Any determination to pay dividends
will depend on our financial condition, capital requirements, results of operations, contractual limitations, legal restrictions
and any other factors the Board of Directors deems relevant.
Events
may occur, including a reduction in forecasted production volumes or realized prices, which could materially adversely
affect the actual results we achieve during the forecasted period. Consequently, our actual results of operations, operating
expenses and financial condition during the forecast period may vary from the forecast, and such variations may be material.
The
amount of dividends we are able to pay in any quarter may be limited by Delaware General Corporation Law, which provides
that a Delaware corporation may pay dividends either (i) out of the corporation’s surplus (as defined by Delaware
law) or (ii) if there is no surplus, out of the corporation’s net profit for the fiscal year in which the dividend
is declared or the preceding fiscal year. The agreement governing the New Revolving Credit Facility will contain customary
limitations on our ability to pay dividends, including compliance with leverage ratios and other customary covenants. The
forecasted dividends for the twelve month period ending September 30, 2019 assume that we do not receive any distributions
from Carbon California and that the cash flow from operating activities at Carbon California is reinvested in the business
or used to pay down debt.
We
do not intend to maintain excess dividend coverage for the purpose of maintaining stability or growth in our dividends,
nor do we intend as a general rule to reserve cash for dividends in future periods, nor do we intend to incur debt to
pay dividends. There may be variability in the amount of our quarterly dividends due to fluctuating commodity prices,
among other things. We generally expect to finance most of our growth with retained cash flow from operating activities
as well as borrowings under our debt agreements. Our Board of Directors may change this dividend policy at any time.
|
|
|
|
Risk
factors
|
|
Please
read “
Risk Factors
” beginning on page 11 of this prospectus for a discussion of risks that you should
consider before investing in our common stock.
|
|
|
|
Symbol
|
|
We
have applied to list our common stock on the Nasdaq Capital Market under the symbol “CRBO.”
|
Summary
Historical and Unaudited Pro Forma Condensed Consolidated Financial Data
The following table presents our summary
historical financial data and summary unaudited pro forma condensed consolidated financial data as of the dates and for the periods
presented. The summary historical financial data presented as of and for the years ended December 31, 2017 and 2016 and as of
and for the six months ended June 30, 2018 and 2017 are derived from the historical financial statements included elsewhere in
this prospectus. The summary unaudited pro forma condensed consolidated financial data presented as of and for the six months
ended June 30, 2018 and as of and for the year ended December 31, 2017 are derived from our unaudited pro forma condensed consolidated
financial statements included elsewhere in this prospectus and gives effect to the following transactions:
|
●
|
the
increase in Carbon’s ownership of Carbon California from 17.81% to 56.41% on February 1, 2018 in connection with the
exercise of the California Warrant by Yorktown and the resulting consolidation of Carbon California for financial reporting
purposes;
|
|
|
|
|
●
|
the
completion of the Seneca Acquisition on May 1, 2018 and the resulting decrease in Carbon’s ownership of Carbon California
from 56.41% to 53.92%;
|
|
|
|
|
●
|
additional
borrowings under our Existing Credit Facility made in connection with Carbon’s acquisition activities;
|
|
|
|
|
●
|
the
exercise of the Appalachia Warrant;
|
|
|
|
|
●
|
the
acquisition by Carbon of Old Ironsides’ 73.5% interest in Carbon Appalachia for approximately $58 million, resulting
in Carbon Appalachia’s becoming a wholly owned subsidiary of Carbon that is consolidated for financial reporting purposes;
|
|
|
|
|
●
|
the
Cabot Acquisition made by Carbon Appalachia;
|
|
|
|
|
●
|
the
EnerVest Acquisition made by Carbon Appalachia;
|
|
|
|
|
●
|
the
issuance of the Preferred Stock to Yorktown in connection with the Seneca Acquisition and automatic conversion to shares
of common stock upon the completion of this offering; and
|
|
|
|
|
●
|
the
use of the remaining proceeds from this offering.
|
For
a detailed discussion of the summary historical financial data contained in the following table, please read “
Management’s
Discussion and Analysis of Financial Condition and Results of Operations
.” The following table should also be read
in conjunction with “
Use of Proceeds
” and our audited and unaudited historical consolidated financial
statements, the audited and unaudited historical consolidated financial statements of Carbon Appalachia and the audited historical
financial statements of Carbon California included elsewhere in this prospectus. Among other things, the audited and unaudited
historical consolidated financial statements include more detailed information regarding the basis of presentation for the information
in the following table (in thousands, unless specifically stated otherwise).
|
|
Historical
|
|
|
Pro
Forma
|
|
|
|
Six Months Ended
June 30,
|
|
|
Year
Ended
December 31,
|
|
|
Six Months
Ended
June 30,
|
|
|
Year Ended
December 31,
|
|
|
|
2018
|
|
|
2017
|
|
|
2017
|
|
|
2016
|
|
|
2018
|
|
|
2017
|
|
|
|
(in thousands, except per share
and production data)
|
|
|
|
(unaudited)
|
|
|
(unaudited)
|
|
|
|
|
|
|
|
|
(unaudited)
|
|
|
(unaudited)
|
|
Consolidated statements of operations data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenue
|
|
$
|
12,621
|
|
|
$
|
13,370
|
|
|
$
|
22,473
|
|
|
$
|
8,195
|
|
|
$
|
61,002
|
|
|
$
|
117,437
|
|
Total expenses
|
|
|
16,511
|
|
|
|
9,159
|
|
|
|
19,265
|
|
|
|
20,713
|
|
|
|
59,138
|
|
|
|
104,305
|
|
Operating income (loss)
|
|
|
(3,890
|
)
|
|
|
4,211
|
|
|
|
3,208
|
|
|
|
(12,518
|
)
|
|
|
1,864
|
|
|
|
13,132
|
|
Total other income (expense)
|
|
|
4,374
|
|
|
|
1,161
|
|
|
|
3,117
|
|
|
|
(301
|
)
|
|
|
(4,208
|
)
|
|
|
(7,239
|
)
|
Income (loss) before income
taxes
|
|
|
484
|
|
|
|
5,372
|
|
|
|
6,325
|
|
|
|
(12,819
|
)
|
|
|
(2,344
|
)
|
|
|
5,893
|
|
Provision for income taxes
|
|
|
—
|
|
|
|
—
|
|
|
|
(74
|
)
|
|
|
—
|
|
|
|
—
|
|
|
|
(74
|
)
|
Net income (loss) before
non-controlling interests
|
|
|
484
|
|
|
|
5,372
|
|
|
|
6,399
|
|
|
|
(12,819
|
)
|
|
|
(2,344
|
)
|
|
|
5,967
|
|
Net
income (loss) attributable to non-controlling interests
|
|
|
(2,505
|
)
|
|
|
76
|
|
|
|
81
|
|
|
|
(413
|
)
|
|
|
(4,796
|
)
|
|
|
(944
|
)
|
Net
income attributable to controlling interests
|
|
$
|
2,989
|
|
|
$
|
5,296
|
|
|
$
|
6,318
|
|
|
$
|
(12,406
|
)
|
|
$
|
2,453
|
|
|
$
|
6,911
|
|
Net income (loss) per common
share:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
$
|
0.41
|
|
|
$
|
0.95
|
|
|
$
|
1.12
|
|
|
$
|
(2.27
|
)
|
|
$
|
0.31
|
|
|
$
|
0.85
|
|
Diluted
(1)
|
|
$
|
0.20
|
|
|
$
|
0.56
|
|
|
$
|
0.49
|
|
|
$
|
(2.27
|
)
|
|
$
|
0.15
|
|
|
$
|
0.64
|
|
Consolidated
balance sheet data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$
|
4,030
|
|
|
$
|
1,014
|
|
|
$
|
1,650
|
|
|
$
|
858
|
|
|
$
|
16,687
|
|
|
$
|
7,254
|
|
Total assets
|
|
|
162,386
|
|
|
|
50,224
|
|
|
|
60,009
|
|
|
|
42,712
|
|
|
|
286,219
|
|
|
|
297,221
|
|
Total liabilities
|
|
|
107,862
|
|
|
|
35,383
|
|
|
|
43,513
|
|
|
|
33,739
|
|
|
|
173,695
|
|
|
|
177,843
|
|
Total stockholders’
equity
|
|
|
54,524
|
|
|
|
14,841
|
|
|
|
16,496
|
|
|
|
8,973
|
|
|
|
112,524
|
|
|
|
119,378
|
|
Consolidated
statements of cash flows data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by (used
in):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating activities
|
|
$
|
1,615
|
|
|
$
|
2,336
|
|
|
$
|
3,920
|
|
|
$
|
(3,142
|
)
|
|
|
|
|
|
|
|
|
Investing activities
|
|
|
(40,197
|
)
|
|
|
(1,437
|
)
|
|
|
(8,533
|
)
|
|
|
(8,754
|
)
|
|
|
|
|
|
|
|
|
Financing activities
|
|
|
40,962
|
|
|
|
(743
|
)
|
|
|
5,405
|
|
|
|
12,449
|
|
|
|
|
|
|
|
|
|
Other
data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EBITDA
(2)
|
|
$
|
3,818
|
|
|
$
|
2,858
|
|
|
$
|
5,048
|
|
|
$
|
(2,775
|
)
|
|
|
|
|
|
|
|
|
(1)
|
Dilution
reflects the conversion of the Preferred Stock to common stock upon the closing of this offering and vesting of the restricted
stock.
|
(2)
|
EBITDA
is a non-GAAP financial measure and generally differs from cash flow from operating activities, the most directly comparable
GAAP financial measure. See “—
Non-GAAP Financial Measures
” for more information.
|
Non-GAAP
Financial Measures
PV-10
PV-10
is a non-GAAP financial measure. We believe that the presentation of PV-10 is relevant and useful to investors because it presents
the discounted future net cash flows attributable to our estimated net proved reserves prior to taking into account future corporate
income taxes, and it is a useful measure for evaluating the relative monetary significance of our oil and gas properties. It is
not intended to represent the current market value of our estimated reserves. PV-10 should not be considered in isolation or as
a substitute for the standardized measure reported in accordance with GAAP, but rather should be considered in addition to the
standardized measure.
PV-10
is derived from the standardized measure, which is the most directly comparable GAAP financial measure. PV-10 is calculated using
the same inputs and assumptions as the standardized measure, with the exception that it omits the impact of future income taxes.
It is considered to be a pre-tax measurement.
The following table provides a reconciliation
of the standardized measure for us and our proportionate share of Carbon Appalachia and Carbon California to PV-10 at December
31, 2017 and 2016 (in thousands):
|
|
Year Ended December 31,
|
|
|
|
2017
|
|
|
2016
|
|
PV-10 (in thousands)
|
|
$
|
152,341
|
|
|
$
|
59,569
|
|
Future income taxes (in thousands)
|
|
|
(35,482
|
)
|
|
|
(14,858
|
)
|
Standardized Measure (in thousands)
|
|
$
|
116,859
|
|
|
$
|
44,711
|
|
EBITDA
EBITDA represents cash flow from operating
activities plus interest expense and provision for income taxes. We disclose EBITDA, which is a non-GAAP liquidity measure, because
management believes this metric assists investors and analysts in assessing the ability of our assets to generate sufficient cash
flows to make dividends to our shareholders. You should not consider EBITDA as an alternative to net income (loss), determined
in accordance with GAAP, or as an alternative to cash flows from operating activities, determined in accordance with GAAP, as
an indicator of our cash flows.
EBITDA
has limitations as an analytical tool. Some of these limitations are:
|
●
|
EBITDA
does not reflect cash expenditures or future cash capital expenditures or contractual
commitments;
|
|
●
|
EBITDA
does not reflect changes in, or cash requirements for, our working capital needs;
|
|
●
|
EBITDA
does not reflect the significant interest expense, or the cash requirements necessary
to service interest or principal payments, on our debt;
|
|
●
|
EBITDA
does not reflect payments made or future requirements for income taxes; and
|
|
●
|
Although
depreciation and amortization are non-cash charges, the assets being depreciated and
amortized will often have to be replaced in the future and EBITDA does not reflect any
cash requirements for such replacements.
|
Because of
these limitations, EBITDA should not be considered in isolation or as a substitute for measures calculated in accordance with
GAAP.
The
following table presents a reconciliation of EBITDA to cash flow from operating activities for each of the periods indicated (in
thousands):
|
|
Historical
|
|
|
|
Six
Months Ended
June 30,
|
|
|
Year
Ended
December 31,
|
|
|
|
2018
|
|
|
2017
|
|
|
2017
|
|
|
2016
|
|
|
|
(in
thousands, except per share and production data)
|
|
|
|
(unaudited)
|
|
|
(unaudited)
|
|
|
|
|
|
|
|
Reconciliation of EBITDA to Cash Flow
from Operating Activities
|
|
|
|
|
|
|
|
|
|
|
|
|
EBITDA
|
|
$
|
3,818
|
|
|
$
|
2,858
|
|
|
$
|
5,048
|
|
|
$
|
(2,775
|
)
|
Interest
Expense
|
|
|
2,203
|
|
|
|
522
|
|
|
|
1,202
|
|
|
|
367
|
|
Provision
for Income Taxes
|
|
|
—
|
|
|
|
—
|
|
|
|
(74
|
)
|
|
|
—
|
|
Cash
Flow from Operating Activities
|
|
|
1,615
|
|
|
|
2,336
|
|
|
|
3,920
|
|
|
|
(3,142
|
)
|
RISK
FACTORS
Investing
in our common stock involves a high degree of risk. You should carefully consider the risks described below with all of the other
information included in this prospectus before deciding to invest in our common stock. If any of the following risks actually
occur, they may materially and adversely affect our business, financial condition, cash flows, and results of operations. In this
event, we might have to decrease, or may not be able to pay, dividends on our common stock, the trading price of our common stock
could decline, and you could lose part or all of your investment. We may experience additional risks and uncertainties not currently
known to us; or, as a result of developments occurring in the future, conditions that we currently deem to be immaterial may also
materially and adversely affect our business, financial condition, cash flows, and results of operations.
Risks
Related to Our Business
Oil,
NGL and natural gas prices and differentials are highly volatile. Declines in commodity prices, especially steep declines in the
price of oil, have adversely affected, and in the future will adversely affect, our financial condition and results of operations,
cash flow, access to the capital markets and ability to grow.
The
oil, NGL and natural gas markets are highly volatile, and we cannot predict future oil, NGL and natural gas prices. Prices for
oil, NGL and natural gas may fluctuate widely in response to relatively minor changes in the supply of and demand for oil, NGLs
and natural gas, market uncertainty and a variety of additional factors that are beyond our control, such as:
|
●
|
domestic
and foreign supply of and demand for oil, NGLs and natural gas;
|
|
●
|
market
prices of oil, NGLs and natural gas;
|
|
●
|
level
of consumer product demand;
|
|
●
|
overall
domestic and global political and economic conditions;
|
|
●
|
political
and economic conditions in producing countries, including those in the Middle East, Russia, South America and Africa;
|
|
●
|
actions
of the Organization of Petroleum Exporting Countries and other state-controlled oil companies relating to oil price and production
controls;
|
|
●
|
impact
of the U.S. dollar exchange rates on commodity prices;
|
|
●
|
technological
advances affecting energy consumption and energy supply;
|
|
●
|
domestic
and foreign governmental regulations and taxation;
|
|
●
|
impact
of energy conservation efforts;
|
|
●
|
capacity,
cost and availability of oil and natural gas pipelines, processing, gathering and other transportation facilities and the
proximity of these facilities to our wells;
|
|
●
|
increase
in imports of liquid natural gas in the United States; and
|
|
●
|
price
and availability of alternative fuels.
|
Oil, NGL and natural gas prices do
not necessarily fluctuate in direct relationship to each other. On a pro forma basis after giving effect to the Pro Forma Adjustments,
our oil, NGL and natural gas accounted for approximately 14.3%, 1.9% and 83.8% of our estimated proved reserves as of December
31, 2017, respectively, and approximately 24.0%, 3.0% and 73.0% of our production for the six months ended June 30, 2018 on an
Mcfe basis, respectively. Accordingly, our financial results will be sensitive to movements in oil, NGL and natural gas prices.
In the past, prices of oil and natural
gas have been extremely volatile, and we expect this volatility to continue. For example, during the year ended December 31, 2017,
the monthly average NYMEX WTI spot price ranged from a high of $61 per Bbl in December to a low of $46 per Bbl in June while the
monthly average Henry Hub natural gas price ranged from a high of $3.30 per MMBtu in January to a low of $2.81 per MMBtu in December.
During the year ended December 31, 2016, the monthly average NYMEX WTI spot price ranged from a high of $52 per Bbl in December
to a low of $30 per Bbl in February while the monthly average Henry Hub natural gas price ranged from a high of $3.59 per MMBtu
in December to a low of $1.73 per MMBtu in March. For July 2018, the NYMEX WTI spot price averaged $70.84 per Bbl and the natural
gas spot price at Henry Hub averaged approximately $3.00 per MMBtu. Price discounts or differentials between NYMEX WTI spot prices
and what we actually receive are also historically very volatile.
In
addition, the market price for natural gas in the Appalachian Basin continues to be lower relative to NYMEX Henry Hub as a result
of the significant increases in the supply of natural gas in the Northeast region in recent years. Due to the volatility of commodity
prices, we are unable to predict future potential movements in the market prices for natural gas, including Appalachian and other
market point basis, NGLs and oil and thus cannot predict the ultimate impact of prices on our operations.
Our production in the Ventura Basin
currently receives an approximate 6% premium to the NYMEX WTI benchmark price. A reduction in this premium would reduce the relative
price advantage we receive for a substantial portion of our production in the Ventura Basin.
Our
revenue, profitability and cash flow depend upon the prices and demand for oil, NGLs and natural gas. A drop in prices similar
to those observed in recent years would significantly affect our financial results and impede our growth. In particular, a significant
or prolonged decline in oil, NGL or natural gas prices or a lack of related storage will negatively impact:
|
●
|
the
value of our reserves, because declines in oil, NGL and natural gas prices would reduce the amount of oil, NGLs and natural
gas that we can produce economically;
|
|
●
|
the
amount of cash flow available for capital expenditures;
|
|
●
|
our
ability to replace our production and future rate of growth;
|
|
●
|
our
ability to borrow money or raise additional capital and our cost of such capital; and
|
|
●
|
our
ability to meet our financial obligations.
|
Historically,
higher oil, NGL and natural gas prices generally stimulate increased demand and result in increased prices for drilling equipment,
crews and associated supplies, equipment and services, as well as higher lease operating expenses and increased end-user conservation
or conversion to alternative fuels. However, commodity price declines do not result in similarly rapid declines of costs associated
with drilling. Accordingly, a high cost environment could adversely affect our ability to pursue our drilling program and our
results of operations.
The
refining industry may be unable to absorb rising U.S. oil and condensate production; in such a case, the resulting surplus could
depress prices and restrict the availability of markets, which could materially and adversely affect our results of operations.
Absent
an expansion of U.S. refining and export capacity, rising U.S. production of oil and condensates could result in a surplus of
these products in the U.S., which would likely cause prices for these commodities to fall and markets to constrict. Although U.S.
law was changed in 2015 to permit the export of oil, exports may not occur if demand is lacking in foreign markets or the price
that can be obtained in foreign markets does not support associated export capacity expansions, transportation and other costs.
In such circumstances, the returns on our capital projects would decline, possibly to levels that would make execution of our
drilling plans uneconomical, and a lack of market for our products could require that we shut in some portion of our production.
If this were to occur, our production and cash flow could decrease, or could increase less than forecasted, which could have a
material adverse effect on our cash flow and profitability.
We
are a holding company with no oil and gas operations of our own, and we depend on subsidiaries for cash to fund all of our operations
and expenses.
Our
operations are conducted entirely through subsidiaries, and our ability to generate cash to meet our debt service obligations
is dependent on the earnings and the receipt of funds from our subsidiaries through distributions or intercompany loans. Our subsidiaries’
ability to generate adequate cash depends on a number of factors, including development of reserves, successful acquisitions of
complementary properties, advantageous drilling conditions, oil and natural gas prices, compliance with all applicable laws and
regulations and other factors.
We
do not solely control certain subsidiaries.
We
have no significant assets other than our ownership interest in entities that own and operate oil and natural gas and oil interests.
We do not fully own, and in many cases do not solely control, such entities. More specifically:
|
●
|
Carbon
Appalachia and Carbon California, our two largest subsidiaries, are managed by their respective governing boards. Our ability
to influence decisions with respect to the operation of such entities varies depending on the amount of control we exercise
under the applicable governing agreement;
|
|
●
|
we
do not control the amount of cash distributed by several of the entities in which we own interests, including Carbon Appalachia
and Carbon California. Further, debt facilities at these entities currently restrict distributions. We may influence the amount
of cash distributed through our board seats on such entity’s governing board, but may not ultimately be successful in
such efforts;
|
|
●
|
we
may not have the ability to unilaterally require certain of the entities in which we own interests to make capital expenditures,
and such entities may require us to make additional capital contributions to fund operating and maintenance expenditures,
as well as to fund expansion capital expenditures, which would reduce the amount of cash otherwise available for dividend
payments by us or require us to incur additional indebtedness;
|
|
●
|
the
entities in which we own interests may incur additional indebtedness without our consent, which debt payments would reduce
the amount of cash that might otherwise be available for distributions;
|
|
●
|
some
of our assets are operated by entities that we do not control; and
|
|
●
|
the
third-party operator of certain of the assets held by each subsidiary and the identity of our subsidiary partners could change,
in some cases without our consent. Our dependence on the operators of such assets and other working interest owners for these
projects and our limited ability to influence or control the operation and future development of these properties could have
a material adverse effect on the realization of our targeted returns on capital or lead to unexpected future costs.
|
If the Old Ironsides Buyout is completed
at the closing of this offering, our proportionate interest in Carbon Appalachia will increase from 27.24% to 100%, in which event
some of the limitations set forth above will not apply to it.
Our
level of indebtedness may increase and reduce our financial flexibility.
We have a $100.0 million bank credit
facility with LegacyTexas Bank with a current borrowing base of $28.0 million, the outstanding balance of which was approximately
$23.1 million at June 30, 2018 (the “
Existing Credit Facility
”). In addition, Carbon Appalachia Enterprises,
LLC, a Delaware limited liability company and indirect subsidiary of Carbon Appalachia (“
Carbon Appalachia Enterprises
”),
has a four-year $100.0 million senior secured asset-based revolving credit facility with LegacyTexas Bank (the “
CAE
Credit Facility
”), which has been used to partially fund each of Carbon Appalachia’s acquisitions. The current
borrowing base under the CAE Credit Facility is $70.0 million. We are not a guarantor of the CAE Credit Facility. As of June 30,
2018, there was approximately $38.0 million outstanding under the CAE Credit Facility.
In connection with the closing of this
offering, we intend to enter the New Revolving Credit Facility to replace our Existing Credit Facility and the CAE Credit Facility
at the closing of this offering. The New Revolving Credit Facility will contain a letters of credit sub-facility up to $1.5 million
and will have an initial borrowing base of $100 million. Entry into the New Revolving Credit Facility will be conditioned upon,
among other things, the completion of this offering. The outstanding debt under our Existing Credit Facility and the CAE Credit
Facility will be assigned to the lender syndicate under the New Revolving Credit Facility, and, following the closing of this
offering, our outstanding debt under the New Revolving Credit Facility will be $
.
In addition, Carbon California sold
certain Senior Secured Revolving Notes to Prudential Legacy Insurance Company of New Jersey and Prudential Insurance Company of
America with a revolving borrowing capacity of $41.0 million. There was $38.5 million of indebtedness outstanding thereunder as
of June 30, 2018. We are not a guarantor of the Senior Secured Revolving Notes.
We,
Carbon Appalachia and Carbon California may incur significant additional indebtedness in the future in order to make acquisitions
or to develop our properties.
Our
level of indebtedness could affect our operations in several ways, including the following:
|
●
|
a
significant portion of our cash flows could be used to service our indebtedness;
|
|
●
|
a
high level of debt would increase our vulnerability to general adverse economic and industry conditions;
|
|
●
|
the
covenants contained in the agreements governing our outstanding indebtedness limit our ability to borrow additional funds,
dispose of assets, pay dividends, and make certain investments;
|
|
●
|
a
high level of debt may place us at a competitive disadvantage compared to our competitors that are less leveraged and therefore,
may be able to take advantage of opportunities that our indebtedness would prevent us from pursuing;
|
|
●
|
our
debt covenants may also affect our flexibility in planning for, and reacting to, changes in the economy and in our industry;
|
|
●
|
a
high level of debt may make it more likely that a reduction in our borrowing base following a periodic redetermination could
require us to repay a portion of our then-outstanding bank borrowings; and
|
|
●
|
a
high level of debt may impair our ability to obtain additional financing in the future for working capital, capital expenditures,
acquisitions, general corporate, or other purposes.
|
A
high level of indebtedness increases the risk that we may default on our debt obligations. Our ability to meet our debt obligations
and to reduce our level of indebtedness depends on our future performance. General economic conditions, commodity prices, and
financial, business, and other factors affect our operations and our future performance. Many of these factors are beyond our
control. We may not be able to generate sufficient cash flows to pay the interest on our debt and future working capital, borrowings,
or equity financing may not be available to pay or refinance such debt. Factors that will affect our ability to raise cash through
an offering of our capital stock or a refinancing of our debt include financial market conditions, the value of our assets, and
our performance at the time we need capital.
We
may not be able to generate enough cash flow to meet our debt obligations or fund our other liquidity needs.
At June 30, 2018, our debt consisted
of approximately $23.1 million in borrowings under our current $28.0 million borrowing base under our Existing Credit Facility,
approximately $38.5 million outstanding under Carbon California’s Senior Secured Revolving Notes due 2022 and approximately
$13.0 million outstanding under Carbon California’s Subordinated Notes due 2024. Following the closing of this offering,
our outstanding debt under the New Revolving Credit Facility will be $ . In addition
to interest expense and principal on our long-term debt, we have demands on our cash resources including, among others, operating
expenses and capital expenditures.
Our
ability to pay the principal and interest on our long-term debt and to satisfy our other liabilities will depend upon future performance
and our ability to repay or refinance our debt as it becomes due. Our future operating performance and ability to refinance will
be affected by economic and capital market conditions, results of operations and other factors, many of which are beyond our control.
Our ability to meet our debt service obligations also may be impacted by changes in prevailing interest rates, as borrowing under
our Existing Credit Facility and our New Revolving Credit Facility will bear interest at floating rates.
We
may not generate sufficient cash flow from operations. Without sufficient cash flow, there may not be adequate future sources
of capital to enable us to service our indebtedness or to fund our other liquidity needs. If we are unable to service our indebtedness
and fund our operating costs, we will be required to adopt alternative strategies that may include:
|
●
|
reducing
or delaying capital expenditures;
|
|
●
|
seeking
additional debt financing or equity capital;
|
|
●
|
restructuring
or refinancing debt.
|
We
may not be able to complete such alternative strategies on satisfactory terms, if at all. Our inability to generate sufficient
cash flows to satisfy our debt obligations and fund our liquidity needs, or to refinance our indebtedness on commercially reasonable
terms, would materially and adversely affect our financial condition and results of operations and may reduce our ability to pay
dividends on our common stock. The formation of joint ventures or other similar arrangements to finance operations may result
in dilution of our interest in the properties affected by such arrangements.
A
deterioration in general economic, business or industry conditions would materially adversely affect our results of operations,
financial condition and ability to pay dividends on our common stock.
In
recent years, concerns over global economic conditions, energy costs, geopolitical issues, inflation, the availability and cost
of credit, and slow economic growth in the United States have contributed to economic uncertainty and diminished expectations
for the global economy. Meanwhile, continued hostilities in the Middle East and the occurrence or threat of terrorist attacks
in the United States or other countries could adversely affect the economies of the United States and other countries. Concerns
about global economic growth have had a significant adverse impact on global financial markets and commodity prices. An oversupply
of crude oil in 2015 led to a severe decline in worldwide oil prices. If the economic climate in the United States or abroad deteriorates,
worldwide demand for petroleum products could materially decrease, which could impact the price at which oil, natural gas and
natural gas liquids from our properties are sold, affect the ability of vendors, suppliers and customers associated with our properties
to continue operations and ultimately materially adversely impact our results of operations, financial condition and ability to
pay dividends on our common stock.
We
have made several significant acquisitions in recent years, and our proportionate interests in our equity investees have recently
increased or is expected to increase upon the closing of this offering. As a result, our historical reserve, operating and
financial data are not comparable from period to period or to the unaudited pro forma reserve, operating financial information
included in this prospectus, which may make it more difficult for you to evaluate our business or our ability to pay dividends.
Consistent
with our acquisition strategy, we, together with Carbon Appalachia and Carbon California, have completed twelve significant acquisitions
since October 2016. Additionally, our proportionate interest in Carbon California increased during 2018 from 17.81% to 53.92%.
This resulted in a change from treating Carbon California as an equity method investment to consolidating Carbon California’s
results into our results beginning with the first quarter of 2018. Further, if the Old Ironsides Buyout is completed at
the closing of this offering, our proportionate interest in Carbon Appalachia will increase from 27.24% to 100%, and Carbon Appalachia’s
results will be consolidated into our results.
As
a result of the execution of our acquisition strategy and the increase in interests in Carbon Appalachia and Carbon California,
the historical reserve, operating and financial data included in this prospectus are not comparable (i) from period to period
or (ii) to the reserve, operating or financial data presented in this prospectus on a pro forma basis. For example, as of
and for the years ended December 31, 2016 and 2017 on a historical basis and for the year ended December 31, 2017 on a pro forma
basis, our total revenue was $8.2 million, $22.4 million, and $117.4 million, respectively, our total assets were $42.7 million,
$60.0 million and $297.2 million, respectively and our total liabilities were $33.7 million, $43.5 million, and $177.8 million,
respectively. Our total proved reserves (excluding non-controlling interests) as of December 31, 2017 were 189.4 Bcfe on
a historical basis and 517.8 Bcfe on a pro forma basis. As a result, the utility of historical reserve, operating and financial
data included in this prospectus may be limited, and thus you may find it difficult to evaluate our business and results of operations
to date and to assess our future prospects and ability to pay dividends.
The
agreements governing our indebtedness contain restrictive covenants that may limit our ability to respond to changes in market
conditions or pursue business opportunities.
Our
credit agreement contains restrictive covenants that limit our ability to, among other things:
|
●
|
incur
additional liens;
|
|
●
|
sell,
transfer or dispose of assets;
|
|
●
|
merge
or consolidate, wind-up, dissolve or liquidate;
|
|
●
|
make
dividends and distributions on, or repurchases of, equity;
|
|
●
|
make
certain investments;
|
|
●
|
enter
into certain transactions with our affiliates;
|
|
●
|
enter
into sales-leaseback transactions;
|
|
●
|
make
optional or voluntary payment of debt;
|
|
●
|
change
the nature of our business;
|
|
●
|
change
our fiscal year to make changes to the accounting treatment or reporting practices;
|
|
●
|
amend
constituent documents; or
|
|
●
|
enter
into certain hedging transactions.
|
In
addition, our credit agreement requires us to maintain certain financial ratios and tests. The requirement that we comply with
these provisions may materially adversely affect our ability to react to changes in market conditions, take advantage of business
opportunities we believe to be desirable, obtain future financing, fund needed capital expenditures, or withstand a continuing
or future downturn in our business. The New Revolving Credit Facility will have similar restrictive covenants, financial ratios
and tests as described above.
If
we are unable to comply with the restrictions and covenants in our credit agreement, there could be an event of default under
the terms of such agreement, which could result in an acceleration of repayment.
If
we are unable to comply with the restrictions and covenants in our credit agreement or the New Revolving Credit Facility, there
could be an event of default. Our ability to comply with these restrictions and covenants, including meeting the financial ratios
and tests, may be affected by events beyond our control. As a result, we cannot assure that we will be able to comply with these
restrictions and covenants or meet such financial ratios and tests. In the event of a default under our credit agreement, the
lenders could terminate their commitments to lend or accelerate the loans and declare all amounts borrowed due and payable. If
any of these events occur, our assets might not be sufficient to repay in full all of our outstanding indebtedness and we may
be unable to find alternative financing. Even if we could obtain alternative financing, it might not be on terms that are favorable
or acceptable to us. Additionally, we may not be able to amend our credit agreement or obtain needed waivers on satisfactory terms.
Our
borrowings under our credit agreement and the Carbon California Senior Revolving Notes expose us to interest rate risk.
Our results of operations are exposed
to interest rate risk associated with borrowings under our credit agreement, which bear interest at a rate elected by us that
is based on the prime, LIBOR, or federal funds rate plus margins ranging from 0.00% to 4.50% depending on the type of loan used
and the amount of the loan outstanding in relation to the borrowing base. Under the proposed terms of the New Revolving Credit
Facility, the borrowings will bear interest at a rate elected by us that is based on the prime, LIBOR, or federal funds rate plus
margins ranging from 0.00% to 3.75% depending on the type of loan used and the amount of the loan outstanding in relation to the
borrowing base. As of June 30, 2018, there was approximately $23.1 million outstanding under our credit agreement. In addition,
interest on borrowings under the Carbon California Senior Revolving Notes is payable quarterly and accrues at a rate per annum
equal to either (i) the prime rate plus an applicable margin of 4.00% or (ii) the LIBOR rate plus an applicable margin of 5.00%
at our option. As of June 30, 2018, there was approximately $38.5 million outstanding under the Carbon California Senior Revolving
Notes. If interest rates increase, so will our interest costs, which may have a material adverse effect on our results of operations
and financial condition.
Any
significant reduction in our borrowing base under our credit agreement or the Carbon California Senior Revolving Notes as a result
of the periodic borrowing base redeterminations or otherwise may negatively impact our ability to fund our operations.
Under (i) our credit agreement, which
as of July 11, 2018 provides for a $28.0 million borrowing base and (ii) the Carbon California Senior Revolving Notes, which as
of May 1, 2018 provide for a $41.0 million borrowing base, we are subject to collateral borrowing base redeterminations based
on our proved reserves. The New Revolving Credit Facility will also be subject to periodic borrowing base redeterminations. Declines
in oil and natural gas prices have in the past adversely impacted the value of our estimated proved developed reserves and, in
turn, the market values used by our lenders to determine our borrowing base. Any significant reduction in our borrowing base as
a result of such borrowing base redeterminations or otherwise may negatively impact our liquidity and our ability to fund our
operations and, as a result, may have a material adverse effect on our financial condition, results of operations, and cash flows.
Our
estimates of proved reserves at December 31, 2017 and 2016 have been prepared under SEC rules which could limit our ability to
book additional proved undeveloped reserves in the future.
Estimates
of our proved reserves as of December 31, 2017 and 2016 have been prepared and presented under the SEC’s rules relating
to the reporting of oil and natural gas exploration activities. These rules require that, subject to limited exceptions, proved
undeveloped reserves may only be booked if they relate to wells scheduled to be drilled within five years of the date of booking.
This rule has limited and may continue to limit our potential to book additional proved undeveloped reserves. Moreover, we may
be required to write down any proved undeveloped reserves that are not developed within the required five-year timeframe. In addition,
we based the discounted future net cash flows from our proved reserves on the twelve month unweighted arithmetic average of the
first-day-of-the-month price for the preceding twelve months without giving effect to derivative transactions. Actual future net
cash flows from our properties will be affected by factors such as the actual prices we receive for oil, NGLs and natural gas,
the amount, timing and cost of actual production and changes in governmental regulations or taxation.
Neither
the estimated quantities of proved reserves nor the discounted present value of future net cash flows attributable to those reserves
included in this prospectus are intended to represent their fair, or current, market value.
Reserve
estimates depend on many assumptions that may turn out to be inaccurate. Any material inaccuracies in these reserve estimates
or underlying assumptions will materially affect the quantities and present value of our proved reserves.
Oil
and natural gas reserve engineering is not an exact science and requires subjective estimates of underground accumulations of
reserves and assumptions concerning future commodity prices, production levels, estimated ultimate recoveries, and operating and
development costs. As a result, estimated quantities of proved reserves, projections of future production rates, and the timing
of development expenditures may be incorrect. Our, Carbon Appalachia’s and Carbon California’s estimates of proved
reserves and related valuations as of December 31, 2017 and 2016 are based on proved reserve reports prepared by CGA, an independent
engineering firm. CGA conducted a well-by-well review of all our, Carbon Appalachia’s and Carbon California’s properties
for the periods covered by its proved reserve reports using information provided by us, Carbon Appalachia or Carbon California.
Over time, we may make material changes to proved reserve estimates taking into account the results of actual drilling, testing,
and production. Also, certain assumptions regarding future commodity prices, production levels, and operating and development
costs may prove incorrect. Any significant variance from these assumptions to actual figures could greatly affect our estimates
of proved reserves, the economically recoverable quantities of reserves attributable to any particular group of properties, the
classifications of reserves based on risk of recovery, and estimates of the future net cash flows. Numerous changes over time
to the assumptions on which our reserve estimates are based, as described above, often result in the actual quantities of reserves
we ultimately recover being different from our estimates.
The
estimates of proved reserves as of December 31, 2017 and 2016 included in this registration statement were prepared using an average
price equal to the unweighted arithmetic average of hydrocarbon prices received on a field-by-field basis on the first day of
each month within the 12 months ended December 31, 2017 and 2016, respectively, in accordance with the SEC guidelines applicable
to reserve estimates for these periods. Reserve estimates do not include any value for probable or possible reserves that may
exist, nor do they include any value for unproved acreage. The reserve estimates represent our, Carbon Appalachia’s and
Carbon California’s net revenue interest in such properties.
The
present value of future net cash flows from estimated proved reserves is not necessarily the same as the current market value
of estimated proved oil and natural gas reserves. We, Carbon Appalachia and Carbon California base the current market value of
estimated proved reserves on prices and costs in effect on the day of the estimate. However, actual future net cash flows from
our oil and natural gas properties also will be affected by factors such as:
|
●
|
the
actual prices we receive for oil and natural gas;
|
|
●
|
our
actual operating costs in producing oil and natural gas;
|
|
●
|
the
amount and timing of actual production;
|
|
●
|
the
amount and timing of our capital expenditures;
|
|
●
|
supply
of and demand for oil and natural gas; and
|
|
●
|
changes
in governmental regulations or taxation.
|
The
timing of our production and incurrence of expenses in connection with the development and production of oil and natural gas properties
will affect the timing of actual future net cash flows from proved reserves and thus their actual present value. In
addition, the 10% discount factor we use when calculating discounted future net cash flows in compliance with GAAP may not be
the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the oil
and gas industry in general.
Lower
oil and natural gas prices and other factors have resulted in, and in the future may result in, ceiling test write-downs and other
impairments of our asset carrying values.
We
use the full cost method of accounting to report our oil and natural gas operations. Under this method, we capitalize the cost
to acquire, explore for, and develop oil and natural gas properties, including capitalizing the costs of abandoned properties,
dry holes, geophysical costs, and annual lease rentals. All general and administrative corporate costs unrelated to drilling activities
are expensed as incurred. Sales or other dispositions of oil and natural gas properties are accounted for as adjustments to capitalized
costs, with no gain or loss recorded unless the ratio of cost to proved reserves would significantly change. Depletion of evaluated
oil and natural gas properties is computed on the units of production method based on proved reserves. The average depletion rate
per Mcfe of production associated with our reserves was approximately $0.80 for the six months ended June 30, 2018. Total depletion
expense for oil and natural gas properties was approximately $3.1 million for the six months ended June 30, 2018.
Under full cost accounting rules, the
net capitalized costs of proved oil and natural gas properties may not exceed a “ceiling limit,” which is based upon
the present value of estimated future net cash flows from proved reserves, discounted at 10%. If net capitalized costs of proved
oil and natural gas properties exceed the ceiling limit, we must charge the amount of the excess to earnings. This is called a
“ceiling test write-down.” Under GAAP, we are required to perform a ceiling test each quarter. Because the ceiling
calculation requires a rolling 12-month average commodity price, due to the effect of lower prices in 2016, we recognized an impairment
of approximately $4.3 million for the year ended December 31, 2016. We did not recognize an impairment for the year ended December
31, 2017 or for the six months ended June 30, 2018. Impairment charges do not affect cash flows from operating activities, but
do adversely affect earnings and stockholders’ equity.
Investments
in unproved properties are assessed periodically to ascertain whether impairment has occurred. Unproved properties whose costs
are individually significant are assessed individually by considering the primary lease terms of the properties, the holding period
of the properties, and geographic and geologic data relating to the properties. The amount of impairment assessed, if any, is
added to the costs to be amortized in the appropriate full cost pool. If an impairment of unproved properties results in a reclassification
to proved reserves, the amount by which the ceiling limit exceeds the capitalized costs of proved reserves would be reduced.
In
addition, GAAP requires us to write down, as a non-cash charge to earnings, the carrying value of our oil and natural gas properties
for impairments, which may occur if we experience substantial downward adjustments to our estimated proved reserves or our unproved
property values, or if estimated future development costs increase. We are required to perform impairment tests on our assets
periodically and whenever events or changes in circumstances warrant a review of our assets. To the extent such tests indicate
a reduction of the estimated useful life or estimated future cash flows of our assets, the carrying value may not be recoverable
and therefore requires a write-down. Future write-downs of our full cost pool may be required if oil and natural gas prices decline,
unproved property values decrease, estimated proved reserve volumes are revised downward or costs incurred in exploration, development,
or acquisition activities in our full cost pool exceed the discounted future net cash flows from the additional reserves, if any,
attributable to our cost pool. Any recorded impairment is not reversible at a later date.
Our
exploration and development projects and acquisitions require substantial capital expenditures. We may be unable to obtain required
capital or financing on satisfactory terms, which could lead to a decline in our reserves.
The oil and natural gas industry is
capital intensive. We make and expect to continue to make substantial capital expenditures for the development, exploitation,
production and acquisition of oil and natural gas reserves. Our cash used in investing activities related to acquisition, development
and exploration expenditures (not including Carbon Appalachia and Carbon California) was approximately $1.2 million and $1.6 million
for the six months ended June 30, 2018 and the year ended December 31, 2017, respectively. Carbon Appalachia’s cash used
in investing activities related to acquisition, development and exploration expenditures was approximately $218,000 and $74.2
million for the six months ended June 30, 2018 and the period ended December 31, 2017, respectively. Carbon California’s
cash used in investing activities related to acquisition, development and exploration expenditures was approximately $39.0 million
and $42.2 million for the six months ended June 30, 2018 and the period ended December 31, 2017, respectively. We contribute our
proportionate share, as a holder of Class A units that require capital contributions, of the capital expenditure obligations of
Carbon Appalachia and Carbon California.
We anticipate that the budget for the
second half of 2018 for exploration and development work on existing acreage will range between $0 million and $1.0 million for
us, between $1.0 million and $4.0 million for Carbon Appalachia, and between $5.0 million and $8.0 million for Carbon California.
We anticipate that the budget for 2019 for exploration and development work on existing acreage will range between $4.0 million
and $8.0 million for us, between $10.0 million and $25.0 million for Carbon Appalachia, and between $15.0 million and $21.0 million
for Carbon California. The budget will be highly dependent on prices that we receive for our oil and natural gas sales. We intend
to finance future capital expenditures through cash on hand, cash flow from operations, and from borrowings under bank credit
facilities. Our cash flows from operations and access to capital are subject to a number of variables, including:
|
●
|
the
volume of hydrocarbons we are able to produce from existing wells;
|
|
●
|
the
prices at which our production is sold;
|
|
●
|
the
levels of our operating expenses; and
|
|
●
|
our
ability to acquire, locate, and produce new reserves.
|
However,
our financing needs, especially in regard to potential acquisitions, may exceed those resources, and our actual capital expenditures
in 2018 could exceed our budget. The Seneca Acquisition closed in May 2018 with a purchase price of $43.0 million, of which our
portion was approximately $5.0 million. Other opportunities may arise during 2018 that could cause our capital expenditures to
exceed the budget. In the event our capital expenditure requirements at any time are greater than the amount of capital we have
available, we may be required to seek additional sources of capital, which may include the issuance of debt or equity securities,
sale of assets, delays in planned exploration, development and completion activities or the use of outside capital through equity
investees or similar arrangements.
Our
business and operating results can be harmed by factors such as the availability, terms, and cost of capital, increases in interest
rates, or a reduction in our credit rating. Changes in any one or more of these factors could cause our cost of doing business
to increase, limit our access to capital, limit our ability to pursue acquisition opportunities, reduce our cash flows available
for drilling, and place us at a competitive disadvantage. In addition, our ability to access the private and public debt or equity
markets is dependent upon a number of factors outside our control, including oil and natural gas prices as well as economic conditions
in the financial markets. Continuing disruptions and volatility in the global financial markets may lead to an increase in interest
rates or a contraction in credit availability impacting our ability to finance operations. We cannot assure you that we will be
able to obtain debt or equity financing on terms favorable to us, or at all.
If
we are unable to fund our capital requirements, we may be required to curtail our operations relating to the exploration and development
of our prospects, which in turn could lead to a possible loss of properties and a decline in our reserves, or may be otherwise
unable to implement our development plan, complete acquisitions, or otherwise take advantage of business opportunities or respond
to competitive pressures, any of which could have a material adverse effect on our production, revenues, and results of operations.
In addition, a delay in or the failure to complete proposed or future infrastructure projects could delay or eliminate potential
efficiencies and related cost savings.
Carbon
California may require its members, including us, to make additional capital contributions to it. If we fail to make a required
capital contribution to Carbon California, (i) we would be considered a defaulting member, (ii) we would lose our representative
on the Board of Directors, and (iii) Prudential would have the option to pay our pro rata portion of the capital contribution
and receive the pro rata share of Class A Units in Carbon California that we otherwise would have received.
Our
identified drilling locations are scheduled for development only if oil and gas prices warrant drilling over a substantial number
of years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling.
At
an appropriate level of oil and natural gas prices, we have a multi-year drilling inventory of horizontal and vertical drilling
locations on existing acreage. These drilling locations, including those without PUDs, represent a significant part of our growth
strategy. Our ability to drill and develop these locations depends on a number of uncertainties, including the availability of
capital, construction of infrastructure, inclement weather, regulatory changes and approvals, commodity prices, lease expirations,
our ability to secure rights to drill at deeper formations, costs, and drilling results.
Further,
our identified potential drilling locations are in various stages of evaluation, ranging from locations that are ready to drill
to locations that will require substantial additional analysis of data. We cannot predict in advance of drilling and testing whether
any particular drilling location will yield oil or natural gas reserves in sufficient quantities to recover drilling or completion
costs or to be economically viable or whether wells drilled on 20-acre spacing will produce at the same rates as those on 40-acre
spacing. The use of reliable technologies and the study of producing fields in the same area will not enable us to know conclusively
prior to drilling whether oil or natural gas reserves will be present or, if present, whether oil or natural gas reserves will
be present in sufficient quantities to be economically viable. Even if sufficient amounts of oil or natural gas reserves exist,
we may damage the potentially productive hydrocarbon bearing formation or experience mechanical difficulties while drilling or
completing the well, possibly resulting in a reduction in production from the well or abandonment of the well. If we drill dry
holes in our current and future drilling locations, our drilling success rate may decline and materially harm our business. We
cannot assure you that the analogies we draw from available data from other wells, more fully explored locations, or producing
fields will be applicable to our drilling locations. Further, initial production rates reported by us or other operators in the
Appalachian Basin and Ventura Basin may not be indicative of future or long-term production rates.
Because
of these uncertainties, we do not know if the potential drilling locations we have identified will ever be drilled or if we will
be able to produce oil or natural gas reserves from these or any other potential drilling locations. As such, our actual drilling
activities may materially differ from those presently identified, which could adversely affect our business, financial condition,
and results of operations.
Our
acreage must be drilled before lease expiration, generally within three to five years, in order to hold the acreage by production.
In a highly competitive market for acreage, failure to drill sufficient wells to hold acreage may result in a substantial lease
renewal cost, or if renewal is not feasible, loss of our lease and prospective drilling opportunities.
Leases
on oil and natural gas properties typically have a term of three to five years, after which they expire unless prior to expiration,
production is established within the spacing units covering the undeveloped acres. The cost to renew such leases may increase
significantly, and we may not be able to renew such leases on commercially reasonable terms or at all. Any reduction in our current
drilling program, either through a reduction in capital expenditures or the unavailability of drilling rigs, could result in the
loss of acreage through lease expirations. We cannot assure you that we will have the liquidity to deploy these rigs when needed,
or that commodity prices will warrant operating such a drilling program. Any such losses of leases could materially and adversely
affect the growth of our asset base, cash flows, and results of operations.
Unless
we replace our reserves, our reserves and production will decline, which would adversely affect our future cash flows and results
of operations.
Producing
oil and natural gas reservoirs generally are characterized by declining production rates that vary depending upon reservoir characteristics
and other factors. As a result, we must locate, acquire and develop new reserves to replace those being depleted by production.
Our business strategy is to grow production and reserves through acquisitions and through exploration and development drilling.
Unless we conduct successful exploration, development and production activities or acquire properties containing proved reserves,
our proved reserves will decline as our existing reserves are produced. Our future oil and natural gas reserves and production,
and therefore our future cash flow and results of operations, are highly dependent on our success in efficiently developing our
reserves and economically finding or acquiring additional recoverable reserves. We have made, and expect to make in the future,
substantial capital expenditures in our business and operations for the development, production, exploration, and acquisition
of reserves. We may not have sufficient resources to undertake our exploration, development, and production activities. In addition,
we may not be able to develop, exploit, find or acquire sufficient additional reserves to replace our current and future production.
If we are unable to replace our current and future production, the value of our reserves will decrease, and our business, financial
condition and results of operations will be adversely affected.
Drilling
for and producing oil and natural gas are high risk activities with many uncertainties that could adversely affect our business,
financial condition and results of operations.
Our
future financial condition and results of operations will depend on the success of our acquisition, exploration, development and
production activities. These activities are subject to numerous risks beyond our control, including the risk that drilling will
not result in commercially viable oil and natural gas production. Our decision to purchase, explore, develop or otherwise exploit
prospects or properties will depend in part on the evaluation of data obtained through geophysical and geological analyses, production
data and engineering studies, the results of which are often inconclusive or subject to varying interpretations. For a discussion
of the uncertainty involved in these processes, see “—
Reserve estimates depend on many assumptions that may
turn out to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect
the quantities and present value of our proved reserves
.” The costs of exploration, exploitation, and development
activities are subject to numerous uncertainties beyond our control, and increases in those costs can adversely affect the economics
of a project. In addition, drilling and completion costs may increase prior to completion of any particular project. Many factors
may curtail, delay or cancel scheduled drilling and production projects, including:
|
●
|
high
costs, shortages or delivery delays of drilling rigs, equipment, labor or other services;
|
|
●
|
unexpected
operational events and drilling conditions;
|
|
●
|
sustained
depressed oil and natural gas prices and further reductions in oil and natural gas prices;
|
|
●
|
limitations
in the market for oil and natural gas;
|
|
●
|
problems
in the delivery of oil and natural gas to market (see “—
Our business depends in part on gathering and transportation
facilities owned by others. Any limitation in the availability of those facilities would interfere with our ability to market
the natural gas we produce.
”);
|
|
●
|
adverse
weather conditions;
|
|
●
|
facility
or equipment malfunctions;
|
|
●
|
equipment
failures or accidents;
|
|
●
|
pipe
or cement failures;
|
|
●
|
compliance
with environmental and other governmental requirements;
|
|
●
|
delays
in obtaining, extending or renewing necessary permits or the inability to obtain, extend or renew such permits at all;
|
|
●
|
environmental
hazards, such as natural gas leaks, oil spills, pipeline ruptures and discharges of toxic gases;
|
|
●
|
lost
or damaged oilfield drilling and service tools;
|
|
●
|
unusual
or unexpected geological formations;
|
|
●
|
loss
of drilling fluid circulation;
|
|
●
|
pressure
or irregularities in formations;
|
|
●
|
fires,
blowouts, surface craterings and explosions; and
|
|
●
|
uncontrollable
flows of oil, natural gas or well fluids.
|
Additionally,
drilling, transportation and processing of hydrocarbons bear an inherent risk of loss of containment. Potential consequences include
loss of reserves, loss of production, loss of economic value associated with an affected wellbore, contamination of soil, ground
water, and surface water, as well as potential fines, penalties, or damages associated with any of the foregoing consequences.
Part
of our strategy involves drilling in existing or emerging shale plays using the latest available horizontal drilling and completion
techniques, which involve risks and uncertainties in their application.
Our
operations involve utilizing the latest drilling and completion techniques as developed by us and our service providers. Risks
that we may face while drilling include, but are not limited to, failing to land our wellbore in the desired drilling zone, not
staying in the desired drilling zone while drilling horizontally through the formation, not running our casing the entire length
of the wellbore, and not being able to run tools and other equipment consistently through the horizontal wellbore. Risks that
we may face while completing our wells include, but are not limited to, not being able to fracture stimulate the planned number
of stages, not being able to run tools the entire length of the wellbore during completion operations, and not successfully cleaning
out the wellbore after completion of the final fracture stimulation stage. In addition, to the extent we engage in horizontal
drilling, those activities may adversely affect our ability to successfully drill in one or more of our identified vertical drilling
locations.
Our
experience with horizontal drilling utilizing the latest drilling and completion techniques is limited. Ultimately, the success
of these drilling and completion techniques can only be evaluated over time as more wells are drilled and production profiles
are established over a sufficiently long time period. If our drilling results are less than anticipated or we are unable to execute
our drilling program because of capital constraints, lease expirations, access to gathering systems, and/or commodity prices decline,
the return on our investment in these areas may not be as attractive as we anticipate. Further, as a result of any of these developments
we could incur material write-downs of our oil and natural gas properties and the value of our undeveloped acreage could decline
in the future.
A
significant portion of our business is conducted in basins with established production histories. The mature nature of these region
could result in lower production.
The
Appalachian and Ventura Basins are mature oil and natural gas production regions that have experienced substantial exploration
and development activity for many years. Because a large number of oil and natural gas prospects in this region have already been
drilled, additional prospects of sufficient size and quality could be more difficult to identify. We cannot assure you that our
future drilling activities in these plays will be successful or, if successful, will achieve the potential reserve levels that
we currently anticipate based on the drilling activities that have been completed, or that we will achieve the anticipated economic
returns based on our current cost models.
Our
operations are substantially dependent on the availability of water. Restrictions on our ability to obtain water may have an adverse
effect on our financial condition, results of operations, and cash flows.
Water
is an essential component of deep shale oil and natural gas production during both the drilling and hydraulic fracturing processes.
Historically, we have been able to purchase water from local land owners for use in our operations. As a result of severe drought,
some local water districts have begun restricting the use of water subject to their jurisdiction for hydraulic fracturing to protect
the availability of local water supply. If we are unable to obtain water to use in our operations from local sources, we may be
unable to economically produce our reserves, which could have an adverse effect on our financial condition, results of operations,
and cash flows.
We
may face unanticipated water and other waste disposal costs.
We
may be subject to regulation that restricts our ability to discharge water produced as part of our natural gas production operations.
Productive zones frequently contain water that must be removed in order for the natural gas to produce, and our ability to remove
and dispose of sufficient quantities of water from the various zones will determine whether we can produce natural gas in commercial
quantities. The produced water must be transported from the production site and injected into disposal wells. The capacity of
the disposal wells we own may not be sufficient to receive all of the water produced from our wells and may affect our ability
to produce our wells. Also, the cost to transport and dispose of that water, including the cost of complying with regulations
concerning water disposal, may reduce our profitability.
Where
water produced from our projects fails to meet the quality requirements of applicable regulatory agencies, our wells produce water
in excess of the applicable volumetric permit limits, the disposal wells fail to meet the requirements of all applicable regulatory
agencies, or we are unable to secure access to disposal wells with sufficient capacity to accept all of the produced water, we
may be required to shut in wells, reduce drilling activities, or upgrade facilities for water handling or treatment. The costs
to dispose of this produced water may increase if any of the following occur:
|
●
|
we
cannot obtain future permits from applicable regulatory agencies;
|
|
●
|
water
of lesser quality or requiring additional treatment is produced;
|
|
●
|
our
wells produce excess water;
|
|
●
|
new
laws and regulations require water to be disposed in a different manner; or
|
|
●
|
costs
to transport the produced water to the disposal wells increase.
|
Our
insurance may not protect us or them against all of the operating risks to which our business is exposed.
The
crude oil and natural gas business involves numerous operating hazards such as well blowouts, mechanical failures, explosions,
uncontrollable flows of crude oil, natural gas or well fluids, fires, formations with abnormal pressures, hurricanes, flooding,
pollution, releases of toxic gas and other environmental hazards and risks, which can result in (i) damage to or destruction of
wells and/or production facilities, (ii) damage to or destruction of formations, (iii) injury to persons, (iv) loss of life, or
(v) damage to property, the environment or natural resources. While we and our subsidiaries carry general liability, control of
well, and operator’s extra expense coverage typical in our industry, we are not fully insured against all risks incidental
to our and their business. Environmental incidents resulting from our operations could defer revenue, increase operating costs
and/or increase maintenance and repair capital expenditures.
Many
of our operations are currently conducted in locations that may be at risk of damage from fire, mudslides, earthquakes or other
natural disasters.
Carbon
California currently conducts operations in California near known wildfire and mudslide areas and earthquake fault zones. Certain
of Carbon California’s operations were temporarily halted in December 2017 due to the wildfires in South California. A future
natural disaster, such as a fire, mudslide or an earthquake, could cause substantial delays in our operations, damage or destroy
equipment, prevent or delay transport of production and cause us to incur additional expenses, which would adversely affect our
business, financial condition and results of operations. In addition, our facilities would be difficult to replace and would require
substantial lead time to repair or replace. The insurance we maintain against earthquakes, mudslides, fires and other natural
disasters would not be adequate to cover a total loss of our facilities, may not be adequate to cover our losses in any particular
case and may not continue to be available to us on acceptable terms, or at all.
We
may suffer losses or incur environmental liability in hydraulic fracturing operations.
Oil
and natural gas deposits exist in shale and other formations. It is customary in our industry to recover oil and natural gas from
these shale formations through the use of hydraulic fracturing, combined with horizontal drilling. Hydraulic fracturing is the
process of creating or expanding cracks, or fractures, underground where water, sand and other additives are pumped under high
pressure into a shale formation. We contract with established service companies to conduct our hydraulic fracturing. The personnel
of these service companies are trained to handle potentially hazardous materials and possess emergency protocols and equipment
to deal with potential spills and carry material safety data sheets for all chemicals.
In
the fracturing process, an accidental release could result in possible environmental damage. All wells have manifolds with escape
lines to containment areas. High pressure valves for flow control are on the wellheads. Valves and piping are designed for higher
pressures than are typically encountered. Piping is tested prior to any procedure and regular safety inspections and incident
drill records are kept on those tests. Despite all of these safety procedures, there are many risks involved in hydraulic fracturing
that could result in liability to us. In addition, our liability for environmental hazards may include conditions created by the
previous owner of properties that we purchase or lease.
We
have entered into natural gas and oil derivative contracts and may in the future enter into additional commodity derivative contracts
for a portion of our production, which may result in future cash payments or prevent us from receiving the full benefit of increases
in commodity prices.
We
use commodity derivative contracts to reduce price volatility associated with certain of our natural gas and oil sales. Under
these contracts, we receive a fixed price per MMbtu of natural gas/Bbl of oil and pay a floating market price per MMbtu/Bbl of
natural gas/oil to the counterparty based on Henry Hub/NYMEX WTI pricing. The fixed-price payment and the floating-price payment
are offset, resulting in a net amount due to or from the counterparty. The extent of our commodity price exposure is related largely
to the effectiveness and scope of our commodity derivative contracts. For example, our commodity derivative contracts are based
on quoted market prices, which may differ significantly from the actual prices we realize in our operations for oil. In addition,
our credit agreement limits the aggregate notional volume of commodities that can be covered under commodity derivative contracts
we enter into and, as a result, we will continue to have direct commodity price exposure on the unhedged portion of our production
volumes. Our policy has been to hedge a significant portion of our estimated oil and natural gas production. However, our price
hedging strategy and future hedging transactions will be determined at our discretion. We are not under an obligation to hedge
a specific portion of our production. The prices at which we hedge our production in the future will be dependent upon commodity
prices at the time we enter into these transactions, which may be substantially higher or lower than current commodity prices.
Accordingly, our price hedging strategy may not protect us from significant declines in commodity prices received for our future
production, whether due to declines in prices in general or to widening differentials we experience with respect to our products.
Conversely, our hedging strategy may limit our ability to realize cash flows from commodity price increases. It is also possible
that a substantially larger percentage of our future production will not be hedged as compared with the next few years, which
would result in our revenues becoming more sensitive to commodity price changes.
In
addition, our actual future production may be significantly higher or lower than we estimate at the time we enter into commodity
derivative contracts for such period. If the actual amount is higher than we estimate, we will have greater commodity price exposure
than we intended. If the actual amount is lower than the notional amount of our commodity derivative contracts, we might be forced
to satisfy all or a portion of our commodity derivative contracts without the benefit of the cash flow from our sale or purchase
of the underlying physical commodity, substantially diminishing our liquidity. There may be a change in the expected differential
between the underlying commodity price in the commodity derivative contract and the actual price received, which may result in
payments to our derivative counterparty that are not offset by our receipt of payments for our production in the field. Accordingly,
our earnings may fluctuate significantly as a result of changes in the fair value of our commodity derivative contracts.
Our
commodity derivative contracts expose us to counterparty credit risk.
Our
commodity derivative contracts expose us to risk of financial loss if a counterparty fails to perform under a contract. Disruptions
in the financial markets could lead to sudden decreases in a counterparty’s liquidity, which could make them unable to perform
under the terms of the contract and we may not be able to realize the benefit of the contract. We are unable to predict sudden
changes in a counterparty’s creditworthiness or ability to perform. Even if we do accurately predict sudden changes, our
ability to negate the risk may be limited depending upon market conditions.
During
periods of declining commodity prices, our derivative contract receivable positions generally increase, which increases our counterparty
credit exposure. If the creditworthiness of our counterparties deteriorates and results in their nonperformance, we could incur
a significant loss with respect to our commodity derivative contracts.
The
inability of our derivative contract counterparty to meet its obligations may adversely affect our financial results.
We
currently have one derivative contract counterparty (BP Energy Company), and this concentration may impact our overall credit
risk in that the counterparty may be similarly affected by changes in economic or other conditions. The inability or failure of
our derivative contract counterparty to meet its obligations to us or their insolvency or liquidation may materially adversely
affect our financial condition and results of operations.
Our
business depends in part on gathering and transportation facilities owned by others. Any limitation in the availability of those
facilities would interfere with our ability to market natural gas we produce.
The
marketability of our natural gas production depends in part on the availability, proximity and capacity of gathering and pipeline
systems owned by third parties. Since we do not own or operate these pipelines or other facilities, their continuing operation
in their current manner is not within our control. The amount of natural gas that can be produced and sold is subject to curtailment
in certain circumstances, such as pipeline interruptions due to scheduled and unscheduled maintenance, excessive pressure, physical
damage to gathering or transportation systems, or lack of contracted transportation capacity on such systems. The curtailments
arising from these and similar circumstances may last from a few days to several months. We may be provided with only minimal,
if any, notice as to when these circumstances will arise, or their duration. If any of these third party pipelines and other facilities
become partially or fully unavailable to transport natural gas or oil, or if the gas quality specifications for the natural gas
gathering or transportation pipelines or facilities change so as to restrict our ability to transport natural gas on those pipelines
or facilities, our revenues and cash available for distribution could be adversely affected.
In
addition, properties may be acquired which are not currently serviced by gathering and transportation pipelines, or the gathering
and transportation pipelines in the area may not have sufficient capacity to transport additional production. As a result, we
may not be able to sell production from these properties until the necessary facilities are built.
We
may incur losses as a result of title deficiencies.
We
typically do not retain attorneys to examine title before acquiring leases or mineral interests. Rather, we rely upon the judgment
of oil and natural gas lease brokers or landmen who perform the fieldwork in examining records in the appropriate governmental
office before attempting to acquire a lease in a specific mineral interest. Prior to drilling a well, however, we (or the company
that is the operator) obtain a preliminary title review to initially determine that no obvious title deficiencies are apparent.
As a result of some such examinations, certain curative work may be required to correct deficiencies in title, and such curative
work may be expensive. In some instances, curative work may not be feasible or possible. Our failure to cure any title defects
may delay or prevent us from utilizing the associated mineral interest, which may adversely impact our ability in the future to
increase production and reserves. Additionally, undeveloped acreage has greater risk of title defects than developed acreage.
If there are any title defects or defects in assignment of leasehold rights in properties in which we hold an interest, we may
suffer a financial loss. In addition, it is possible that certain interests could have been bought in error from someone who is
not the owner. In that event, our interest would be worthless.
In
addition, our reserve estimates assume that we have proper title for the properties we have acquired. In the event we are unable
to perform curative work to correct deficiencies and our interest is deemed to be worthless, our reserve estimates and the financial
information related thereto may be found to be inaccurate, which could have a material adverse effect on us.
Conservation
measures and technological advances could reduce demand for oil and natural gas.
Fuel
conservation measures, alternative fuel requirements, increasing consumer demand for alternatives to oil and natural gas, technological
advances in fuel economy and energy-generation devices could reduce demand for oil and natural gas. The impact of the changing
demand for oil and natural gas services and products may materially adversely affect our business, financial condition, results
of operations and ability to pay dividends on our common stock.
Competition
in the oil and natural gas industry is intense, making it more difficult for us to acquire properties, market oil and natural
gas and secure trained personnel.
The
oil and natural gas industry is intensely competitive, and we compete with other companies that have greater resources than us.
Many of these companies not only explore for and produce oil and natural gas, but also carry on midstream and refining operations
and market petroleum and other products on a regional, national, or international basis. These companies may be able to pay more
for productive oil and natural gas properties and exploratory prospects or define, evaluate, bid for, and purchase a greater number
of properties and prospects than our financial or human resources permit. In addition, these companies may have a greater ability
to continue exploration activities during periods of low oil and natural gas market prices. Our larger competitors may be able
to absorb the burden of present and future federal, state, local, and other laws and regulations more easily than we can, which
would adversely affect our competitive position. Our ability to acquire additional properties and to discover reserves in the
future will be dependent upon our ability to evaluate and select suitable properties and to consummate transactions in a highly
competitive environment. In addition, because we have fewer financial and human resources than many companies in our industry,
we may be at a disadvantage in bidding for exploratory prospects and producing reserves.
The
oil and natural gas industry is characterized by rapid and significant technological advancements and introductions of new products
and services using new technologies. As others use or develop new technologies, we may be placed at a competitive disadvantage
or competitive pressures may force us to implement those new technologies at substantial costs. In addition, other oil and natural
gas companies may have greater financial, technical, and personnel resources that allow them to enjoy technological advantages
and may in the future allow them to implement new technologies before we can. We may not be able to respond to these competitive
pressures and implement new technologies on a timely basis or at an acceptable cost. If one or more of the technologies we use
now or in the future were to become obsolete or if we are unable to use the most advanced commercially available technology, our
business, financial condition, and results of operations could be materially adversely affected.
The
unavailability or high cost of drilling rigs, equipment, supplies, personnel and field services could adversely affect our ability
to execute our exploration and development plans within our budget and on a timely basis.
The
demand for qualified and experienced field personnel, geologists, geophysicists, engineers and other professionals in the industry
can fluctuate significantly, often in correlation with oil and natural gas prices, causing periodic shortages. Historically, there
have been shortages of qualified personnel, drilling and workover rigs, pipe and other equipment and materials as demand for rigs
and equipment increased along with the number of wells being drilled. We cannot predict whether these conditions will exist in
the future and, if so, what their timing and duration will be. Such shortages could delay or cause us to incur significant expenditures
that are not provided for in our capital budget, which could have a material adverse effect on our business, financial condition
and results of operations.
The
loss of senior management or technical personnel could adversely affect operations.
We
depend on the services of our senior management and technical personnel. The loss of the services of our senior management, including
Patrick McDonald, our Chief Executive Officer, Mark Pierce, our President, and Kevin Struzeski, our Chief Financial Officer, Treasurer
and Secretary, could have a material adverse effect on our operations. We do not maintain, nor do we plan to obtain, any insurance
against the loss of any of these individuals.
In
addition, there is competition within our industry for experienced technical personnel and certain other professionals, which
could increase the costs associated with identifying, attracting and retaining such personnel. If we cannot identify, attract,
develop and retain our technical and professional personnel or attract additional experienced technical and professional personnel,
our ability to compete could be harmed.
Due
to our lack of asset and geographic diversification, adverse developments in our operating areas would reduce our ability to pay
dividends on shares of our common stock.
We
derive substantially all of our revenues from sales of natural gas. Furthermore, a substantial majority of our assets are located
in the Ventura Basin in California and Appalachian Basin. Due to our lack of diversification in asset type and location, an adverse
development in the oil and gas business of these geographic areas, including those resulting from the impact of regional supply
and demand factors, delays or interruptions of production from wells in these areas caused by and costs associated with governmental
regulation, processing or transportation capacity constraints, market limitations, water shortages or other weather related conditions,
interruption of the processing or transportation of oil, NGLs or natural gas and changes in regional and local political regimes
and regulations, would have a significantly greater impact on our results of operations and cash available for dividend payments
on shares of our common stock than if we maintained more diverse assets and locations.
There
can be no assurance that the Old Ironsides Buyout will be consummated in the anticipated timeframe, on the terms described herein,
or at all.
We
signed a purchase agreement to acquire all of Old Ironsides’ interest in Carbon Appalachia for $58 million. The consummation
of the Old Ironsides Buyout is subject to certain closing conditions, including a financing condition that we anticipate being
satisfied by the application of the proceeds from this offering. In addition, the purchase agreement contains certain closing
conditions and termination rights for each of Carbon and Old Ironsides if the closing of the Old Ironsides Buyout has not occurred
on or before October 15, 2018. There can be no assurances that the Old Ironsides Buyout will be consummated in the anticipated
timeframe, on the terms described herein, or at all. Our stock price could be negatively impacted if we fail to complete the Old
Ironsides Buyout.
We
may be subject to risks in connection with acquisitions of properties and may be unable to successfully integrate acquisitions.
There
is intense competition for acquisition opportunities in our industry and we may not be able to identify attractive acquisition
opportunities. Even if we do identify attractive acquisition opportunities, we may not be able to complete the acquisitions or
do so on commercially acceptable terms. Competition for acquisitions may increase the cost of, or cause us to refrain from, completing
acquisitions. Our ability to complete acquisitions is dependent upon, among other things, our ability to obtain debt and equity
financing and, in some cases, regulatory approvals. Further, these acquisitions may be in geographic regions in which we do not
currently operate, which could result in unforeseen operating difficulties and difficulties in coordinating geographically dispersed
operations, personnel, and facilities. In addition, if we enter into new geographic markets, we may be subject to additional and
unfamiliar legal and regulatory requirements. Compliance with these regulatory requirements may impose substantial additional
obligations on us and our management, cause us to expend additional time and resources in compliance activities, and increase
our exposure to penalties or fines for non-compliance with such additional legal requirements. Completed acquisitions could require
us to invest further in operational, financial, and management information systems and to attract, retain, motivate, and effectively
manage additional employees. The inability to effectively manage the integration of acquisitions could reduce our focus on subsequent
acquisitions and current operations, which, in turn, could negatively impact our results of operations and growth. Our financial
condition and results of operations may fluctuate significantly from period to period, based on whether or not significant acquisitions
are completed in particular periods.
Any
acquisition involves potential risks, including, among other things:
|
●
|
the
validity of our assumptions about estimated proved reserves, future production, commodity prices, revenues, capital expenditures,
operating expenses, and costs;
|
|
●
|
an
inability to obtain satisfactory title to the assets we acquire;
|
|
●
|
a
decrease in our liquidity by using a significant portion of our available cash or borrowing capacity to finance acquisitions;
|
|
●
|
a
significant increase in our interest expense or financial leverage if we incur additional debt to finance acquisitions;
|
|
●
|
the
assumption of unknown liabilities, losses, or costs for which we obtain no or limited indemnity or other recourse;
|
|
●
|
the
diversion of management’s attention from other business concerns;
|
|
●
|
an
inability to hire, train, or retain qualified personnel to manage and operate our growing assets; and
|
|
●
|
the
occurrence of other significant changes, such as impairment of oil and natural gas properties, goodwill, or other intangible
assets, asset devaluation, or restructuring charges.
|
Our
ability to complete dispositions of assets, or interests in assets, may be subject to factors beyond our control, and in certain
cases we may be required to retain liabilities for certain matters.
From
time to time, we may sell an interest in a strategic asset for the purpose of assisting or accelerating the asset’s development.
In addition, we regularly review our property base for the purpose of identifying nonstrategic assets, the disposition of which
would increase capital resources available for other activities and create organizational and operational efficiencies. Various
factors could materially affect our ability to dispose of such interests or nonstrategic assets or complete announced dispositions,
including the receipt of approvals of governmental agencies or third parties and the availability of purchasers willing to acquire
the interests or purchase the nonstrategic assets on terms and at prices acceptable us.
Sellers
typically retain certain liabilities or indemnify buyers for certain pre-closing matters, such as matters of litigation, environmental
contingencies, royalty obligations and income taxes. The magnitude of any such retained liability or indemnification obligation
may be difficult to quantify at the time of the transaction and ultimately may be material. Also, as is typical in divestiture
transactions, third parties may be unwilling to release us from guarantees or other credit support provided prior to the sale
of the divested assets. As a result, after a divestiture, we may remain secondarily liable for the obligations guaranteed or supported
to the extent that the buyer of the assets fails to perform these obligations.
Properties
we acquire may not produce as projected, and we may be unable to determine reserve potential, identify liabilities associated
with the properties that we acquire, or obtain protection from sellers against such liabilities.
Acquiring
oil and natural gas properties requires us to assess reservoir and infrastructure characteristics, including recoverable reserves,
development and operating costs, and potential environmental and other liabilities. Such assessments are inexact and inherently
uncertain. In connection with the assessments, we perform a review of the subject properties, but such a review will not reveal
all existing or potential problems. In the course of our due diligence, we may not inspect every well or pipeline. We cannot necessarily
observe structural and environmental problems, such as pipe corrosion, when an inspection is made. We may not be able to obtain
contractual indemnities from the seller for liabilities created prior to our purchase of the property. We may be required to assume
the risk of the physical condition of the properties in addition to the risk that the properties may not perform in accordance
with our expectations.
Our
ability to use net operating loss carryforwards to offset future taxable income for U.S. federal income tax purposes is subject
to limitation.
As
of December 31, 2017, we had approximately $21.2 million of U.S. federal net operating loss carryforwards (“
NOLs
”),
which begin to expire in 2032. Utilization of these NOLs depends on many factors, including our future income, which cannot be
assured. In addition, Section 382 of the Internal Revenue Code of 1986, as amended (“
Section 382
”),
generally imposes an annual limitation on the amount of NOLs that may be used to offset taxable income by a corporation that has
undergone an “ownership change” (as determined under Section 382). An ownership change generally occurs if one or
more stockholders (or groups of stockholders) that are each deemed to own at least 5% of our stock increase their ownership percentage
by more than 50 percentage points over their lowest ownership percentage during a rolling three-year period.
We
believe we will experience an ownership change as a result of this offering. Thus, our ability to utilize NOLs existing at the
time of such ownership change will be subject to limitation under Section 382. The application of such NOL limitation may cause
U.S. federal income taxes to be paid earlier than they otherwise would be paid if such limitation were not in effect and could
cause such NOLs to expire unused, in each case reducing or eliminating the benefit of such NOLs. To the extent we are not able
to offset our future income with our NOLs, this would adversely affect our operating results and cash flows if we have taxable
income in the future. Similar rules and limitations may apply for state income tax purposes.
Recently
enacted tax legislation may impact our ability to fully utilize our interest expense deductions and net operating loss carryovers
to fully offset our taxable income in future periods.
On
December 22, 2017, tax legislation commonly known as the Tax Cuts and Jobs Act (the “
TCJA
”) was enacted.
Beginning in 2018, the TCJA generally will (i) limit our annual deductions for interest expense to no more than 30% of our “adjusted
taxable income” (plus 100% of our business interest income) for the year and (ii) permit us to offset only 80% (rather than
100%) of our taxable income with net operating losses we generate after 2017. Interest expense and net operating losses subject
to these limitations may be carried forward by us for use in later years, subject to these limitations. Additionally, the TCJA
repealed the domestic manufacturing tax deduction for oil and gas companies. These tax law changes could have the effect of causing
us to incur income tax liability sooner than we otherwise would have incurred such liability or, in certain cases, could cause
us to incur income tax liability that we might otherwise not have incurred, in the absence of these tax law changes. The TCJA
also includes provisions that, beginning in 2018, reduce the maximum federal corporate income tax rate from 35% to 21% and eliminate
the alternative minimum tax, which would lessen any adverse impact of the limitations described in the preceding sentences.
We
may incur more taxes and certain of our projects may become uneconomic if certain federal income tax deductions currently available
with respect to oil and natural gas exploration and development are eliminated as a result of future legislation.
Various
proposals have been made recommending the elimination of certain key U.S. federal tax incentives that are currently available
with respect to oil and natural gas exploration and development. Any such change could negatively impact our financial condition
and results of operations by increasing the costs we incur which would in turn make it uneconomic to drill some prospects if commodity
prices are not sufficiently high, resulting in lower revenues and decreases in production and reserves.
A
terrorist attack or armed conflict could harm our business.
Terrorist
activities, anti-terrorist activities and other armed conflicts involving the United States or other countries may adversely affect
the United States and global economies. If any of these events occur, the resulting political instability and societal disruption
could reduce overall demand for oil and natural gas, potentially putting downward pressure on demand for our operators’
services and causing a reduction in our revenues. Oil and natural gas facilities, including those of our operators, could be direct
targets of terrorist attacks, and if infrastructure integral to our operators is destroyed or damaged, they may experience a significant
disruption in their operations. Any such disruption could materially adversely affect our financial condition, results of operations
and cash available to pay dividends on our common stock.
Our
business could be materially and adversely affected by security threats, including cybersecurity threats, and other disruptions.
As
an oil and gas producer, we face various security threats, including cybersecurity threats to gain unauthorized access to sensitive
information or to render data or systems unusable; threats to the security of our facilities and infrastructure or third party
facilities and infrastructure, such as processing plants and pipelines; and threats from terrorist acts. The potential for such
security threats has subjected our operations to increased risks that could have a material adverse effect on our business. In
particular, our implementation of various procedures and controls to monitor and mitigate security threats and to increase security
for our information, facilities and infrastructure may result in increased capital and operating costs. Costs for insurance may
also increase as a result of security threats, and some insurance coverage may become more difficult to obtain, if available at
all. Moreover, there can be no assurance that such procedures and controls will be sufficient to prevent security breaches from
occurring. If any of these security breaches were to occur, they could lead to losses of sensitive information, critical infrastructure
or capabilities essential to our operations and could have a material adverse effect on our reputation, financial position, results
of operations and cash flows.
Cybersecurity
attacks in particular are becoming more sophisticated. We rely extensively on information technology systems, including Internet
sites, computer software, data hosting facilities and other hardware and platforms, some of which are hosted by third parties,
to assist in conducting our business. Our technologies systems and networks, and those of our business associates may become the
target of cybersecurity attacks, including without limitation malicious software, attempts to gain unauthorized access to data
and systems, and other electronic security breaches that could lead to disruptions in critical systems and materially and adversely
affect us in a variety of ways, including the following:
|
●
|
unauthorized
access to and release of seismic data, reserves information, strategic information or other sensitive or proprietary information,
which could have a material adverse effect on our ability to compete for oil and gas resources;
|
|
●
|
data
corruption or operational disruption of production infrastructure, which could result in loss of production or accidental
discharge;
|
|
●
|
unauthorized
access to and release of personal identifying information of royalty owners, employees and vendors, which could expose us
to allegations that we did not sufficiently protect that information;
|
|
●
|
a
cybersecurity attack on a vendor or service provider, which could result in supply chain disruptions and could delay or halt
operations; and
|
|
●
|
a
cybersecurity attack on third-party gathering, transportation, processing, fractionation, refining or export facilities, which
could delay or prevent us from transporting and marketing our production, resulting in a loss of revenues.
|
These
events could damage our reputation and lead to financial losses from remedial actions, loss of business or potential liability.
Additionally, certain cyber incidents, such as surveillance, may remain undetected for an extended period.
Increased
costs of capital could materially adversely affect our business.
Our
business, ability to make acquisitions and operating results could be harmed by factors such as the availability, terms and cost
of capital or increases in interest rates. Changes in any one or more of these factors could cause our cost of doing business
to increase, limit our access to capital, limit our ability to pursue acquisition opportunities, and place us at a competitive
disadvantage. A significant reduction in the availability of credit could materially and adversely affect our ability to achieve
our planned growth and operating results.
Increases
in interest rates could adversely affect the demand for our common stock.
An
increase in interest rates may cause a corresponding decline in demand for equity investments, in particular for yield-based equity
investments such as our common stock. Any such reduction in demand for our common stock resulting from other more attractive investment
opportunities may cause the trading price of our common stock to decline.
Risks
Related to Regulatory Requirements
We
are subject to complex federal, state, local and other laws and regulations that could adversely affect the cost, manner or feasibility
of conducting our operations or expose us to significant liabilities.
Our
exploration, production and transportation operations are subject to complex and stringent laws and regulations. In order to conduct
our operations in compliance with these laws and regulations, we must obtain and maintain numerous permits, approvals and certificates
from various federal, state and local governmental authorities. We may incur substantial costs in order to maintain compliance
with these existing laws and regulations. In addition, our costs of compliance may increase if existing laws and regulations are
revised or reinterpreted, or if new laws and regulations become applicable to our operations. Such costs could have a material
adverse effect on our business, financial condition and results of operations. For example, in California, there have been proposals
at the legislative and executive levels in the past for tax increases which have included a severance tax as high as 12.5% on
all oil production in California. Although the proposals have not passed the California legislature, the State of California could
impose a severance tax on oil in the future. Carbon California has significant oil production in California and while we cannot
predict the impact of such a tax without having more specifics, the imposition of such a tax could have severe negative impacts
on its willingness and ability to incur capital expenditures in California to increase production, could severely reduce or completely
eliminate its profit margins from operations in California and would result in lower oil production in its California properties
due to the need to shut-in wells and facilities made uneconomic either immediately or at an earlier time than would have previously
been the case.
Our
business is subject to federal, state and local laws and regulations as interpreted and enforced by governmental authorities possessing
jurisdiction over various aspects of the exploration for, and the production and transportation of, oil and natural gas. Failure
to comply with such laws and regulations, including any evolving interpretation and enforcement by governmental authorities, could
have a material adverse effect on our business, financial condition and results of operations.
Changes
to existing or new regulations may unfavorably impact us, could result in increased operating costs, and could have a material
adverse effect on our financial condition and results of operations. For example, over the last few years, several bills have
been introduced in Congress that, if adopted, would subject companies involved in oil and natural gas exploration and production
activities to, among other items, additional regulation of and restrictions on hydraulic fracturing of wells, the elimination
of certain U.S. federal tax incentives and deductions available for such activities, and the prohibition or additional regulation
of private energy commodity derivative and hedging activities. Additionally, the Bureau of Land Management (“
BLM
”),
acting under its authority pursuant to the Mineral Leasing Act of 1920, finalized new regulations in November 2016 that aimed
to reduce waste of natural gas from federal and tribal leasehold by imposing new venting, flaring, and leak detection and repair
requirements. In December 2017, BLM issued a final rule suspending implementation of the November 2016 rule until January 2019.
In February 2018, the suspension was overturned by the U.S. District Court for Northern California. Implementation of these regulations
remains uncertain due to ongoing litigation. If these regulations, or other potential regulations, particularly at the local level,
are implemented, they could increase our operating costs, reduce our liquidity, delay or halt our operations or otherwise alter
the way we conduct our business, which could in turn have a material adverse effect on our financial condition, results of operations
and cash flows.
Operations
may be exposed to significant delays, costs and liabilities as a result of environmental, health and safety requirements applicable
to our business activities.
We
may incur significant delays, costs and liabilities as a result of environmental, health and safety requirements applicable to
our exploration, development and production activities. These delays, costs and liabilities could arise under a wide range of
federal, state and local laws and regulations and enforcement policies relating to protection of the environment, health and safety,
which have tended to become increasingly stringent over time. Failure to comply with these laws and regulations may result in
the assessment of administrative, civil and criminal penalties, imposition of cleanup and site restoration costs and liens, and,
in some instances, issuance of orders or injunctions limiting or requiring discontinuation of certain operations. We are often
required to prepare and present to federal, state or local authorities data pertaining to the effect or impact that a proposed
project may have on the environment, threatened and endangered species, and cultural and archaeological artifacts. The public
may comment on and otherwise engage in the permitting process, including through judicial intervention. As a result, the permits
we need may not be issued, or if issued, may not be issued in a timely manner or may impose requirements that restrict our ability
to conduct operations.
In
addition, claims for damages to persons or property, including natural resources, may result from the environmental, health and
safety impacts of our operations. Strict liability and joint and several liability may be imposed under certain environmental
laws, which could cause us to become liable for the conduct of others or for consequences of our own actions that were in compliance
with all applicable laws at the time those actions were taken.
New
laws, regulations or enforcement policies could be more stringent and impose unforeseen liabilities or significantly increase
compliance costs. If we are not able to recover the resulting costs through increased revenues, our business, financial condition
or results of operations could be adversely affected.
The
adoption of climate change legislation or regulations restricting emissions of “greenhouse gases” could result in
increased operating costs and reduced demand for the oil and natural gas we produce.
In response to findings that emissions
of carbon dioxide, methane and other “greenhouse gases” present an endangerment to public health and the environment,
the EPA has issued regulations to restrict emissions of greenhouse gases under existing provisions of the federal Clean Air Act.
In June 2016, the EPA finalized rules that establish new air emission controls for methane emissions from certain new, modified
or reconstructed equipment and processes in the oil and natural gas source category, including production, processing, transmission
and storage activities. However, over the past year the EPA has taken steps to delay or pause implementation of the agency’s
methane standards, including a two year stay of the requirements proposed in June 2017. EPA published a notice of data availability
for the two-year stay in November 2017, but it has not yet been finalized. In March 2018, EPA also amended two provisions of the
methane standards. As a result of these developments, future implementation of the 2016 rules is uncertain at this time. In addition,
various industry and environmental groups have separately challenged both the original methane requirements and the EPA’s
attempts to delay implementation of the rules. As a result, substantial uncertainty exists with respect to the future status of
the EPA’s methane rules. Compliance with rules to control methane emissions require enhanced record-keeping practices, new
equipment such as optical gas imaging instruments to detect leaks and increased frequency of maintenance and repair activities
to address emissions leaks. The rules also likely require hiring additional personnel to support these activities or the engagement
of third party contractors to assist with and verify compliance with these rules and could over time increase the cost of upstream
oil and gas operations. Continued implementation of these rules, or additional proposed rules, could result in increased compliance
costs for operators.
In
addition, Congress has from time to time considered adopting legislation to reduce emissions of greenhouse gases and many states
have already established greenhouse gas cap and trade programs. Internationally, the United Nations Framework Convention on Climate
Change finalized an agreement among 195 nations at the 21st Conference of the Parties in Paris with an overarching goal of preventing
global temperatures from rising more than 2 degrees Celsius. The agreement includes provisions that every country take some action
to lower emissions, but there is no legal requirement for how or by what amount emissions should be lowered. In June 2017, President
Trump announced that the United States will withdraw from the Paris Agreement unless it is renegotiated. The State Department
informed the United Nations of the United States’ withdrawal in August 2017. Under the terms of the Paris Agreement, the
earliest possible effective withdrawal date is November 2020.
California
has been one of the leading states in adopting greenhouse gas emission reduction requirements, and has implemented a cap and trade
program as well as mandates for renewable fuels sources. California’s cap and trade program requires Carbon California to
report its greenhouse gas emissions and essentially sets maximum limits or caps on total emissions of greenhouse gases from all
industrial sectors that are or become subject to the program. This includes the oil and natural gas extraction sector of which
Carbon California is a part. Carbon California’s main sources of greenhouse gas emissions for its Southern California oil
and gas operations are primarily attributable to emissions from internal combustion engines powering generators to produce electricity,
flares for the disposal of excess field gas, and fugitive emission from equipment such as tanks and components. Under the California
program, the cap declines annually from 2013 through 2020. In July 2017, California extended the cap and trade program to 2030.
Under the cap and trade program, Carbon California is required to obtain authorizations for each metric ton of greenhouse gases
that it emits, either in the form of allowances (each the equivalent of one ton of carbon dioxide) or qualifying offset credits.
A portion of the allowance will be granted by the state, but any shortfall between the state-granted allowance and the facility’s
emissions will have to be addressed through the purchase of additional allowances either from the state or a third party. The
availability of allowances will decline over time in accordance with the declining cap, and the cost to acquire such allowances
may increase over time. However, we do not expect the cost to be material to Carbon California’s operations.
The
adoption of legislation or regulatory programs to reduce emissions of greenhouse gases could require us to incur increased operating
costs, such as costs to purchase and operate emissions control systems, to acquire emissions allowances or comply with new regulatory
or reporting requirements, or they could promote the use of alternative fuels and thereby decrease demand for the oil and gas
that we produce. Any such legislation or regulatory programs could also increase the cost of consuming, and thereby reduce demand
for, the oil and natural gas. Consequently, legislation and regulatory programs to reduce emissions of greenhouse gases could
have an adverse effect on our business, financial condition and results of operations. Finally, it should be noted that some scientists
have concluded that increasing concentrations of greenhouse gases in the Earth’s atmosphere may produce climate changes
that have significant physical effects, such as increased frequency and severity of storms, droughts and floods and other climatic
events. Our hydraulic fracturing operations require large amounts of water. Such climatic events could have an adverse effect
on our financial condition and results of operations.
Environmental
legislation and regulatory initiatives, including those relating to hydraulic fracturing and underground injection, could result
in increased costs and additional operating restrictions or delays.
We
are subject to extensive federal, state and local laws and regulations concerning environmental protection. Government authorities
frequently add to those regulations. Both oil and gas development generally and hydraulic fracturing in particular, are receiving
increased regulatory attention.
Essentially
all of our reserves in the Appalachian Basin are subject to or have been subjected to hydraulic fracturing. The reservoir rock
in these areas, in general, has insufficient permeability to flow enough oil or natural gas to be economically viable without
stimulation. The controlling regulatory agencies for well construction have standards that are designed specifically in anticipation
of hydraulic fracturing. The stimulation process cost varies according to well location and reservoir. The regulatory environment
may change with respect to the use of hydraulic fracturing. Any increase in compliance costs could negatively impact our ability
to conduct our business.
While
hydraulic fracturing historically has been regulated by state and natural gas commissions, the practice has become increasingly
controversial in certain parts of the country, resulting in increased scrutiny and regulation from federal and state agencies.
The EPA has asserted federal regulatory authority pursuant to the federal SDWA over hydraulic fracturing involving fluids that
contain diesel fuel and published permitting guidance in February 2014 for hydraulic fracturing operations that use diesel fuel
in fracturing fluids in those states in which EPA is the permitting authority. In recent years, the EPA has issued final regulations
under the federal CAA establishing performance standards for completions of hydraulically fractured oil and natural gas wells,
compressors, controllers, dehydrators, storage tanks, natural gas processing plants and certain other equipment. EPA also finalized
rules in June 2016 that prohibit the discharge of wastewater from hydraulic fracturing operations to publicly owned wastewater
treatment plants. Federal agencies have also proposed limits on hydraulic fracturing activities on federal lands and many producing
states, cities and counties have adopted, or are considering adopting, regulations that impose more stringent permitting, public
disclosure and well construction requirements on hydraulic fracturing operations or bans or moratoria on drilling that effectively
prohibit further production of oil and natural gas through the use of hydraulic fracturing or similar operations. For example,
several jurisdictions in California have proposed various forms of moratoria or bans on hydraulic fracturing and other hydrocarbon
recovery techniques, including traditional waterflooding, acid treatments and cyclic steam injection.
Moreover, while the scientific community
and regulatory agencies at all levels are continuing to study a possible linkage between oil and gas activity and induced seismicity,
some state regulatory agencies have modified their regulations or guidance to regulate potential causes of induced seismicity
including fluid injection or oil and natural gas extraction. In addition, the California Division of Oil, Gas & Geothermal
Resources (“
DOGGR
”) adopted regulations intended to bring California’s Class II Underground Injection
Control (“
UIC
”) program into compliance with the federal Safe Drinking Water Act, under which some wells
may require an aquifer exemption. DOGGR has been reviewing all active UIC projects and has developed aquifer exemption proposals
for UIC projects that are identified to be permitted for injection into potentially non-exempt underground sources of drinking
water. In addition, DOGGR has undertaken a comprehensive examination of existing regulations and has begun the rulemaking process
with respect to certain oil and gas activities, such as management of idle wells, pipelines and underground fluid injection. If
new regulatory initiatives are implemented that restrict or prohibit the use of underground injection wells in areas where we
rely upon the use of such wells in our operations, our costs to operate may significantly increase and our ability to continue
production may be delayed or limited, which could have an adverse effect on our results of operation and financial position.
Any
of the above factors could have a material adverse effect on our financial position, results of operations or cash flows and could
make it more difficult or costly for us to perform hydraulic fracturing or underground injection.
Should
we fail to comply with all applicable FERC administered statutes, rules, regulations and orders, we could be subject to substantial
penalties and fines.
FERC
has civil penalty authority under the Natural Gas Act (“
NGA
”), the Natural Gas Policy Act, and the rules,
regulations, restrictions, conditions and orders promulgated under those statutes, including regulations prohibiting market manipulation
in connection with the purchase or sale of natural gas, to impose penalties for current violations of up to approximately $1.2
million per day for each violation and disgorgement of profits associated with any violation. This maximum penalty authority established
by statute will continue to be adjusted periodically for inflation.
Section
1(b) of the NGA exempts certain natural gas gathering facilities from regulation by FERC. We believe that our natural gas gathering
pipelines meet the traditional tests FERC has used to establish a pipeline’s status as an exempt gatherer not subject to
regulation as a natural gas company. While our systems have not been regulated by FERC as a natural gas company under the
NGA, we are required to report aggregate volumes of natural gas purchased or sold at wholesale to the extent such transactions
utilize, contribute to, or may contribute to the formation of price indices. In addition, Congress may enact legislation, FERC
may adopt regulations, or a court may make a determination that may subject certain of our otherwise non-FERC jurisdictional facilities
to further regulation. Failure to comply with those regulations in the future could subject us to civil penalty liability.
The
adoption of derivatives legislation could have an adverse impact on our ability to use derivatives as hedges against fluctuating
commodity prices.
In
July 2010, the Dodd-Frank Act was enacted, representing an extensive overhaul of the framework for regulation of U.S. financial
markets. The Dodd-Frank Act called for various regulatory agencies, including the SEC and the Commodities Futures Trading Commission
(“
CFTC
”), to establish regulations for implementation of many of its provisions. The Dodd-Frank Act
contains significant derivatives regulations, including requirements that certain transactions be cleared on exchanges and that
cash collateral (margin) be posted for such transactions. The Dodd-Frank Act provides for an exemption from the clearing and cash
collateral requirements for commercial end-users, such as Carbon, and includes a number of defined terms used in determining how
this exemption applies to particular derivative transactions and the parties to those transactions. We have satisfied the requirements
for the commercial end-user exception to the clearing requirement and intend to continue to engage in derivative transactions.
In
December 2016, the CFTC proposed rules on capital requirements that may have an impact on our hedging counterparties, as the proposed
rules would require certain swap dealers and major swap participants to calculate capital requirements inclusive of swaps with
commercial end-users. The CFTC has not yet acted on this proposed rulemaking. Also in December 2016, the CFTC re-proposed regulations
regarding position limits for certain futures and option contracts in the major energy markets and for swaps that are their economic
equivalents, subject to exceptions for certain bona fide hedging transactions. The CFTC has not acted on the re-proposed position
limit regulations. As these new position limit rules are not yet final, the impact of those provisions on us is uncertain at this
time. However, as proposed, Carbon anticipates that its swaps would qualify as exempt bona fide hedging transactions. The ultimate
effect of these new rules and any additional regulations is uncertain. New rules and regulations in this area may result in significant
increased costs and disclosure obligations as well as decreased liquidity as entities that previously served as hedge counterparties
exit the market.
Risks
Related to This Offering and Our Common Stock
We
may not have sufficient available cash to pay any dividends on our common stock.
We
may not have sufficient available cash each quarter to enable us to pay any dividends to our stockholders. The actual amount of
our available cash we will have to pay dividends each quarter will be reduced by the cost to fund acquisitions without issuing
additional equity or debt, payments in respect of our debt instruments, other contractual obligations, operating expenses, general
and administrative expenses, maintenance capital expenditures and reserves for future capital needs that the board of directors
may determine are appropriate.
Our
ability to pay regular dividends on our common stock is subject to the discretion of our board of directors.
Our
stockholders will have no contractual or other legal right to dividends. The payment of future dividends on our common stock will
be at the discretion of our board of directors and will depend on, among other things, our earnings, financial condition, capital
requirements, level of indebtedness, statutory and contractual restrictions applying to the payment of dividends and other considerations
that our board of directors deems relevant. Our board of directors will have the authority to establish cash reserves for the
prudent conduct of our business, and the establishment of or increase in those reserves could result in a reduction in cash available
for distribution to pay dividends on our common stock at anticipated levels. Accordingly, we may not be able to make, or may have
to reduce or eliminate, the payment of dividends on our common stock, which could adversely affect the market price of our common
stock.
Delaware
law imposes restrictions on our ability to pay cash dividends on our common stock.
Holders
of our common stock do not have a right to dividends on such shares unless declared or set aside for payment by our board of directors.
Under Delaware law, cash dividends on capital stock may only be paid from “surplus” or, if there is no “surplus,”
from the corporation’s net profits for the then-current or the preceding fiscal year. Unless we operate profitably, our
ability to pay dividends on our common stock would require the availability of adequate “surplus,” which is defined
as the excess, if any, of net assets (total assets less total liabilities) over capital. Our business may not generate sufficient
cash flow from operations to enable us to pay dividends on our common stock.
Our
credit facilities impose restrictions on dividend payments.
Our Existing
Credit Facility contains covenants that prohibit us from paying dividends on our common stock while amounts are owed to LegacyTexas
Bank. Additionally, our Existing Credit Facility requires us to maintain a balance of unencumbered cash and cash equivalents of
$750,000 as of the relevant determination dates. Under the New Revolving Credit Facility, we will not be able to make a dividend
to shareholders unless (i) no default exists or would exist pro forma for such a dividend, (ii) the minimum revolver availability
is at least 15% following such dividend, and (iii) the Net Debt (as defined therein) to Adjusted EBITDAX (as defined therein)
ratio is not greater than 2.75 to 1.00 pro forma for such dividend measured at the time such dividends are declared. There can
be no assurance that we will generate sufficient Adjusted EBITDAX to permit us to pay dividends under our New Revolving Credit
Facility.
Restrictions
on distributions to us by our subsidiaries and affiliates under their credit agreements could limit our ability to pay anticipated
dividends to holders of our common stock. These agreements contain financial tests and covenants that our subsidiaries and affiliates
must satisfy prior to making distributions. If any of our subsidiaries or affiliates is unable to satisfy these restrictions or
is otherwise in default under such agreements, it would be prohibited from making distributions to us that could, in turn, limit
our ability to pay dividends to holders of our common stock.
We
do not have a legal or contractual obligation to pay dividends quarterly or on any other basis. The amount of our quarterly cash
dividends, if any, may vary significantly both quarterly and annually and will be directly dependent on the performance of our
business.
Investors
who are looking for an investment that will pay regular and predictable quarterly dividends should not invest in our common stock.
Our future business performance may be volatile and our cash flows may be unstable and we do not intend to maintain excess dividend
coverage for the purpose of maintaining stability or growth in our dividends nor do we intend to reserve cash for dividends in
future periods or incur debt to pay dividends. Because our quarterly dividends will be dependent upon the amount of cash we generate
each quarter after payment of our fixed and variable expenses and after reserves for (i) debt service and other contractual obligations
and fixed charges and (ii) future operating and capital needs, future quarterly dividends paid to our stockholders will vary significantly
from quarter to quarter and may be zero. Please read “
Dividend Policy and Forecasted Cash Available for Dividends
.”
Our
board of directors will initially adopt a policy to pay dividends to our stockholders, which could limit our ability to grow and
make acquisitions.
As
a result of our dividend policy, we will have limited cash available to fund acquisitions, and we will rely primarily upon external
financing sources, including commercial bank borrowings and the issuance of debt and equity securities, to fund our acquisitions.
As such, to the extent we are unable to finance growth externally, our dividend policy may significantly impair our ability to
grow.
To
the extent we issue additional shares of common stock in connection with any acquisitions or as in-kind dividends, the payment
of dividends on those additional shares of common stock may increase the risk that we will be unable to maintain or increase our
per share dividend level. The incurrence of commercial borrowings or other debt to finance our growth strategy would result in
increased interest expense, which, in turn, would reduce the available cash that we have to distribute to our stockholders.
The
market price of our common stock could be materially adversely affected by sales of substantial amounts of our common stock in
the public markets, including sales by Yorktown.
Giving
effect to the Pro Forma Adjustments, Yorktown and its affiliates will beneficially own approximately %
of our outstanding common stock. After the expiration of the 180-day lockup with the underwriters, Yorktown and its affiliates
will be able to sell their shares in the public markets. Any such sales, or the perception that such sales might occur, could
have a material adverse effect on the price of our common stock or could impair our ability to obtain capital through an offering
of equity securities.
We
have incurred and will continue to incur increased costs and demands upon management and accounting and finance resources as a
result of complying with the laws and regulations affecting public companies; any failure to establish and maintain adequate internal
control over financial reporting or to recruit, train and retain necessary accounting and finance personnel could have an adverse
effect on our ability to accurately and timely prepare our financial statements.
As
a public company, we incur significant administrative, legal, accounting and other burdens and expenses beyond those of a private
company, including those associated with corporate governance requirements and public company reporting obligations. We have had
to and will continue to expend resources to supplement our internal accounting and financial resources, to obtain technical and
public company training and expertise, and to develop and expand our quarterly and annual financial statement closing process
in order to satisfy such reporting obligations.
Our
management team must comply with various requirements of being a public company. We have devoted, and will continue to devote,
significant resources to address these public company-associated requirements, including compliance programs and investor relations,
as well as our financial reporting obligations. Complying with these rules and regulations results in higher legal and financial
compliance costs as compared to a public company. As we continue to acquire other properties and expand our business we expect
these costs to increase.
If
we fail to maintain an effective system of internal controls, we may not be able to accurately report our financial results or
prevent fraud. As a result, current and potential stockholders could lose confidence in our financial reporting, which would harm
our business and the trading price of our common stock.
We
are required to disclose material changes made in our internal control over financial reporting on a quarterly basis and we are
required to assess the effectiveness of our controls annually. Effective internal controls are necessary for us to provide reliable
financial reports, prevent fraud and operate successfully as a public company. We cannot be certain that our efforts to maintain
our internal controls will be successful or that we will be able to comply with our obligations under Section 404 of the Sarbanes
Oxley Act of 2002. We may incur significant costs in our efforts to comply with Section 404. As a smaller reporting company, we
currently are exempt from the requirement to obtain an external audit on the effectiveness of internal controls over financial
reporting provided in Section 404(b) of the Sarbanes-Oxley Act. Any failure to maintain effective internal controls, or difficulties
encountered in implementing or improving our internal controls, could harm our operating results or cause us to fail to meet our
reporting obligations. Ineffective internal controls could also cause investors to lose confidence in our reported financial information,
which would likely have a negative effect on the trading price of our common stock. For a description of a significant deficiency
in our internal controls as of December 31, 2017, please see Note 13 to our consolidated financial statements included in this
prospectus.
An
active, liquid and orderly trading market for our common stock does not exist and may not develop, and the price of our stock
may be volatile and may decline in value.
There
currently is not an active public market for our common stock. An active trading market may not develop or, if developed, may
not be sustained. The lack of an active market may impair your ability to sell your shares of common stock at the time you wish
to sell them or at a price that you consider reasonable. An inactive market may also impair our ability to raise capital by selling
shares of common stock and may impair our ability to acquire other companies or assets by using shares of our common stock as
consideration.
The
market price of our common stock may also be influenced by many factors, some of which are beyond our control, including:
|
●
|
changes
in commodity prices;
|
|
●
|
public
reaction to our press releases, announcements and filings with the SEC;
|
|
●
|
fluctuations
in broader securities market prices and volumes, particularly among securities of oil and natural gas companies;
|
|
●
|
changes
in market valuations of similar companies;
|
|
●
|
departures
of key personnel;
|
|
●
|
commencement
of or involvement in litigation;
|
|
●
|
variations
in our quarterly results of operations or those of other oil and natural gas companies;
|
|
●
|
changes
in general economic conditions, financial markets or the oil and natural gas industry;
|
|
●
|
announcements
by us or our competitors of significant acquisitions or other transactions;
|
|
●
|
changes
in accounting standards, policies, guidance, interpretations or principles;
|
|
●
|
the
failure of securities analysts to cover our common stock after this offering or changes in their recommendations and estimates
of our financial performance;
|
|
●
|
future
sales of our common stock; and
|
|
●
|
the
other factors described in these “
Risk Factors
.”
|
We
are a “smaller reporting company” and the reduced disclosure requirements applicable to smaller reporting companies
may make our common stock less attractive to investors.
We
are considered a “smaller reporting company” (a company that has a public float of less than $75 million or, following
the effectiveness of amendments by the SEC, $250 million) and expect to remain a “smaller reporting company” until
at least June 30, 2019. We are therefore entitled to rely on certain reduced disclosure requirements, such as an exemption from
providing selected financial data and executive compensation information. We have utilized this exemption for each year since
the year ended March 31, 2009. These exemptions and reduced disclosures in our SEC filings due to our status as a smaller reporting
company mean our auditors do not review our internal control over financial reporting and may make it harder for investors to
analyze our results of operations and financial prospects. We cannot predict if investors will find our common stock less attractive
because we may rely on these exemptions. If some investors find our common stock less attractive as a result, there may be a less
active trading market for our common stock and our common stock prices may be more volatile.
Control
of our stock by current stockholders is expected to remain significant.
Currently,
our key stockholders directly and indirectly beneficially own a majority of our outstanding common stock, and they will continue
to own a substantial amount of our outstanding common stock following this offering. As a result, these affiliates have the ability
to exercise significant influence over matters submitted to our stockholders for approval, including the election and removal
of directors, amendments to our certificate of incorporation and bylaws and the approval of any business combination. This concentration
of ownership may also have the effect of delaying or preventing a change of control of our company or discouraging others from
making tender offers for our shares, which could prevent our stockholders from receiving an offer premium for their shares.
Provisions
of our charter documents and Delaware law may inhibit a takeover, which could limit the price investors might be willing to pay
in the future for our common stock.
Provisions
in our certificate of incorporation and bylaws may have the effect of delaying or preventing an acquisition of us or a merger
in which we are not the surviving company and may otherwise prevent or slow changes in our board of directors and management.
In addition, because we are incorporated in Delaware, we are governed by the provisions of Section 203 of the Delaware General
Corporation Law (the “
DGCL
”), which will apply to us from the closing of this offering. These provisions
could discourage an acquisition of us or other change in control transactions and thereby negatively affect the price that investors
might be willing to pay in the future for our common stock.
Our
amended and restated bylaws designate the state and federal courts located within the State of Delaware as the sole and exclusive
forum for certain types of actions and proceedings that may be initiated by our stockholders, which could limit our stockholders’
ability to obtain a favorable judicial forum for disputes with us or our directors, officers, employees or agents.
Our
amended and restated bylaws provide that, unless we consent in writing to the selection of an alternative forum, the state and
federal courts located within the State of Delaware will, to the fullest extent permitted by applicable law, be the sole and exclusive
forum for (i) any derivative action or proceeding brought on our behalf, (ii) any action asserting a claim of breach
of a fiduciary duty owed by any of our directors, officers, or other employees to us or our stockholders, (iii) any action
asserting a claim arising pursuant to any provision of the DGCL, or (iv) any action asserting a claim governed by the internal
affairs doctrine, in each such case subject to such court’s having personal jurisdiction over the indispensable parties
named as defendants therein. Any person or entity purchasing or otherwise acquiring any interest in shares of our capital stock
will be deemed to have notice of the provisions of our amended and restated bylaws described in the preceding sentence. This choice
of forum provision may limit a stockholder’s ability to bring a claim in a judicial forum that it finds favorable for disputes
with us or our directors, officers, employees or agents, which may discourage such lawsuits against us and such persons. Alternatively,
if a court were to find these provisions of our amended and restated bylaws inapplicable to, or unenforceable in respect of, one
or more of the specified types of actions or proceedings, we may incur additional costs associated with resolving such matters
in other jurisdictions, which could adversely affect our business, financial condition or results of operations.
Terms
of subsequent financings may adversely impact stockholder equity.
We
may raise additional capital through the issuance of equity or debt in the future. In that event, the ownership of our existing
stockholders would be diluted, and the value of the stockholders’ equity in common stock could be reduced. If we raise more
equity capital from the sale of common stock, institutional or other investors may negotiate terms more favorable than the current
prices of our common stock. If we issue debt securities, the holders of the debt would have a claim to our assets that would be
prior to the rights of stockholders until the debt is paid. Interest on these debt securities would increase costs and could negatively
impact operating results.
In
accordance with Delaware law and the provisions of our certificate of incorporation, we may issue preferred stock that ranks senior
in right of dividends, liquidation or voting to our common stock. The issuance by us of such preferred stock may (a) reduce or
eliminate the amount of cash available for payment of dividends to our holders of common stock, (b) diminish the relative voting
strength of the total shares of common stock outstanding as a class, or (c) subordinate the claims of our holders of common stock
to our assets in the event of our liquidation.
The
borrowing base under our secured lending facility presently is $28.0 million and all borrowings under the facility are secured
by a majority of our oil and natural gas assets. The proposed terms of our New Revolving Credit Facility also provide that borrowings
will be secured by a majority of our oil and natural gas assets. Borrowings outside the facility, or, once adopted, the New Revolving
Credit Facility, may have to be unsecured, and such borrowings, if obtainable, may have a higher interest rate, which would increase
debt service costs could negatively impact our operating results.
Our
Certificate of Incorporation does not provide stockholders the pre-emptive right to buy shares from us. As a result, stockholders
will not have the automatic ability to avoid dilution in their percentage ownership of us.
The
underwriters of this offering may waive or release parties to the lock-up agreements entered into in connection with this offering,
which could adversely affect the price of our common stock.
We,
Yorktown and its affiliates and each of our directors and executive officers have entered into lock-up agreements with respect
to their common stock, pursuant to which they are subject to certain resale restrictions for a period of 180 days following the
date of this prospectus. The underwriter, at any time and without notice, may release all or any portion of the common stock subject
to the foregoing lock-up agreements. If the restrictions under the lock-up agreements are waived, then common stock will be available
for sale into the public markets, which could cause the market price of our common stock to decline and impair our ability to
raise capital.
FORWARD-LOOKING
STATEMENTS
The
information in this prospectus includes “forward-looking statements.” All statements, other than statements of historical
fact included in this prospectus, regarding our strategy, forecasted dividend payments, future operations, financial position,
estimated revenues and losses, projected costs, prospects, plans and objectives of management are forward-looking statements.
When used in this prospectus, the words “could,” “believe,” “anticipate,” “intend,”
“estimate,” “expect,” “project” and similar expressions are intended to identify forward-looking
statements, although not all forward-looking statements contain such identifying words. These forward-looking statements are based
on management’s current expectations and assumptions about future events and are based on currently available information
as to the outcome and timing of future events. Actual results could vary materially. When considering forward-looking statements,
you should keep in mind the risk factors and other cautionary statements described under the heading “
Risk Factors
”
included in this prospectus.
Forward-looking
statements include statements about:
|
●
|
estimates
of our oil and natural gas reserves;
|
|
●
|
estimates
of our future oil and natural gas production, including estimates of any increases or decreases in our production;
|
|
●
|
our
future financial condition and results of operations;
|
|
●
|
our
future revenues, cash flows and expenses;
|
|
●
|
our
access to capital and our anticipated liquidity;
|
|
●
|
our
future business strategy and other plans and objectives for future operations and acquisitions;
|
|
●
|
our
outlook on oil and natural gas prices;
|
|
●
|
the
amount, nature and timing of future capital expenditures, including future development costs;
|
|
●
|
our
ability to access the capital markets to fund capital and other expenditures;
|
|
●
|
our
assessment of our counterparty risk and the ability of our counterparties to perform their future obligations; and
|
|
●
|
the
impact of federal, state and local political, regulatory and environmental developments in the United States.
|
We
caution you that these forward-looking statements can be affected by inaccurate assumptions and are subject to all of the risks
and uncertainties, most of which are difficult to predict and many of which are beyond our control, incident to the exploration
for and development, production and sale of oil and natural gas. In addition, there are numerous uncertainties inherent in estimating
quantities of proved reserves and in projecting future rates of production and timing of development expenditures. Oil and natural
gas reserve engineering is and must be recognized as a subjective process of estimating underground accumulations of oil and natural
gas that cannot be measured in any exact way, and estimates of other engineers might differ materially from those included herein.
The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation,
and estimates may justify revisions based on the results of drilling, testing and production activities. Accordingly, reserve
estimates are often materially different from the quantities of oil and natural gas that are ultimately recovered.
Should
one or more of the risks or uncertainties described in this prospectus occur, or should underlying assumptions prove incorrect,
our actual results, plans and ability to pay cash distributions could differ materially from those expressed in any forward-looking
statements.
All
forward-looking statements, expressed or implied, included in this prospectus are expressly qualified in their entirety by this
cautionary statement. This cautionary statement should also be considered in connection with any subsequent written or oral forward-looking
statements that we or persons acting on our behalf may issue.
Except
as otherwise required by applicable law, we disclaim any duty to update any forward-looking statements, all of which are expressly
qualified by the statements in this section, to reflect events or circumstances after the date of this prospectus.
USE
OF PROCEEDS
We expect to receive approximately
$ million of net proceeds (assuming the midpoint of the
price range set forth on the cover of this prospectus) from the sale of the common stock offered by us after deducting the underwriting
discount and estimated offering expenses payable by us. We intend to use approximately $58 million of the net proceeds of this
offering to fund the Old Ironsides Buyout, $ million
to pay down a portion of our debt and the remaining $ million
for general corporate purposes, including to fund potential expansion capital expenditures and acquisitions. We may temporarily
invest the net proceeds in short-term marketable securities until they are used for their stated purpose.
If the underwriters exercise their option
to purchase additional shares in full, the additional net proceeds to us would be approximately $ million,
after deducting the estimated underwriting discount. We will use any net proceeds from the exercise of the underwriters’
option to purchase additional shares from us for general corporate purposes.
An increase or decrease in the public
offering price of $1.00 per share of common stock would cause the net proceeds from the offering, after deducting the underwriting
discount and estimated offering expenses, to increase or decrease by approximately $
million, based on an assumed public offering price of $
per share of common stock. Each increase of 1.0 million shares of common stock offered by us, together with a concurrent $1.00
increase in the assumed public offering price of $
per share of common stock, would increase net proceeds by approximately $ million.
Similarly, each decrease of 1.0 million shares common stock offered by us, together with a concurrent $1.00 decrease in the assumed
public offering price of $
per share of common stock, would decrease the net proceeds to us from this offering by approximately $
million. If the proceeds increase due to a higher public offering price or decrease due to a lower public offering price, the
amount of net proceeds used for general corporate purposes will increase or decrease, as applicable, by a corresponding amount.
MARKET
PRICE OF OUR COMMON STOCK
Market
Information
We have one class of common stock outstanding,
which has a par value of $0.01 per share. Our common stock is quoted through the OTC Markets (“
OTCQB
”)
under the symbol “CRBO”. We have applied to list our common stock on the Nasdaq Capital Market under the symbol “CRBO.”
Although we believe we will satisfy listing requirements immediately prior to the date of this prospectus, no assurance can be
given that such listing will in fact be achieved.
The limited and sporadic quotations of
our common stock may not constitute an established trading market for our common stock. There can be no assurance that an active
market will develop for our common stock in the future. Effective March 15, 2017 and pursuant to a reverse stock split approved
by the stockholders and Board of Directors, each 20 shares of issued and outstanding common stock became one share of common stock
and no fractional shares were issued. In connection with the reverse stock split, the number of authorized shares of our common
stock was decreased from 200,000,000 to 10,000,000. On June 1, 2018, we increased the number of authorized shares of our common
stock from 10,000,000 to 35,000,000.
The
table below sets forth the high and low bid prices per share for our common stock as quoted on the OTCQB for the periods indicated
and gives retroactive effect to the reverse stock split for all periods presented. All OTCQB quotations included herein reflect
inter-dealer prices, without retail mark-up, mark-down or commission and may not necessarily represent actual transactions.
Period
|
|
High
|
|
|
Low
|
|
First quarter 2016
|
|
$
|
14.00
|
|
|
$
|
3.60
|
|
Second quarter 2016
|
|
|
6.00
|
|
|
|
5.00
|
|
Third quarter 2016
|
|
|
6.40
|
|
|
|
4.00
|
|
Fourth quarter 2016
|
|
|
9.40
|
|
|
|
4.00
|
|
First quarter 2017
|
|
|
12.80
|
|
|
|
10.60
|
|
Second quarter 2017
|
|
|
12.00
|
|
|
|
10.25
|
|
Third quarter 2017
|
|
|
10.60
|
|
|
|
10.50
|
|
Fourth quarter 2017
|
|
|
13.25
|
|
|
|
8.00
|
|
First quarter 2018
|
|
|
11.00
|
|
|
|
9.80
|
|
Second quarter 2018
|
|
|
12.00
|
|
|
|
9.80
|
|
Third quarter 2018 (through September 5, 2018)
|
|
|
13.00
|
|
|
|
9.50
|
|
On September 5, 2018, the closing price of our common stock
was $10.30 per share.
Holders
As
of , there were approximately holders
of record of our common stock. The number of holders does not include the stockholders for whom shares are held in a “nominee”
or “street” name.
DIVIDEND
POLICY AND Forecasted cash Available for Dividends
The following discussion includes
forward-looking statements relating to our dividend policy as well as an illustrative forecast of our possible future operating
results for the twelve month period ending September 30, 2019. This forecast of future operating results is based on the assumptions
described below. However, we cannot assure you that any or all of these assumptions will be realized. Future results will be different
from this forecast and the differences may be materially less favorable. Our operations are subject to numerous risks and uncertainties,
including those discussed above under the caption “
Risk Factors
” and “
Forward-Looking Statements
.”
For additional information regarding our pro forma and historical results of operations, you should refer to our historical financial
statements and the accompanying notes and out unaudited pro forma consolidated financial statements and the accompanying notes
included elsewhere in this prospectus.
Dividend
Policy
We
have not to date paid any cash dividends on our common stock. We have historically retained our earnings to support operations
and to finance the growth of our business.
At or prior to the closing of this
offering, our Board of Directors will adopt a policy pursuant to which we intend to pay, to the extent practicable, quarterly
dividends that grow as we grow our reserves, production and cash flow from operating activities. The amount of our dividends will
be based on the amount of cash we have available each quarter, after reserves for (i) debt service and other contractual obligations
and fixed charges and (ii) future operating or capital needs that the Board of Directors may determine are appropriate. Pursuant
to our dividend policy, we initially intend to maintain a targeted payout ratio of approximately 40% of cash flow from operating
activities (excluding cash flow from Carbon California), subject to the factors described below. Based on our forecast for the
twelve month period ending September 30, 2019 and the related assumptions, and assuming that concurrently with the closing of
this offering we close the Old Ironsides Buyout, we expect to pay dividends of $ ,
$ , $ and $ per
share for the quarters ending December 31, 2018, March 31, 2019, June 30, 2019 and September 30, 2019, subject to the actual declaration
of the dividend by the Board of Directors in accordance with the dividend policy stated herein.
Any
determination to pay dividends will depend on our financial condition, capital requirements, results of operations, contractual
limitations, legal restrictions and any other factors the Board of Directors deem relevant. Events may occur, including a reduction
in forecasted production volumes or realized prices, which could materially adversely affect the actual results we achieve during
the forecasted period. Consequently, our actual results of operations, operating expenses and financial condition during the forecast
period may vary from the forecast, and such variations may be material. Prospective investors are cautioned not to place undue
reliance on our forecast and should make their own independent assessment of our future results of operations and financial condition.
In addition, the Board of Directors may be required to, or may elect to, reduce, or eliminate our dividends during periods of
reduced prices or demand for oil and natural gas, among other reasons. Please read “
Risk Factors
.” Furthermore,
our Board of Directors may change our dividend policy at any time.
We
do not intend to maintain excess dividend coverage for the purpose of maintaining stability or growth in our dividends, nor do
we intend as a general rule to reserve cash for dividends in future periods, nor do we intend to incur debt to pay dividends.
There may be variability in the amount of our quarterly dividends due to fluctuating commodity prices, among other things. For
example, the seasonality of natural gas demand typically results in higher prices during winter months and lower prices during
summer months. We generally expect to finance our capital expenditures with retained cash flow from operating activities as well
as borrowings under our debt agreements. As a result of various factors, such as the extent to which we finance capital expenditures
with cash flow from operating activities or the level of commodity prices, we may increase or decrease our targeted payout ratio.
Restrictions
on Dividends
Under the New Revolving Credit Facility,
we will not be able to make a dividend to shareholders unless (i) no default exists or would exist pro forma for such dividend,
(ii) the minimum revolver availability is at least 15% following such dividend and (iii) the Net Debt (as defined therein) to Adjusted
EBITDAX (as defined therein) ratio is not greater than 2.75 to 1.00 pro forma for such dividend measured at the time such dividends
are declared. Carbon California is currently restricted by the terms of its debt agreements from paying any distributions. The
following projections assume that we do not receive any distributions from Carbon California and that the cash flow from operating
activities at Carbon California is reinvested in the business or used to pay down debt. Had the New Revolving Credit Facility been
in effect historically, it would not have impacted our ability to pay dividends at the targeted payout ratio of 40%.
Furthermore, the amount of dividends
we are able to pay in any quarter may be limited by Delaware General Corporation Law, which provides that a Delaware corporation
may pay dividends only (i) out of the corporation’s surplus, which is defined as the excess, if any, of net assets (total
assets less total liabilities) over capital, or (ii) if there is no surplus, out of the corporation’s net profit for the
fiscal year in which the dividend is declared, or the preceding fiscal year. The forecasted dividends for the twelve month period
ending September 30, 2019 assume that we do not receive any distributions from Carbon California and that the cash flow from operating
activities at Carbon California is reinvested in the business or used to pay down debt.
Unaudited Pro Forma Consolidated
Cash Flow from Operating Activities
On a pro forma
basis, assuming we had completed this offering and the Pro Forma Adjustments on January 1, 2017, we believe our cash flow from
operating activities, excluding Carbon California, for the twelve months ended June 30, 2018 and the year ended December 31, 2017
would have been approximately $15.2 million and $17.7 million, respectively. The amount of cash flow from operating activities
we must generate to support the payment of dividends estimated below at a payout ratio of 40% is approximately $7.1 million
per year. As a result, we would have had sufficient cash flow from operating activities to pay a dividend on our common stock
of $ for the twelve months ended June 30, 2018 and $
for the year ended December 31, 2017. However, our Existing Credit Facility contains covenants that prohibit us from paying dividends
on our common stock while amounts are owed to LegacyTexas Bank and therefore we could not have paid dividends in these amounts
in these historical periods.
We based the
Pro Forma Adjustments upon currently available information and specific estimates and assumptions. The pro forma amounts in the
table below do not purport to present our results of operations had the Pro Forma Adjustments contemplated in this prospectus
actually been completed as of the dates indicated. In addition, cash flow from operating activities is primarily a cash accounting
concept, while our unaudited pro forma financial statements have been prepared on an accrual basis. As a result, you should view
the amount of pro forma cash available for dividends only as a general indication of the amount of cash available for dividends
that we might have generated had the Pro Forma Adjustments occurred on January 1, 2017.
The following
table illustrates, on a pro forma basis for the twelve months ended June 30, 2018 and the year ended December 31, 2017, the amount
of cash available for dividends that would have been available for payment of a dividend on our common stock assuming that this
offering and the Pro Forma Adjustments contemplated in this prospectus had been consummated on January 1, 2017.
($ in thousands, unless
otherwise noted)
|
|
Year Ended December 31,
2017
|
|
|
Twelve Months Ended
June 30, 2018
|
|
Revenue:
|
|
|
|
|
|
|
Oil
|
|
$
|
25,519
|
|
|
$
|
47,366
|
|
Natural gas and liquid sales
|
|
|
63,104
|
|
|
|
48,199
|
|
Derivative Gain / (Loss)
|
|
|
4,092
|
|
|
|
(8,446
|
)
|
Gathering / Midstream Income
|
|
|
23,385
|
|
|
|
29,238
|
|
Other
|
|
|
1,337
|
|
|
|
39
|
|
Total revenue
|
|
$
|
117,437
|
|
|
$
|
116,396
|
|
Expenses:
|
|
|
|
|
|
|
|
|
Lease operating expenses
|
|
|
31,493
|
|
|
|
33,304
|
|
Transportation and gathering costs
|
|
|
17,662
|
|
|
|
14,283
|
|
Production and property taxes
|
|
|
8,062
|
|
|
|
6,147
|
|
Marketing gas purchases
|
|
|
19,679
|
|
|
|
23,202
|
|
General and administrative
|
|
|
13,089
|
|
|
|
15,513
|
|
Depreciation, depletion and amortization
|
|
|
13,905
|
|
|
|
16,290
|
|
Accretion of asset retirement obligations
|
|
|
697
|
|
|
|
1,019
|
|
Total expenses
|
|
$
|
104,587
|
|
|
$
|
109,758
|
|
|
|
|
|
|
|
|
|
|
Operating (loss) income
|
|
|
12,850
|
|
|
|
6,638
|
|
Interest expense
|
|
|
(7,809
|
)
|
|
|
(7,584
|
)
|
Investment in affiliate
|
|
|
68
|
|
|
|
82
|
|
Other
|
|
|
28
|
|
|
|
-
|
|
Income (loss) before income taxes
|
|
|
5,137
|
|
|
|
(864
|
)
|
Provision for income taxes
|
|
|
(74
|
)
|
|
|
-
|
|
Net income (loss) before non-controlling interest
|
|
$
|
5,211
|
|
|
$
|
(864
|
)
|
Net income (loss) attributable
to non-controlling interests
|
|
|
(1,162
|
)
|
|
|
(692
|
)
|
Net income (loss) attributable
to controlling interest
|
|
$
|
6,374
|
|
|
$
|
(172
|
)
|
|
|
|
|
|
|
|
|
|
Cash Flow from Operating Activities
|
|
|
|
|
|
|
|
|
EBITDA
(1)
|
|
$
|
27,452
|
|
|
$
|
23,947
|
|
Interest expense
|
|
|
(7,809
|
)
|
|
|
(7,584
|
)
|
Provision for income taxes
|
|
|
(74
|
)
|
|
|
-
|
|
Cash flow from Operating Activities (Including Carbon
California)
|
|
$
|
19,569
|
|
|
$
|
16,191
|
|
|
|
|
|
|
|
|
|
|
Cash flow from Operating Activities Attributable to
Carbon California
|
|
|
1,837
|
|
|
|
2,708
|
|
Cash flow from Operating Activities Attributable to
Carbon
(Excluding Carbon California)
|
|
$
|
17,732
|
|
|
$
|
13,483
|
|
|
|
|
|
|
|
|
|
|
Cash
available for dividends
(2)
|
|
$
|
7,093
|
|
|
$
|
5,393
|
|
Dividend per share
|
|
|
|
|
|
|
|
|
(1)
|
EBITDA represents
cash flow from operating activities plus interest expense and provision for income taxes.
|
(2)
|
Represents
a payout ratio of 40% of cash flow from operating activities attributable to Carbon (excluding Carbon California).
|
Forecasted
Consolidated Cash Flow from Operating Activities
Based upon the assumptions described
below and assuming that concurrently with the closing of this offering we close the Old Ironsides Buyout, we believe that we will
generate approximately $32.3 million of cash flow from operating activities, excluding Carbon California, over the forecast period
and that such amount will be sufficient to support the payment of dividends forecasted below at a payout ratio of 40%.
In “—Forecast Assumptions and
Considerations” below, we discuss the major assumptions underlying this estimate, including the assumptions that we believe
are relevant to particular line items in the table below. We can give you no assurance that our assumptions will be realized or
that we will generate enough consolidated cash flow from operating activities to support the payment of any dividends during any
period presented below. When considering our ability to generate consolidated cash flow from operating activities and how we calculate
forecasted cash flow from operating activities, please keep in mind all the risk factors and other cautionary statements under
the headings “Risk Factors” and “Forward-Looking Statements,” which discuss factors that could cause our
results of operations and consolidated cash flow from operating activities to vary significantly from our estimates.
We do not, as a matter of course, make
public projections as to future sales, earnings, cash flows or other results. However, our management has prepared the prospective
financial information set forth below to present our expectations regarding our ability to generate $29.63 million of cash flow
from operating activities, excluding Carbon California, and $11.9 million of cash available for dividends, excluding Carbon California,
for the twelve months ending September 30, 2019. The accompanying prospective financial information was not prepared with a view
toward public disclosure or complying with the guidelines established by the American Institute of Certified Public Accountants
with respect to prospective financial information, but, in the view of our management, was prepared on a reasonable basis, reflects
the best currently available estimates and judgments, and presents, to the best of management’s knowledge and belief, the
expected course of action and our expected future financial performance.
The assumptions and estimates underlying
the prospective financial information are inherently uncertain and, though considered reasonable by our management team as of
the date of its preparation, are subject to a wide variety of significant business, market, economic, and competitive risks and
uncertainties that could cause actual results to differ materially from those contained in the prospective financial information.
In particular, we derive our oil and natural gas pricing assumptions from the NYMEX monthly strip pricing as of August 30, 2018.
Accordingly, there can be no assurance that the prospective results are indicative of our future performance or that actual results
will not differ materially from those presented in the prospective financial information. Inclusion of the prospective financial
information in this prospectus should not be regarded as a representation by any person that the results contained in the prospective
financial information will be achieved.
We do not undertake any obligation
to release publicly the results of any future revisions we may make to the forecast or to update this forecast to reflect events
or circumstances after the date of this prospectus, except as required by applicable law. In light of the above, the statement
that we believe that we will have sufficient consolidated cash flow from operating activities to allow us to pay the forecasted
quarterly dividends on all of our outstanding common stock for each quarter in the twelve months ending September 30, 2019 should
not be regarded as a representation by us or the underwriters or any other person that we will generate such cash, or pay such
dividends. Therefore, you are cautioned not to place undue reliance on this forecast.
Neither our independent registered public
accounting firm, independent auditors, nor any other independent registered public accounting firm, has compiled, examined or performed
any procedures with respect to the forecasted financial information contained herein, nor has it expressed any opinion or given
any other form of assurance on such information or its achievability, and it assumes no responsibility for such forecasted financial
information. Our independent registered public accounting firm’s reports included elsewhere in this prospectus relate to
our audited historical combined financial information. These reports do not extend to the tables and the related forecasted information
contained in this section and should not be read to do so.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Twelve Month
|
|
|
|
Quarter
Ending
|
|
|
Period Ending
|
|
($ in
millions, unless otherwise noted)
|
|
December 31,
2018
|
|
|
March 31,
2019
|
|
|
June 30,
2019
|
|
|
September 30,
2019
|
|
|
September 30,
2019
|
|
Net Production
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (MBbl/d)
|
|
|
1.7
|
|
|
|
1.9
|
|
|
|
2.1
|
|
|
|
2.3
|
|
|
|
2.0
|
|
Gas (MMcf/d
|
|
|
59.0
|
|
|
|
64.5
|
|
|
|
66.4
|
|
|
|
70.0
|
|
|
|
65.0
|
|
NGLS
(MBbl/d
|
|
|
0.2
|
|
|
|
0.3
|
|
|
|
0.3
|
|
|
|
0.3
|
|
|
|
0.3
|
|
Average
Daily Equivalents (MMcfe/d)
|
|
|
70.4
|
|
|
|
77.8
|
|
|
|
80.8
|
|
|
|
86.0
|
|
|
|
78.7
|
|
% Gas
|
|
|
84
|
%
|
|
|
83
|
%
|
|
|
82
|
%
|
|
|
81
|
%
|
|
|
83
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Benchmark
Pricing
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil ($/Bbl)
|
|
$
|
69.56
|
|
|
$
|
68.63
|
|
|
$
|
67.73
|
|
|
$
|
66.75
|
|
|
$
|
68.17
|
|
Gas ($/Mcf)
|
|
$
|
2.91
|
|
|
$
|
3.00
|
|
|
$
|
2.62
|
|
|
$
|
2.66
|
|
|
$
|
2.80
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Differentials
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil ($/Bbl)
|
|
$
|
1.58
|
|
|
$
|
1.06
|
|
|
$
|
1.01
|
|
|
$
|
1.28
|
|
|
$
|
1.23
|
|
Gas ($/Mcf)
|
|
$
|
(0.19
|
)
|
|
$
|
(0.16
|
)
|
|
$
|
(0.17
|
)
|
|
$
|
(0.14
|
)
|
|
$
|
(0.17
|
)
|
NGLs (% of Benchmark)
|
|
|
60.1
|
%
|
|
|
59.0
|
%
|
|
|
58.2
|
%
|
|
|
57.6
|
%
|
|
|
58.7
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Realized
Pricing
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil ($/Bbl)
|
|
$
|
71.14
|
|
|
$
|
69.69
|
|
|
$
|
68.74
|
|
|
$
|
68.03
|
|
|
$
|
69.40
|
|
Gas ($/Mcf)
|
|
$
|
2.72
|
|
|
$
|
2.84
|
|
|
$
|
2.45
|
|
|
$
|
2.52
|
|
|
$
|
2.63
|
|
NGLs ($/Bbl)
|
|
$
|
41.84
|
|
|
$
|
40.50
|
|
|
$
|
39.39
|
|
|
$
|
38.45
|
|
|
$
|
40.05
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenue
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil
|
|
$
|
10.9
|
|
|
$
|
12.2
|
|
|
$
|
13.2
|
|
|
$
|
14.7
|
|
|
$
|
51.0
|
|
Gas
|
|
|
14.7
|
|
|
|
16.5
|
|
|
|
14.88
|
|
|
|
16.2
|
|
|
|
62.3
|
|
NGLs
|
|
|
0.9
|
|
|
|
1.0
|
|
|
|
1.0
|
|
|
|
1.1
|
|
|
|
4.0
|
|
Derivative Gain / (Loss)
|
|
|
(1.2
|
)
|
|
|
(1.5
|
)
|
|
|
(0.4
|
)
|
|
|
(0.4
|
)
|
|
|
(3.4
|
)
|
Gathering
/ Midstream Income
|
|
|
1.5
|
|
|
|
2.0
|
|
|
|
1.3
|
|
|
|
1.0
|
|
|
|
5.8
|
|
Total
Revenue
|
|
$
|
26.9
|
|
|
$
|
30.2
|
|
|
$
|
29.9
|
|
|
$
|
32.6
|
|
|
$
|
119.6
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease Operating Expenses
|
|
$
|
(10.1
|
)
|
|
$
|
(10.8
|
)
|
|
$
|
(11.0
|
)
|
|
$
|
(11.1
|
)
|
|
$
|
(43.0
|
)
|
Transportation and Gathering
Costs
|
|
|
(1.1
|
)
|
|
|
(1.2
|
)
|
|
|
(1.3
|
)
|
|
|
(1.5
|
)
|
|
|
(5.0
|
)
|
Plugging & Abandonment
|
|
|
(0.4
|
)
|
|
|
(0.2
|
)
|
|
|
(0.2
|
)
|
|
|
(0.2
|
)
|
|
|
(1.0
|
)
|
Production and Property
Taxes
|
|
|
(1.9
|
)
|
|
|
(2.1
|
)
|
|
|
(2.0
|
)
|
|
|
(2.2
|
)
|
|
|
(8.2
|
)
|
General & Administrative
|
|
|
(3.0
|
)
|
|
|
(3.0
|
)
|
|
|
(3.0
|
)
|
|
|
(3.0
|
)
|
|
|
(11.9
|
)
|
Depreciation,
Depletion & Amortization
|
|
|
(2.5
|
)
|
|
|
(2.8
|
)
|
|
|
(2.9
|
)
|
|
|
(3.2
|
)
|
|
|
(11.4
|
)
|
Total
Expenses
|
|
$
|
(18.9
|
)
|
|
$
|
(20.1
|
)
|
|
$
|
(20.4
|
)
|
|
$
|
(21.2
|
)
|
|
$
|
(80.6
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Income / (Loss)
|
|
$
|
8.0
|
|
|
$
|
10.1
|
|
|
$
|
9.6
|
|
|
$
|
11.4
|
|
|
$
|
39.0
|
|
Interest
Expense
|
|
|
(1.8
|
)
|
|
|
(1.4
|
)
|
|
|
(1.5
|
)
|
|
|
(1.5
|
)
|
|
|
(6.2
|
)
|
Income
Before Income Taxes
|
|
$
|
6.2
|
|
|
$
|
8.7
|
|
|
$
|
8.1
|
|
|
$
|
9.9
|
|
|
$
|
32.9
|
|
Provision
for Income Taxes
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
Net
Income Before Non-Controlling Interests
|
|
$
|
6.2
|
|
|
$
|
8.7
|
|
|
$
|
8.1
|
|
|
$
|
9.9
|
|
|
$
|
32.9
|
|
Net Income Attributable
to Controlling Interests
|
|
$
|
5.6
|
|
|
$
|
7.7
|
|
|
$
|
6.9
|
|
|
$
|
8.1
|
|
|
$
|
28.3
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash
Flow from Operating Activities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EBITDA
(1)
|
|
$
|
10.4
|
|
|
$
|
12.9
|
|
|
$
|
12.5
|
|
|
$
|
14.6
|
|
|
$
|
50.4
|
|
Interest Expense
|
|
|
(1.8
|
)
|
|
|
(1.4
|
)
|
|
|
(1.5
|
)
|
|
|
(1.5
|
)
|
|
|
(6.2
|
)
|
Provision
for Income Taxes
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
Cash
Flow from Operating Activities (Including Carbon California)
|
|
$
|
8.7
|
|
|
$
|
11.4
|
|
|
$
|
11.0
|
|
|
$
|
13.1
|
|
|
$
|
44.3
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash
Flow from Operating Activities Attributable to Carbon California
|
|
|
2.3
|
|
|
|
3.2
|
|
|
|
3.8
|
|
|
|
5.3
|
|
|
|
14.6
|
|
Cash
Flow from Operating Activities Attributable to Carbon (Excluding Carbon California)
|
|
$
|
6.4
|
|
|
$
|
8.3
|
|
|
$
|
7.2
|
|
|
$
|
7.8
|
|
|
$
|
29.6
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash
Available for Dividends
(2)
|
|
$
|
2.5
|
|
|
$
|
3.3
|
|
|
$
|
2.9
|
|
|
$
|
3.1
|
|
|
$
|
11.9
|
|
Dividend per Share
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
|
EBITDA represents cash flow from operating activities plus interest expense and provision for income taxes.
|
(2)
|
Represents a payout ratio of 40% of cash flow from operating activities attributable to Carbon (excluding Carbon California).
|
EBITDA represents cash flow from operating
activities plus interest expense and provision for income taxes. We disclose EBITDA, which is a non-GAAP liquidity measure, because
management believes this metric assists investors and analysts in assessing the ability of our assets to generate sufficient cash
flows to make dividends to our shareholders. You should not consider EBITDA as an alternative to net income (loss), determined
in accordance with GAAP, or as an alternative to cash flows from operating activities, determined in accordance with GAAP, as
an indicator of our cash flows.
EBITDA
has limitations as an analytical tool. Some of these limitations are:
|
●
|
EBITDA
does not reflect cash expenditures or future cash capital expenditures or contractual
commitments;
|
|
●
|
EBITDA
does not reflect changes in, or cash requirements for, our working capital needs;
|
|
●
|
EBITDA
does not reflect the significant interest expense, or the cash requirements necessary
to service interest or principal payments, on our debt;
|
|
●
|
EBITDA
does not reflect payments made or future requirements for income taxes; and
|
|
●
|
Although
depreciation and amortization are non-cash charges, the assets being depreciated and
amortized will often have to be replaced in the future and EBITDA does not reflect any
cash requirements for such replacements.
|
Because of these limitations, EBITDA
should not be considered in isolation or as a substitute for measures calculated in accordance with GAAP.
Forecast
Assumptions and Considerations
The
following assumptions are presented on a consolidated basis unless otherwise stated.
Production estimates.
Our net
daily production for the quarter ended June 30, 2018, pro forma for the Seneca Acquisition, was approximately 61.1 MMcfe/d. We
expect our net daily production over the forecast period to average approximately 78.7 MMcfe/d. The expected increase is primarily
driven by an increase in crude oil production as a result of workovers and field development programs in California and by an
increase in natural gas production as a result of workovers and field development programs in Appalachia.
Oil and natural gas prices and differentials.
Our forecast utilizes monthly NYMEX strip prices as of August 30, 2018 for each of the periods set forth therein. The average
benchmark oil and natural gas prices over the forecast period are $68.17 and $2.80, respectively. Any differences between NYMEX
prices and realized prices are referred to as differentials. Our realized prices are a function of both quality and location differentials.
In estimating our realized prices for the twelve month period ending September 30, 2019, we have considered the oil and natural
gas NYMEX price curves, our historical realized prices across our asset base and any forecasted changes in quality, or location
differentials.
In California, we expect our produced
oil to realize a price approximately $1.23 in excess of forecasted NYMEX oil prices. The production from the region often receives
premium pricing relative to NYMEX oil pricing as a result of increased demand for light oil and our close location to refineries
along the West Coast. In addition, approximately 2.1% of our forecasted production is in the form of natural gas liquids, which
we expect to be priced at 58.7% of NYMEX oil prices, consistent with our historical results.
In Appalachia, we expect to realize
an average differential of ($0.17) per Mcf over the next twelve month period ending September 30, 2019. This differential is primarily
driven by the basis differential between the regional natural gas price index versus NYMEX and the heating value of the natural
gas.
Settlement of derivative contracts.
To achieve more predictable cash flows and to reduce our exposure to downward price fluctuations, we enter into derivative
contracts using fixed price swap contracts and costless collars. Based on our commodity hedges in place as of August 17, 2018
and NYMEX strip prices as of August 30, 2018, we expect to realize a $3.4 million loss over the next twelve month period ending
September 30, 2019. The following is our projected hedge position over the forecast period:
Natural
Gas Swaps
|
|
|
|
Natural
Gas Collars
|
|
|
Oil
Swaps
|
|
|
|
|
|
|
Weighted
Average
|
|
|
|
|
|
Weighted
Average
|
|
|
WTI
|
|
|
Weighted
Average
|
|
|
Brent
|
|
|
Weighted
Average
|
|
MMBtu
|
|
|
Price
(1)
|
|
|
MMBtu
|
|
|
Price
(1)
|
|
|
Bbl
|
|
|
Price
(2)
|
|
|
Bbl
|
|
|
Price
(3)
|
|
|
14,160,000
|
|
|
$
|
2.90
|
|
|
|
1,385,000
|
|
|
$
|
2.94
|
|
|
|
218,427
|
|
|
$
|
53.21
|
|
|
|
153,430
|
|
|
$
|
66.38
|
|
|
(1)
|
NYMEX
Henry Hub Natural Gas futures contract
for the respective period.
|
|
(2)
|
NYMEX Light Sweet Crude West Texas Intermediate
futures contract for the respective period.
|
|
(3)
|
Brent for the respective period.
|
Gathering
and midstream income.
Gathering and marketing income is comprised of several components of activities related to the utilization
of the Company’s natural gas pipelines and related facilities to provide natural gas purchase and resale, gathering and
transportation services to third parties. The income generated by these activities is expected to be variable over the forecast
as a result of seasonal fluctuations in storage volumes. Carbon maintains term natural gas purchase and gathering contracts with
third party producers connected to the Company’s natural gas gathering systems and delivers that natural gas to on-system
and off-system purchasers. In addition, Carbon is a supplier of natural gas to a natural gas distribution company under a contract
whereby Carbon utilizes its ownership and operation of natural gas storage facilities to provide seasonal natural gas supply.
Carbon also utilizes its natural gas pipelines to conduct natural gas purchase and resale activities which utilize the Company’s
pipeline interconnects with third party pipelines.
Lease operating expenses.
Lease
operating expenses include costs incurred to produce oil and natural gas, together with the costs incurred to maintain our producing
properties. Such costs include maintenance, repairs and workover expenses related to our oil and natural gas properties. We estimate
that lease operating expenses for the twelve month period ending September 30, 2019 will be approximately $43.0 million, or $1.50/Mcfe.
This compares to a unit cost of $1.55/Mcfe during the six month period ended June 30, 2018. The increase in estimated cost is
primarily due to the Seneca Acquisition which consisted of oil properties that have higher lease operating expenses per unit of
production.
Transportation
and gathering costs.
Transportation and gathering costs are incurred to bring produced hydrocarbons to market. Transportation
costs refers to costs incurred by us to secure reserved and guaranteed transportation capacity on third party pipelines for the
transportation of natural gas from the natural gas receipt point to the natural gas sales delivery point. Gathering costs are
costs associated with the collection of oil and natural gas from multiple wells and in the case of natural gas, delivery to an
interconnection with a downstream transportation pipeline or, in the case of oil in case of oil, delivery to a central tank battery
or downstream market delivery point. We expect to incur an average transportation and gathering cost of $0.18 per Mcfe over the
forecast period.
Production and property taxes.
Production
(severance) taxes are paid on the extraction of oil and natural gas based on either the value or volume of production. The tax
rate is established by the state taxing authority. Property (ad valorem) tax rates, which can fluctuate by year, are determined
by individual counties where we have production and are assessed on our oil and natural gas revenues one or two years in arrears
depending upon the location of the production. In Appalachia, we expect production taxes and property taxes to average 4.4% and
4.6%, respectively, of oil and natural gas sales over the forecast period. In California, the State does not assess a severance
tax. Instead we expect to pay a special assessment fee of $0.49 per barrel of oil equivalent. The property tax rate is capped
at 1.2% of assessed property value which equates to an average ad valorem tax rate of 3.5% of oil and natural gas sales over the
forecast period.
General administrative expenses.
General
and administrative expenses are expected to increase from $10.4 million during 2017 to $11.9 million over the forecast period
due to the addition of technical, accounting and support personnel to manage and operate the expanded scope of the Company’s
operations as a result of the asset acquisitions during 2017.
Depreciation, depletion and amortization
(“DD&A”).
We use the full cost method of accounting of oil and gas properties. All cost incidental to the
acquisition, exploration and development of oil and gas properties, including costs of undeveloped leasehold, dry holes and leasehold
equipment, are capitalized. Depletion is calculated using capitalized costs in the full cost pool, including estimated asset retirement
costs and estimated future expenditures to be incurred in developing proved reserves, net of estimated salvage values and depleted
based on a unit-of-production method. We are depleting our reserves in California and Appalachia using depletion rates of $0.92
per Mcfe and $0.28 per Mcfe, respectively. On a consolidated basis, this results in a blended depletion rate of $0.40 per Mcfe
over the forecast period.
Interest expense.
We finance
a portion of our working capital requirements for drilling and completion activities and our acquisitions with borrowings under
our credit facilities. As a result, we incur interest expense that is affected by both fluctuations in interest rates and our
financing decisions. During the forecast period, we expect to have an average balance of approximately $26.4 million outstanding
on our Appalachia credit facility, with a borrowing base of $100 million, bearing interest of 5.7%, an average balance of approximately
$37.2 million outstanding on Carbon California’s Senior Revolving Notes, with a borrowing base of $41 million, bearing interest
of 8.3% and an average balance of $13 million of Carbon California’s Subordinated Notes outstanding, bearing interest of
12.0%.
Provision for income taxes
. Over
the next twelve months, Carbon does not anticipate paying federal income taxes. Carbon’s forecasted operating income is
primarily offset by net operating loss carryforward deductions and drilling cost deductions.
Deconsolidation of Carbon California
.
The forecast for the twelve months ending September 30, 2019
is fully consolidated and therefore includes operating results reflecting 100% of Carbon Appalachia and 100% of Carbon California.
Pursuant to the terms of Carbon California’s debt agreements, we subtract 100% of Carbon California’s cash flow from
operating activities.
Capital
expenditures
. Operational capital expenditure items are estimated to be approximately $37.6 million over the forecast period.
Specifically, we expect to spend $25.9 million in Appalachia performing workovers on 11 wellbores and drilling and completing
20 undeveloped locations, and $11.8 million in California performing workovers on 97 wellbores and drilling and completing six
proved undeveloped locations. We expect to finance the substantial majority of these capital expenditures with cash flow from
operating activities with the remainder borrowed under our New Revolving Credit Facility. Although we anticipate making acquisitions
during the forecast period, our forecast does not reflect any acquisitions as we cannot give any assurance that we in fact will
be able to consummate acquisitions or what the terms of any acquisitions would be.
Regulatory, industry and economic
factors
. Our forecast for the twelve month period ending September 30, 2019 is based on the following significant assumptions
related to regulatory, industry and economic factors:
|
●
|
There
will not be any new federal, state, or local regulation of portions of the energy industry
in which we operate, or an interpretation of existing regulation, that will be materially
adverse to our business;
|
|
●
|
There
will not be any major adverse change in commodity prices or the energy industry in general;
|
|
●
|
Market,
insurance and overall economic conditions will not change substantially; and
|
|
●
|
We
will not undertake any extraordinary transactions that would materially affect our cash
flow.
|
Sensitivity
Analyses
Our ability to generate sufficient
cash from operations to pay dividends to our shareholders is a function of two primary variables: (i) production volumes and (ii)
commodity prices. In the paragraphs below, we demonstrate the impact that changes in either of these variables, while holding
all other variables constant, would have on our ability to generate sufficient cash from our operations to pay quarterly dividends
for the twelve month period ending September 30, 2019.
Production
Volume Changes
The following table shows estimated
cash available for dividends under various assumed production levels forecasted for the twelve month period ending September 30,
2019. We have assumed no changes in commodity prices at these different production levels.
|
|
Change
in Forecasted Production Volumes
|
|
($
in millions, unless otherwise noted)
|
|
80%
|
|
|
100%
|
|
|
120%
|
|
Net Production
|
|
|
|
|
|
|
|
|
|
Oil (MBbl/d)
|
|
|
1.6
|
|
|
|
2.0
|
|
|
|
2.4
|
|
Gas (MMcf/d)
|
|
|
52.0
|
|
|
|
65.0
|
|
|
|
78.0
|
|
NGLs (MBbl/d)
|
|
|
0.2
|
|
|
|
0.3
|
|
|
|
0.3
|
|
Average Daily Equivalents (MMcfe/d)
|
|
|
63.0
|
|
|
|
78.7
|
|
|
|
94.5
|
|
% Gas
|
|
|
83
|
%
|
|
|
83
|
%
|
|
|
83
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Benchmark Pricing
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil ($/Bbl)
|
|
$
|
68.17
|
|
|
$
|
68.17
|
|
|
$
|
68.17
|
|
Gas ($/Mcf)
|
|
$
|
2.80
|
|
|
$
|
2.80
|
|
|
$
|
2.80
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Differentials
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil ($/Bbl)
|
|
$
|
1.23
|
|
|
$
|
1.23
|
|
|
$
|
1.23
|
|
Gas ($/Mcf)
|
|
$
|
(0.17
|
)
|
|
$
|
(0.17
|
)
|
|
$
|
(0.17
|
)
|
NGLs (% of Benchmark)
|
|
|
58.7
|
%
|
|
|
58.7
|
%
|
|
|
58.7
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Realized Pricing
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil ($/Bbl)
|
|
$
|
69.40
|
|
|
$
|
69.40
|
|
|
$
|
69.40
|
|
Gas ($/Mcf)
|
|
$
|
2.63
|
|
|
$
|
2.63
|
|
|
$
|
2.63
|
|
NGLs ($/Bbl)
|
|
$
|
40.05
|
|
|
$
|
40.05
|
|
|
$
|
40.05
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash Flow from Operating Activities
|
|
|
|
|
|
|
|
|
|
|
|
|
EBITDA
(1)
|
|
$
|
27.4
|
|
|
$
|
50.4
|
|
|
$
|
73.4
|
|
Interest Expense
|
|
|
(6.8
|
)
|
|
|
(6.2
|
)
|
|
|
(5.6
|
)
|
Provision for Income Taxes
|
|
|
-
|
|
|
|
-
|
|
|
|
(2.3
|
)
|
Cash Flow from Operating Activities (Including
Carbon California)
|
|
$
|
20.7
|
|
|
$
|
44.3
|
|
|
$
|
65.5
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash Flow from Operating Activities Attributable
to Carbon California
|
|
|
5.0
|
|
|
|
14.6
|
|
|
|
24.3
|
|
Cash Flow from Operating Activities Attributable
to Carbon (Excluding Carbon California)
|
|
$
|
15.7
|
|
|
$
|
29.6
|
|
|
$
|
41.2
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash Available for Dividends
(2)
|
|
$
|
6.3
|
|
|
$
|
11.9
|
|
|
$
|
16.5
|
|
Dividend per Share
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
|
EBITDA represents cash flow from operating activities plus interest expense and provision
for income taxes.
|
(2)
|
Represents a payout ratio of 40% of cash flow operating activities attributable to Carbon
(excluding Carbon California)
|
Commodity
Price Changes
The following table shows estimated
cash available for dividends under various assumed commodity prices forecasted for the twelve month period ending September 30,
2019. The amounts shown below are based on forecasted realized commodity prices that take into account our average NYMEX commodity
price differential assumptions. We have assumed no changes in our production based on changes in prices.
|
|
Change in Forecasted Commodity
Prices
|
|
($ in millions, unless otherwise noted)
|
|
80%
|
|
|
100%
|
|
|
120%
|
|
Net Production
|
|
|
|
|
|
|
|
|
|
Oil (MBbl/d)
|
|
|
2.0
|
|
|
|
2.0
|
|
|
|
2.0
|
|
Gas (MMcf/d)
|
|
|
65.0
|
|
|
|
65.0
|
|
|
|
65.0
|
|
NGLs (MBbl/d)
|
|
|
0.3
|
|
|
|
0.3
|
|
|
|
0.3
|
|
Average Daily Equivalents (MMcfe/d)
|
|
|
78.7
|
|
|
|
78.7
|
|
|
|
78.7
|
|
% Gas
|
|
|
83
|
%
|
|
|
83
|
%
|
|
|
83
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Benchmark Pricing
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil ($/Bbl)
|
|
$
|
54.54
|
|
|
$
|
68.17
|
|
|
$
|
81.80
|
|
Gas ($/Mcf)
|
|
$
|
2.24
|
|
|
$
|
2.80
|
|
|
$
|
3.36
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Differentials
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil ($/Bbl)
|
|
$
|
1.23
|
|
|
$
|
1.23
|
|
|
$
|
1.23
|
|
Gas ($/Mcf)
|
|
$
|
(0.17
|
)
|
|
$
|
(0.17
|
)
|
|
$
|
(0.17
|
)
|
NGLs (% of Benchmark)
|
|
|
58.7
|
%
|
|
|
58.7
|
%
|
|
|
58.7
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Realized Pricing
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil ($/Bbl)
|
|
$
|
55.77
|
|
|
$
|
69.40
|
|
|
$
|
83.03
|
|
Gas ($/Mcf)
|
|
$
|
2.07
|
|
|
$
|
2.63
|
|
|
$
|
3.19
|
|
NGLs ($/Bbl)
|
|
$
|
32.04
|
|
|
$
|
40.05
|
|
|
$
|
48.06
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash Flow from Operating Activities
|
|
|
|
|
|
|
|
|
|
|
|
|
EBITDA
(1)
|
|
$
|
39.6
|
|
|
$
|
50.4
|
|
|
$
|
61.4
|
|
Interest Expense
|
|
|
(6.5
|
)
|
|
|
(6.2
|
)
|
|
|
(5.8
|
)
|
Provision for Income Taxes
|
|
|
-
|
|
|
|
-
|
|
|
|
(0.1
|
)
|
Cash Flow from Operating Activities (including Carbon California)
|
|
$
|
33.1
|
|
|
$
|
44.3
|
|
|
$
|
55.5
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash Flow from Operating Activities Attributable to Carbon California
|
|
|
7.5
|
|
|
|
14.6
|
|
|
|
21.8
|
|
Cash Flow from Operating Activities
Attributable to Carbon (Excluding Carbon California)
|
|
$
|
25.6
|
|
|
$
|
29.6
|
|
|
$
|
33.7
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash Available for
Dividends
(2)
|
|
$
|
10.3
|
|
|
$
|
11.9
|
|
|
$
|
13.5
|
|
Dividend per Share
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
|
EBITDA represents cash flow from operating
activities plus interest expense and provision for income taxes.
|
|
(2)
|
Represents
a payout ratio of 40% of cash flow from operating activities attributable to Carbon (excluding
Carbon California).
|
CAPITALIZATION
The following table shows our cash and cash equivalents
and capitalization as of June 30, 2018:
|
●
|
on a pro forma
as adjusted basis to give effect to borrowings under the New Revolving Credit Facility, the sale of shares of common stock
in this offering at an assumed public offering price of $ per
share (which is the midpoint of the price range set forth on the cover of this prospectus) and the application of the net
proceeds therefrom as described under “
Use of Proceeds
.”
|
This table is derived from, and should
be read together with, the historical financial statements and the accompanying notes included elsewhere in this prospectus. You
should also read this table in conjunction with “
Use of Proceeds
” and “
Management’s
Discussion and Analysis of Financial Condition and Results of Operations
.”
|
|
As
of June 30, 2018
|
|
|
|
Actual
|
|
|
As
Adjusted
|
|
|
|
|
|
|
(in
thousands, except
per share data)
(unaudited)
|
|
Cash
and cash equivalents
|
|
$
|
4,030
|
|
|
$
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-term
debt, including current maturities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Existing
Credit Facility
(1)
|
|
$
|
23,140
|
|
|
$
|
|
|
|
$
|
|
|
Carbon
California Senior Secured Revolving Notes
|
|
|
38,500
|
|
|
|
|
|
|
|
|
|
Carbon
California Senior Subordinated Notes, net
|
|
|
13,000
|
|
|
|
|
|
|
|
|
|
Long-term
debt
|
|
|
78
|
|
|
|
|
|
|
|
|
|
CAE
Credit Facility
|
|
|
—
|
(2)
|
|
|
|
|
|
|
|
|
New
Revolving Credit Facility
(3)
|
|
|
—
|
|
|
|
|
|
|
|
|
|
Total
long-term debt, including current maturities
|
|
|
73,118
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Stockholders’
equity:
|
|
|
|
|
|
|
|
|
|
|
|
|
Preferred
stock, $0.01 per share; 1,000,000 shares authorized, 50,000 shares issued and outstanding, actual and as adjusted; and 1,000,000
shares authorized, no shares issued or outstanding, as further adjusted
|
|
$
|
1
|
|
|
$
|
|
|
|
|
|
|
Common
Stock, $0.01 par value; 35,000,000 shares authorized, 7,700,619 shares issued and outstanding, actual and as adjusted; and
35,000,000 shares authorized, shares
issued and outstanding, as further adjusted
|
|
|
77
|
|
|
|
|
|
|
|
|
|
Additional
paid in capital
|
|
|
75,594
|
|
|
|
|
|
|
|
|
|
Accumulated
deficit
|
|
|
(42,424
|
)
|
|
|
|
|
|
|
|
|
Total
stockholders’ equity
|
|
|
33,247
|
|
|
|
|
|
|
|
|
|
Noncontrolling
interest
|
|
|
21,277
|
|
|
|
|
|
|
|
|
|
Total
equity
|
|
|
54,524
|
|
|
|
|
|
|
|
|
|
Total
capitalization
|
|
$
|
162,386
|
|
|
$
|
|
|
|
|
|
|
(1)
|
As of September 5, 2018, we had $26.1 million outstanding under
our Exiting Credit Facility.
|
|
|
(2)
|
As of June 30,
2018, Carbon Appalachia was accounted for as an equity method investment. Accordingly, the $38.0 million of borrowings outstanding
under the CAE Credit Facility is not reflected in our long-term debt on an actual basis.
|
|
|
(3)
|
Entry into the
New Revolving Credit Facility is conditioned upon the closing of this offering.
|
MANAGEMENT’S
DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The
following discussion includes forward-looking statements about our business, financial condition and results of operations, including
discussions about management’s expectations for our business. These statements represent projections, beliefs and expectations
based on current circumstances and conditions, and you should not construe these statements either as assurances of performance
or as promises of a given course of action. Instead, various known and unknown factors may cause our actual performance and management’s
actions to vary, and the results of these variances may be both material and adverse. A description of material factors known
to us that may cause our results to vary, or may cause management to deviate from its current plans and expectations, is set forth
under “
Risk Factors
.” The following discussion should be read in conjunction with “
Forward-Looking
Statements
,” “
Risk Factors
” and our consolidated financial statements, including the notes thereto
appearing elsewhere in this prospectus.
Overview
Carbon Energy Corporation, a Delaware
corporation formed in 2007 and formerly known as Carbon Natural Gas Company, is a growth-oriented, independent oil and natural
gas company engaged in the acquisition, exploration, development and production of oil, natural gas and natural gas liquids properties
in the United States. Our acreage positions provide multiple resource play opportunities and have been delineated largely through
drilling by us, as well as by other industry operators. Our primary business objective is to grow our reserves, production and
cash generated from operations over the long term, while paying, to the extent practicable, a quarterly dividend to our stockholders.
Our
assets, held through our majority-owned subsidiaries, are characterized by stable, long-lived producing properties in the Appalachian
Basin in Kentucky, Ohio, Tennessee, Virginia and West Virginia; the Ventura Basin in California; and the Illinois Basin in Illinois
and Indiana. We focus on conventional and unconventional reservoirs, including shale, tight sands and coalbed methane. Our executive
offices are in Denver, Colorado and we maintain offices in Lexington, Kentucky, and Santa Paula, California from which we conduct
our oil and gas operations.
At December 31, 2017, our proved developed
reserves and our interest in Carbon Appalachia’s and Carbon California’s proved developed reserves were comprised
of 6% oil, 1% natural gas liquids (“
NGL
”), and 93% natural gas. During 2017 and the first quarter of
2018, our capital expenditures consisted principally of oil-related remediation, return to production and recompletion projects
in California and the optimization and streamlining of our natural gas gathering and compression facilities in Appalachia to provide
more efficient and lower cost operations and greater flexibility in moving our production to markets with more favorable pricing.
Our current capital expenditure program is focused on the acquisition and development of oil and natural gas properties in areas
where we currently operate. We believe that our asset and lease position, combined with our low operating expense structure and
technical expertise, provides us with a portfolio of opportunities for the development of our oil and natural gas properties,
including a large inventory of potential return to production, behind pipe recompletion and proved undeveloped drilling projects.
Our growth plan is centered on acquiring, developing, optimizing and maintaining a portfolio of low risk, long-lived oil and natural
gas properties that provide stable cash flows and attractive risk adjusted rates of return.
Factors
That Significantly Affect Our Financial Condition and Results of Operations
Our
revenue, profitability and future growth rate depend on many factors which are beyond our control, including but not limited to,
economic, political and regulatory developments and competition from other industry participants. Our financial results are sensitive
to fluctuations in oil and natural gas prices. Oil and gas prices historically have been volatile and may fluctuate widely in
the future due to a variety of factors, including but not limited to, prevailing economic conditions, supply and demand of hydrocarbons
in the marketplace, actions by speculators, and geopolitical events such as wars or natural disasters. The following table highlights
the quarterly average of NYMEX oil and natural gas prices for the last eight calendar quarters:
|
|
2016
|
|
|
2017
|
|
|
2018
|
|
|
|
Q3
|
|
|
Q4
|
|
|
Q1
|
|
|
Q2
|
|
|
Q3
|
|
|
Q4
|
|
|
Q1
|
|
|
Q2
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (Bbl)
|
|
$
|
44.94
|
|
|
$
|
49.33
|
|
|
$
|
51.86
|
|
|
$
|
48.29
|
|
|
$
|
48.19
|
|
|
$
|
55.39
|
|
|
$
|
62.89
|
|
|
$
|
67.90
|
|
Natural Gas (MMBtu)
|
|
$
|
2.93
|
|
|
$
|
2.98
|
|
|
$
|
3.07
|
|
|
$
|
3.09
|
|
|
$
|
2.89
|
|
|
$
|
2.87
|
|
|
$
|
3.13
|
|
|
$
|
2.77
|
|
Low
oil and natural gas prices may decrease our revenues, may reduce the amount of oil, natural gas and natural gas liquids that we
can produce economically and potentially lower our oil and natural gas reserves. Our estimated proved reserves and our interest
in Carbon Appalachia and Carbon California’s estimated proved reserves may decrease if the economic life of the underlying
producing wells is shortened as a result of lower oil and natural gas prices. A substantial or extended decline in oil or natural
gas prices may result in future impairments of our proved reserves and may materially and adversely affect our future business,
financial condition, cash flows, results of operations or liquidity. Lower oil and natural gas prices may also reduce the amount
of borrowing base under our New Revolving Credit Facility, which is determined at the discretion of our lender and may make it
more difficult to comply with the covenants and other restrictions under our New Revolving Credit Facility.
We use the full cost method of accounting
for our oil and gas properties and perform a ceiling test quarterly. The ceiling calculation utilizes a rolling 12-month average
commodity price. Due to the effect of lower commodity prices in 2016, we recognized an impairment of approximately $4.3 million
for the year ended December 31, 2016. We did not recognize an impairment in 2017 or for the six months ended June 30, 2018.
Future
write downs or impairments, if any, are difficult to predict and will depend not only on commodity prices, but also other factors
that include, but are not limited to, incremental proved reserves that may be added each period, revisions to previous reserve
estimates, capital expenditures and operating costs. There are numerous uncertainties inherent in the estimation of proved reserves
and accounting for oil and natural gas properties in subsequent periods.
We
use commodity derivative instruments, such as swaps and costless collars, to manage and reduce price volatility and other market
risks associated with our production. These arrangements are structured to reduce our exposure to commodity price decreases, but
they can also limit the benefit we might otherwise receive from commodity price increases. Please read “
Business—Risk
Management
” for additional discussion of our commodity derivative contracts.
Impairment
charges do not affect cash flows from operating activities but do adversely affect net income and stockholders’ equity.
An extended decline in oil or natural gas prices may materially and adversely affect our future business, financial condition,
cash flows and liquidity.
Future
property acquisitions or dispositions could have a material impact on our financial condition and results of operations by increasing
or decreasing our reserves, production and revenues as well as expenses and future capital expenditures. We currently anticipate
that we would finance any future acquisitions with available borrowings under our New Revolving Credit Facility, sales of properties
or the issuance of additional equity or debt.
Operational
Highlights
Weakness
in commodity prices has had an adverse impact on our results of operations and the amount of cash flow available to invest in
exploration and development activities. Based on expected future prices for oil and natural gas and the resultant reduced rate
of return on drilling projects, we reduced our drilling activity in 2016 and 2017 in order to manage and optimize the utilization
of our capital resources.
During
2016 and 2017, we concentrated our efforts on the acquisition and enhancement of producing properties through the EXCO Acquisition
and our equity investments in Carbon Appalachia and Carbon California, which completed a number of acquisitions. Our field development
activities have consisted principally of oil-related remediation, return to production and recompletion projects in California
and the optimization and streamlining of our natural gas gathering and compression facilities in Appalachia to provide more efficient
and lower cost operations and greater flexibility in moving our production to markets with more favorable pricing. Since closing
these acquisitions, we have focused on the reduction of operating expenses, optimization of natural gas gathering and compression
facilities and the identification of development project opportunities. In addition, since 2010, we have drilled 56 horizontal
wells in a Berea sandstone oil formation located in Eastern Kentucky, including two wells in 2017. We have enhanced our well performance,
improved well drilling and completion performance, including reduced drilling days, increased horizontal lateral length, decreased
cost per frac stage and reduced days from spud to first production. In addition, we have established an infrastructure of oil
and natural gas gathering and water handling and disposal facilities which will benefit the economics of future drilling.
As of June 30, 2018, we owned working
interests in approximately 3,200 gross wells (3,000 net) and royalty interests located in Kentucky, Ohio, Tennessee and West Virginia,
and had leasehold positions in approximately 189,000 net developed acres and approximately 221,000 net undeveloped acres. Approximately
68% of this acreage is held by production and of the remaining acreage, approximately 49% have lease terms of greater than five
years remaining in the primary term or contractual extension periods.
As of June 30, 2018, Carbon Appalachia owned working interests in approximately 5,200 gross wells
(4,800 net) located in Kentucky, Tennessee, Virginia and West Virginia, and had leasehold positions in approximately 851,000 net
developed acres and approximately 373,000 net undeveloped acres. Approximately 74% of this acreage is held by production and of
the remaining acreage, approximately 89% have lease terms of greater than five years remaining in the primary term or contractual
extension periods. As described below, as of December 31, 2017, our proportionate share in Carbon Appalachia was 27.24%. Effective
upon the Old Ironsides Buyout (which we intend to fund using proceeds from this offering), we will own 100% of Carbon Appalachia.
As of June 30, 2018, Carbon California
owned working interests in approximately 540 gross wells (340 net) located in California and had leasehold positions in approximately
5,000 net developed acres and approximately 11,800 net undeveloped acres. Approximately 100% of this acreage is held by production
or is fee mineral. As described below, as of December 31, 2017, our proportionate share in Carbon California was 17.81%, and beginning
on February 1, 2018, our proportionate share in Carbon California increased to 56.41%. As a result of the Seneca Acquisition on
May 1, 2018, our proportionate share in Carbon California decreased to 53.92%.
Our oil and natural gas assets contain
an inventory of multi-year proved developed non-producing properties with multiple potential future drilling locations which will
provide significant drilling and completion opportunities from multiple proven formations when oil and natural gas commodity prices
make such opportunities economical.
Recent Developments and Factors Affecting Comparability
We are continually evaluating producing
property and land acquisition opportunities in our operating areas, and engage from time to time in discussions with potential
sellers, which would expand our operations and provide attractive risk adjusted rates of return on invested capital. Assets acquired
in one or more of such transactions may have a material effect on our business, financial condition and results of operations.
The drilling of additional oil and natural gas wells is contingent on our expectation of future oil and natural gas prices.
Investment in Affiliates
Carbon Appalachia
Carbon Appalachia was formed in 2016 by
us, Yorktown and Old Ironsides to acquire producing assets in the Appalachian Basin in Kentucky, Tennessee, Virginia and West Virginia.
Substantial operations commenced in April 2017. Carbon Appalachia’s board of directors is composed of four members. We have
the right to appoint one member to the board of directors, and Patrick R. McDonald, our Chief Executive Officer, is our designee
to the board of directors.
We currently serve as the manager of
Carbon Appalachia and operate its day-to-day administration pursuant to the terms of the limited liability company agreement of
Carbon Appalachia and the management services agreement between Carbon Appalachia and us, subject to certain approval rights held
by the board of directors of Carbon Appalachia. Because Carbon Appalachia is managed by its governing board, our ability to influence
decisions with respect to acquisitions, capital calls or capital expenditures is limited.
Following the closing of this offering,
we expect to complete the Old Ironsides Buyout. Following the closing of the Old Ironsides Buyout, Carbon Appalachia will be our
wholly-owned subsidiary. Our obligation to consummate the Old Ironsides Buyout is conditioned on the completion of this offering.
In addition, the purchase agreement contains certain closing conditions and termination rights for each of Carbon and Old Ironsides
if the closing of the Old Ironsides Buyout has not occurred on or before October 15, 2018.
Our
Capital Contributions to Carbon Appalachia
Outlined
below is a summary of (i) our contributions to Carbon Appalachia since its formation, (ii) our resulting percent ownership of
Class A Units, which represents the voting interest in Carbon Appalachia, and (iii) our proportionate share in Carbon Appalachia
after giving effect of all classes of ownership interests. Each contribution is described in detail following the table.
Timing
|
|
Capital
Contribution
|
|
Resulting Class A
Units (%)
|
|
|
Proportionate Share
(%)
|
|
April 2017
|
|
$0.24 million
|
|
|
2.00
|
%
|
|
|
2.98
|
%
|
August 2017
|
|
$3.71 million
|
|
|
15.20
|
%
|
|
|
16.04
|
%
|
September 2017
|
|
$2.92 million
|
|
|
18.55
|
%
|
|
|
19.37
|
%
|
November 2017
|
|
Warrant exercise
|
|
|
26.50
|
%
|
|
|
27.24
|
%
|
In
connection with the entry into the Carbon Appalachia LLC Agreement, we acquired a 2.0% voting interest represented by Class A
Units of Carbon Appalachia in exchange for a capital contribution to Carbon Appalachia of $0.2 million, and we made a capital
commitment of $2.0 million to Carbon Appalachia. The aggregate capital commitments to Carbon Appalachia from all members was $100.0
million. We also received the right to earn up to an additional 20% of Carbon Appalachia distributions (represented by our ownership
of 100% of the issued and outstanding Class B Units of Carbon Appalachia) after certain return thresholds to the holders of Class
A Units are met. The Class B Units were acquired for no additional cash consideration. In addition, we acquired a 1.0% interest
represented by Class C Units of Carbon Appalachia in connection with the contribution to Carbon Appalachia of a portion of our
working interest in our undeveloped properties in Tennessee. If Carbon Appalachia drills wells on these properties, it will pay
100% of the cost of drilling and completion for the first 20 wells in exchange for a 75% working interest in such properties.
We, through our subsidiary, Nytis LLC, retain a 25% working interest in the properties.
Our
initial capital contribution to Carbon Appalachia constituted a portion of the purchase price for the CNX Acquisition.
On
April 3, 2017, we issued to Yorktown a warrant to purchase approximately 408,000 shares of our common stock at an exercise price
of $7.20 per share (the “
Appalachia Warrant
”). The exercise price for the Appalachia Warrant is payable
exclusively with Class A Units of Carbon Appalachia held by Yorktown, and the number of shares of our common stock for which the
Appalachia Warrant is exercisable is determined, as of the time of exercise, by dividing (a) the aggregate unreturned capital
of Yorktown’s Class A Units of Carbon Appalachia plus a 10% internal rate of return by (b) the exercise price. The Appalachia
Warrant had a term of seven years and included certain standard registration rights with respect to the shares of our common stock
issuable upon exercise of the Appalachia Warrant.
On
November 1, 2017, Yorktown exercised the Appalachia Warrant resulting in the issuance of 432,051 shares of our common stock in
exchange for Class A Units representing approximately 7.95% of then outstanding Class A Units of Carbon Appalachia. We accounted
for the exercise through extinguishment of the warrant liability associated with the Appalachia Warrant of approximately $1.9
million and the receipt of Yorktown’s Class A Units as an increase to investment in affiliates in the amount of approximately
$2.9 million. After giving effect to the exercise on November 1, 2017, we owned 26.5% of Carbon Appalachia’s outstanding
Class A Units, 100% of its Class B Units and 100% of its Class C Units.
The
issuance of the Class B Units and the Appalachia Warrant were in contemplation of each other, and under non-monetary related party
guidance, we accounted for the Appalachia Warrant, at issuance, based on the fair value of the Appalachia Warrant as of the date
of grant (April 3, 2017) and recorded a long-term warrant liability with an associated offset to Additional Paid in Capital (“
APIC
”).
Future changes to the fair value of the Appalachia Warrant are recognized in earnings. We accounted for the fair value of the
Class B Units at their estimated fair value at the date of grant, which became our investment in Carbon Appalachia with an offsetting
entry to APIC.
As
of the grant date of the Appalachia Warrant, we estimated that the fair market value of the Appalachia Warrant was approximately
$1.3 million and the fair value of the Class B Units was approximately $924,000. The difference in the fair value of the Appalachia
Warrant from the grant date through its exercise on November 1, 2017, was approximately $619,000 and was recognized in warrant
derivative gain in our consolidated statement of operations for the year ended December 31, 2017.
We use the HLBV method to determine
our share of profits or losses in Carbon Appalachia and adjust the carrying value of our investment accordingly. The HLBV method
is a balance-sheet approach that calculates the amount each member of an entity would receive if the entity were liquidated at
book value at the end of each measurement period. The change in the allocated amount to each member during the period represents
the income or loss allocated to that member. In the event of liquidation of Carbon Appalachia, available proceeds are first distributed
to holders of Class A and Class C units until their contributed capital is recovered with an internal rate of return of 10%. Any
additional distributions would then be shared between holders of Class A, Class B and Class C Units, with the Class A Units and
Class C Units sharing 80% of the proceeds pro rata and the Class B Units receiving 20% of the proceeds. For purposes of the HLBV,
our membership interest in Carbon Appalachia is represented by our approximate $6.9 million contributed capital. For the six months
ended June 30, 2018, Carbon Appalachia incurred a net gain, of which our share is approximately $917,000, and accordingly we recorded
this amount to investment in affiliates. Upon the successful completion of this offering and closing of the Old Ironsides Buyout,
Carbon Appalachia would become a wholly-owned subsidiary and would be consolidated for financial reporting purposes.
Carbon
California
Carbon
California was formed in 2016 by us, Yorktown and Prudential to acquire producing assets in the Ventura Basin in California. Substantial
operations commenced in February 2017. Carbon California’s board of directors is composed of five members. We have the right
to appoint one member to the board of directors, and Patrick R. McDonald, our Chief Executive Officer, is our designee.
We currently serve as the manager of
Carbon California and operate its day-to-day administration pursuant to the terms of the limited liability company agreement of
Carbon California and the management services agreement between Carbon California and us, subject to certain approval rights held
by the board of directors of Carbon California.
In
connection with the entry into the Carbon California LLC Agreement, and Carbon California engaging in the transactions described
above, we received Class B Units and issued to Yorktown a warrant to purchase approximately 1.5 million shares of our common stock
at an exercise price of $7.20 per share (the “
California Warrant
”). The exercise price for the California
Warrant is payable exclusively with Class A Units of Carbon California held by Yorktown and the number of shares of our common
stock for which the California Warrant is exercisable is determined, as of the time of exercise, by dividing (a) the aggregate
unreturned capital of Yorktown’s Class A Units of Carbon California by (b) the exercise price. The California Warrant had
a term of seven years and included certain standard registration rights with respect to the shares of our common stock issuable
upon exercise of the California Warrant. Yorktown exercised the California Warrant on February 1, 2018.
The
issuance of the Class B Units and the warrant were in contemplation of each other, and under non-monetary related party guidance,
we accounted for the California Warrant, at issuance, based on the fair value of the California Warrant as of the date of grant
(February 15, 2017) and recorded a long-term warrant liability with an associated offset to APIC. Future changes to the fair value
of the California Warrant are recognized in earnings. We accounted for the fair value of the Class B Units at their estimated
fair value at the date of grant, which became our investment in Carbon California with an offsetting entry to APIC.
As of the grant date of the California
Warrant, we estimated that the fair market value of the California Warrant was approximately $5.8 million and the fair value of
the Class B Units was approximately $1.9 million. As of December 31, 2017, we estimated that the fair value of the California
Warrant was approximately $2.0 million. The difference in the fair value of the California Warrant from the grant date through
December 31, 2017 was approximately $3.8 million and was recognized in warrant derivative gain in our consolidated statements
of operations for the year ended December 31, 2017. The difference in the fair value of the California Warrant from December 31,
2017 through its exercise on February 1, 2018, was approximately $225,000 and was recognized in warrant derivative gain in our
consolidated statement of operations for the six months ended June 30, 2018.
On
February 1, 2018, Yorktown exercised the California Warrant resulting in the issuance of 1,527,778 shares of our common stock
in exchange for Yorktown’s Class A Units of Carbon California representing approximately 46.96% of the outstanding Class
A Units of Carbon California and a profits interest of approximately 38.59%. After giving effect to the exercise on February 1,
2018 and the Seneca Acquisition on May 1, 2018, we own 53.92% of the voting and profits interests of Carbon California. At the
closing of this offering, Yorktown will own % of the outstanding shares of our common
stock, assuming the conversion of the Preferred Stock (described herein) to shares of our common stock.
Effective
February 1, 2018, Carbon California became consolidated for financial reporting purposes. From February 15, 2017 through January
31, 2018, Carbon California was treated as an equity method investment; therefore, we used the HLBV method to determine our share
of profits or losses in Carbon California and adjusted the carrying value of our investment accordingly. The HLBV method is a
balance-sheet approach that calculates the amount each member of an entity would receive if the entity were liquidated at book
value at the end of each measurement period. The change in the allocated amount to each member during the period represents the
income or loss allocated to that member. In the event of liquidation of Carbon California, to the extent that Carbon California
has net income, available proceeds are first distributed to members holding Class A and Class B Units and any remaining proceeds
are then distributed to members holding Class A units. From the commencement of substantial operations on February 15, 2017 through
January 31, 2018, Carbon California incurred a net loss, of which our share (as a holder of Class B units for that period) is
zero.
Recent
Acquisitions
Historically, we have made acquisitions
through Nytis LLC, Carbon California or Carbon Appalachia, including numerous acquisitions during 2017 and 2018. For acquisitions
by Carbon California or Carbon Appalachia, we typically contribute a portion of the purchase price based on our ownership interest
to fund such acquisitions. In 2018, 2017 and 2016, we contributed an aggregate of $23.9 million to Carbon Appalachia, Carbon California
and Nytis LLC in connection with our acquisition activities. While Carbon Appalachia and Carbon California made other insignificant
acquisitions that are not specifically listed, the acquisitions described below most meaningfully affect the financial condition
of Carbon Appalachia and Carbon California, and, therefore, us. See “
—Acquisition and Divestiture Activities
”
for more information about our acquisitions and divestitures.
|
●
|
On
July 11, 2018, Nytis USA signed a Purchase and Sale Agreement to acquire 54 operated oil and gas wells covering approximately
55,000 gross acres (22,000 net), the associated mineral interests, and gas wells and associated facilities in the Appalachian
Basin for a purchase price of $3.0 million, subject to customary and standard purchase price adjustments (the “
Liberty
Acquisition
”). We contributed the full amount of the purchase price to Nytis USA to fund the purchase price.
The Liberty Acquisition closed on July 11, 2018 with an effective date as of January 1, 2018. The Liberty Acquisition is not
reflected in our pro forma financial statements.
|
|
●
|
In
October 2017, Carbon California signed a Purchase and Sale Agreement to acquire 309 operated and 1 non-operated oil wells
covering approximately 6,800 gross acres (6,500 net), and fee interests in and to certain lands, situated in the Ventura Basin,
together with associated wells, pipelines, facilities, equipment and other property rights for a purchase price of $43.0 million,
subject to customary and standard purchase price adjustments, from Seneca Resources Corporation (the “
Seneca Acquisition
”).
We contributed approximately $5.0 million to Carbon California to fund our portion of the purchase price, with the remainder
funded by Prudential and debt. We raised our $5.0 million through the issuance of 50,000 shares of Preferred Stock to Yorktown.
Upon the completion of this offering, the Preferred Stock will automatically convert into shares of common stock. The conversion
ratio at which the Preferred Stock will convert into common stock is equal to an amount per share of $100 plus all accrued
but unpaid dividends payable in respect thereof (together, the “
Liquidation Preference
”) divided
by the greater of (i) $8.00 per share or (ii) the price that is 15% less than the price per share of shares sold to the public
in this offering. See “
Description of Capital Stock—Preferred Stock
” for more information
on the terms of our Preferred Stock. The Seneca Acquisition closed on May 2018 with an effective date as of October 1, 2017.
|
|
●
|
In
September 2017, but effective as of April 1, 2017 for oil and gas assets and September 29, 2017 for the corporate entity,
a wholly-owned subsidiary of Carbon Appalachia acquired certain oil and gas assets, including associated mineral interests,
certain gathering system assets, associated vehicles and equipment, and all of the outstanding shares of Cranberry Pipeline
Corporation, a Delaware corporation (“
Cranberry Pipeline
”), for a purchase price of $41.3 million
from Cabot Oil & Gas Corporation (the “
Cabot Acquisition
”). We contributed approximately $2.9
million to Carbon Appalachia to fund this acquisition. Cranberry Pipeline operates certain pipeline assets.
|
|
●
|
In
August 2017, but effective as of May 1, 2017, a wholly-owned subsidiary of Carbon Appalachia acquired 865 oil and gas leases
on approximately 320,300 acres, the associated mineral interests, and gas wells and associated facilities in the Appalachian
Basin for a purchase price of approximately $21.5 million from EnerVest Energy Institutional Fund XII-A, L.P., EnerVest Energy
Institutional Fund XII-WIB, L.P., EnerVest Energy Institutional Fund XII-WIC, L.P. and EnerVest Operating, L.L.C. (the “
EnerVest
Acquisition
”). We contributed approximately $3.7 million to Carbon Appalachia to fund this acquisition.
|
|
●
|
In
April 2017, but effective as of February 1, 2017 for oil and gas assets and April 3, 2017 for the corporate entity, a wholly-owned
subsidiary of Carbon Appalachia acquired all of the issued and outstanding shares of Coalfield Pipeline Company, a Tennessee
corporation (“
Coalfield Pipeline
”), and all of the membership interest in Knox Energy, LLC, a Tennessee
limited liability company (“
Knox Energy
”), for a purchase price of $20.0 million from CNX Gas Company,
LLC (the “
CNX Acquisition
”). We contributed approximately $0.2 million to Carbon Appalachia to fund
this acquisition. Coalfield Pipeline and Knox Energy operate certain pipeline assets and 203 oil and gas leases on approximately
142,600 acres and own the associated mineral interests and vehicles and equipment.
|
|
●
|
In
February 2017, but effective as of January 1, 2017, Carbon California acquired 43 oil wells on approximately 1,400 gross acres
(1,400 net), the associated mineral interests and gas wells and vehicles and equipment in the Ventura Basin for a purchase
price of approximately $4.5 million from Mirada Petroleum, Inc. (the “
Mirada Acquisition
”). We were
not required to contribute any cash to Carbon California to fund this acquisition.
|
|
●
|
In
February 2017, but effective as of November 1, 2016, Carbon California acquired 191 oil wells on approximately 8,900 gross
acres (8,900 net), the associated mineral interests, oil and gas wells and associated facilities, a field office building,
land and vehicles and equipment in the Ventura Basin for a purchase price of $34.0 million from California Resources Petroleum
Corporation and California Resources Production Corporation (the “
CRC Acquisition
”). We were not
required to contribute any cash to Carbon California to fund this acquisition.
|
As
a result of our recent acquisitions and the Pro Forma Adjustments, our historical operating, financial and reserve data may not
be comparable between periods or with the pro forma operating, financial and reserve data presented in this prospectus. See “
Risk
Factors—Risks Related to Our Business—We have made several significant acquisitions in recent years, and our proportionate
interests in our equity investees have recently increased or is expected to increase upon the closing of this offering. As a result,
our historical reserve, operating and financial data are not comparable from period to period or to the unaudited pro forma reserve,
operating financial information included in this prospectus, which may make it more difficult for you to evaluate our business
or our ability to pay dividends.
”
Reverse
Stock Split
Our stockholders and board of directors
approved a reverse stock split of our common stock, effective March 15, 2017, pursuant to which every 20 shares of issued and
outstanding common stock became one share of common stock and no fractional shares were issued. All references to the number of
shares of common stock and per share amounts give retroactive effect to the reverse stock split for all periods presented. In
connection with the reverse stock split, the number of authorized shares decreased from 200,000,000 to 10,000,000. On June 1,
2018, we increased the number of authorized shares of our common stock from 10,000,000 to 35,000,000.
Preferred
Stock Issuance to Yorktown
In connection with the closing of the
Seneca Acquisition, we raised $5.0 million through the issuance of 50,000 shares of Preferred Stock to Yorktown. Upon the completion
of this offering, the Preferred Stock will automatically convert into shares of common stock. The conversion ratio at which the
Preferred Stock will convert into common stock is equal to the Liquidation Preference divided by the greater of (i) $8.00 per
share or (ii) the price that is 15% less than the price per share of shares sold to the public in this offering. See “
Description
of Capital Stock—Preferred Stock
” for more information on the terms of our preferred stock.
How
We Evaluate Our Operations
In
evaluating our financial results, we focus on the mix of our revenues from oil, natural gas, and NGLs, the average realized price
from sales of our production, our production margins, and our capital expenditures.
We
also evaluate our rates of return on invested capital in our wells. We believe the quality of our assets combined with the technical
capabilities of our management team can generate attractive rates of return as we develop our extensive resource base. Additionally,
by focusing on concentrated acreage positions, we can build and own centralized production infrastructure, which enable us to
reduce reliance on outside service companies, minimize costs, and increase our returns.
Principal
Components of Our Cost Structure
|
●
|
Lease
operating expenses.
These are costs incurred to bring oil and natural gas out of the ground and to market, together with
the costs incurred to maintain our producing properties. Such costs include maintenance, repairs and workover expenses related
to our oil and natural gas properties.
|
|
●
|
Transportation
and gathering costs.
Transportation and gathering costs are incurred to bring oil and natural gas to market. Gathering
refers to using groups of small pipelines to move the oil and natural gas from several wells into a major pipeline, or in
case of oil, into a tank battery.
|
|
●
|
Production
and property taxes.
Production taxes consist of severance and property taxes and are paid on oil and natural
gas produced based on a percentage of market prices or at fixed rates established by federal, state or local taxing authorities.
|
|
●
|
Depreciation,
amortization and impairment
. We use the full cost method of accounting for oil and gas properties. All costs incidental
to the acquisition, exploration and development of oil and gas properties, including costs of undeveloped leasehold, dry holes
and leasehold equipment, are capitalized. We perform a quarterly ceiling test. The full cost ceiling test is a limitation
on capitalized costs prescribed by the SEC. The ceiling test is not a fair value-based measurement; rather, it is a standardized
mathematical calculation that compares the net capitalized costs of our full cost pool to estimated discounted cash flows.
Should the net capitalized cost exceed the sum of the estimated discounted cash flows, a ceiling test write-down would be
recognized to the extent of the excess.
|
We perform our ceiling tests
based on average first-of-the-month prices during the twelve-month period prior to the reporting date. For the year ended December
31, 2017 and the six months ended June 30, 2018, we did not incur a ceiling test impairment. During the year ended December 31,
2016, we incurred ceiling test impairments of approximately $4.3 million. During the six months ended June 30, 2018, we did not
recognize a ceiling test impairment.
|
●
|
Depletion.
Depletion is calculated using capitalized costs in the full cost pool, including estimated asset retirement costs and
estimated future expenditures to be incurred in developing proved reserves, net of estimated salvage values and depleted based
on a unit-of-production method.
|
|
●
|
General
and administrative expense.
These costs include payroll and benefits for our corporate staff, non-cash stock-based
compensation, costs of maintaining our offices, costs of managing our production, development and acquisition operations,
franchise taxes, audit, tax, legal and other professional fees and legal compliance. Certain of these costs are recovered
as management reimbursements in place with Carbon California and Carbon Appalachia.
|
|
●
|
Interest
expense.
We finance a portion of our working capital requirements for drilling and completion activities and
acquisitions with borrowings under our credit facilities. As a result, we incur interest expense that is affected by both
fluctuations in interest rates and our financing decisions.
|
|
●
|
Income
tax expense.
We are subject to state and federal income taxes but typically have not been in a tax paying position
for regular federal income taxes, primarily due to the current deductibility of intangible drilling costs (“
IDC
”)
and net operating loss (“
NOL
”) carryforwards. We pay alternative minimum tax, state income or franchise
taxes where IDC or NOL deductions do not exceed taxable income or where state income or franchise taxes are determined on
another basis. As of December 31, 2017, we had NOL carryforwards of approximately $21.2 million available to reduce future
years’ federal taxable income. The federal NOLs begin to expire in 2032. As of December 31, 2017, we had various state
NOL carryforwards available to reduce future years’ state taxable income, which are dependent on apportionment percentages
and state laws that can change from year to year and impact the amount of such carryforwards. These state NOL carryforwards
will expire in the future based upon each jurisdiction’s specific law surrounding NOL carry forwards. We believe we
will experience an “ownership change” (as determined under Section 382) as a result of this offering. This will
subject our ability to utilize federal NOLs existing at the time of such ownership change to limitation, which may cause U.S.
federal income taxes to be paid earlier than they otherwise would be paid if such limitation were not in effect and could
cause such NOLs to expire unused, in each case reducing or eliminating the benefit of such NOLs. See “
Risk Factors—Risks
Related to Our Business—Our ability to use net operating loss carryforwards to offset future taxable income for U.S.
federal income tax purposes is subject to limitation
” for more information regarding this limitation.
|
On December 22, 2017, the TCJA was enacted.
The TCJA significantly changes the U.S. corporate tax law by, among other things, lowering the U.S. corporate income tax rate
from 35% to 21% beginning in January 2018. FASB ASC Topic 740, Income Taxes, requires companies to recognize the impact of the
changes in tax law in the period of enactment. See “
Risk Factors—Risks Related to Our Business—Recently
enacted tax legislation may impact our ability to fully utilize our interest expense deductions and net operating loss carryovers
to fully offset our taxable income in future periods
” for more information on the TCJA.
Amounts recorded during the year ended
December 31, 2017 and the six months ended June 30, 2018, related to the TCJA principally relate to the reduction in the U.S.
corporate income tax rate to 21%, which resulted in (i) income tax expense of approximately $6.0 million from the revaluation
of our deferred tax assets and liabilities as of the date of enactment allowance as well as (ii) an income tax benefit totaling
$74,000 related to a reduction in our existing valuation allowances relating to refundable Alternative Minimum Tax credits. Reasonable
estimates were made based on our analysis of the remeasurement of its deferred tax assets and liabilities and valuation allowances
under tax reform. These provisional amounts may be adjusted in future periods if additional information is obtained or further
clarification and guidance is issued by regulatory authorities regarding the application of the law.
Other
provisions of the TCJA that may impact income taxes in future years include (i) a limitation on the current deductibility of net
interest expense in excess of 30% of adjusted taxable income, (ii) a limitation on the usage of NOLs generated after 2017 to 80%
of taxable income, (iii) the inclusion of performance based compensation in determining the excessive compensation limitation,
and (iv) the unlimited carryforward of NOLs.
Factors
Affecting Our Business and Outlook
The
price we receive for our oil, natural gas and NGL production heavily influences our revenue, profitability, access to capital
and future rate of growth. Our revenues, cash flow from operations, and future growth depend substantially on factors beyond our
control, such as economic, political, and regulatory developments and competition from other sources of energy. Oil, natural gas
and NGLs are commodities, and therefore, their prices are subject to wide fluctuations in response to relatively minor changes
in supply and demand. Sustained periods of low prices for oil, natural gas, or NGLs could materially and adversely affect our
financial condition, our results of operations, the quantities of oil and natural gas that we can economically produce, and our
ability to access capital.
We
use commodity derivative instruments, such as swaps and collars, to manage and reduce price volatility and other market risks
associated with our production. These arrangements are structured to reduce our exposure to commodity price decreases, but they
can also limit the benefit we might otherwise receive from commodity price increases. We do not apply hedge accounting, and therefore
designate our current portfolio of commodity derivative contracts as hedges for accounting purposes and all changes in commodity
derivative fair values are immediately recorded to earnings.
Like
all businesses engaged in the exploration and production of oil and natural gas, we face the challenge of natural production declines.
As initial reservoir pressures are depleted, oil and natural gas production from a given well naturally decreases. Thus, an oil
and natural gas exploration and production company depletes part of its asset base with each unit of oil or natural gas it produces.
We attempt to overcome this natural decline by acquiring more reserves than we produce or drilling to find additional reserves.
Our future growth will depend on our ability to continue to acquire reserves in a cost-effective manner and enhance production
levels from our existing reserves. Our ability to continue to acquire reserves and to add reserves through drilling is dependent
on our capital resources and can be limited by many factors, including our ability to access capital in a cost-effective manner
and to timely obtain drilling permits and regulatory approvals.
As
with our historical acquisitions, any future acquisitions could have a substantial impact on our financial condition and results
of operations. In addition, funding future acquisitions may require us to incur additional indebtedness or issue additional equity.
Results
of Operations
The following
tables set forth for the periods presented our selected historical statements of operations and production data and do not include
results of operations from Carbon Appalachia for the six months ended June 30, 2018 or from Carbon Appalachia or Carbon California
for the six months ended June 30, 2017 or the years ended December 31, 2017 and 2016.
|
|
Six Months Ended
|
|
|
|
|
|
|
June 30,
|
|
|
Percent
|
|
(in thousands except production and per unit data)
|
|
2018
|
|
|
2017
|
|
|
Change
|
|
Revenue:
|
|
|
|
|
|
|
|
|
|
Natural gas sales
|
|
$
|
7,462
|
|
|
$
|
8,017
|
|
|
|
(7
|
%)
|
Natural gas liquids sales
|
|
|
713
|
|
|
|
-
|
|
|
|
*
|
|
Oil sales
|
|
|
11,074
|
|
|
|
2,192
|
|
|
|
405
|
%
|
Commodity derivative (loss) gain
|
|
|
(6,647
|
)
|
|
|
3,141
|
|
|
|
*
|
|
Other income
|
|
|
19
|
|
|
|
20
|
|
|
|
(5
|
%)
|
Total revenues
|
|
|
12,621
|
|
|
|
13,370
|
|
|
|
(6
|
%)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expenses
|
|
|
6,058
|
|
|
|
2,706
|
|
|
|
124
|
%
|
Transportation costs
|
|
|
2,353
|
|
|
|
1,015
|
|
|
|
132
|
%
|
Production and property taxes
|
|
|
1,048
|
|
|
|
855
|
|
|
|
23
|
%
|
General and administrative
|
|
|
5,491
|
|
|
|
3,494
|
|
|
|
57
|
%
|
General and administrative - related party reimbursement
|
|
|
(2,213
|
)
|
|
|
(300
|
)
|
|
|
637
|
%
|
Depreciation, depletion and amortization
|
|
|
3,471
|
|
|
|
1,234
|
|
|
|
181
|
%
|
Accretion of asset retirement obligations
|
|
|
303
|
|
|
|
155
|
|
|
|
96
|
%
|
Total expenses
|
|
|
16,511
|
|
|
|
9,159
|
|
|
|
80
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income (loss)
|
|
$
|
(3,890
|
)
|
|
$
|
4,211
|
|
|
|
*
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other income and (expense):
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense
|
|
|
(2,203
|
)
|
|
|
(522
|
)
|
|
|
(322
|
%)
|
Warrant derivative gain
|
|
|
225
|
|
|
|
1,683
|
|
|
|
(87
|
%)
|
Gain on derecognized equity investments in affiliate-Carbon California
|
|
|
5,390
|
|
|
|
-
|
|
|
|
*
|
|
Equity investment income (loss)
|
|
|
962
|
|
|
|
-
|
|
|
|
*
|
|
Total other income (expense)
|
|
$
|
4,374
|
|
|
$
|
1,161
|
|
|
|
277
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production data:
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas (Mcf)
|
|
|
2,848,528
|
|
|
|
2,359,995
|
|
|
|
21
|
%
|
Oil (Bbl)
|
|
|
159,879
|
|
|
|
45,111
|
|
|
|
256
|
%
|
Natural gas liquids (Bbl)
|
|
|
18,399
|
|
|
|
-
|
|
|
|
*
|
|
Combined (Mcfe)
|
|
|
3,918,196
|
|
|
|
2,627,661
|
|
|
|
49
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average prices before effects of hedges:
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas (per Mcf)
|
|
$
|
2.62
|
|
|
$
|
3.40
|
|
|
|
(23
|
%)
|
Oil (per Bbl)
|
|
$
|
69.26
|
|
|
$
|
48.59
|
|
|
|
42
|
%
|
Natural gas liquids (per Bbl)
|
|
$
|
38.70
|
|
|
|
-
|
|
|
|
*
|
|
Combined (per Mcfe)
|
|
$
|
4.91
|
|
|
$
|
3.89
|
|
|
|
21
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average prices after effects of hedges**:
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas (per Mcf)
|
|
$
|
2.62
|
|
|
$
|
4.27
|
|
|
|
(37
|
%)
|
Oil and (per Bbl)
|
|
$
|
69.26
|
|
|
$
|
73.09
|
|
|
|
(17
|
%)
|
Natural gas liquids (per Bbl)
|
|
$
|
38.70
|
|
|
$
|
-
|
|
|
|
*
|
|
Combined (per Mcfe)
|
|
$
|
4.91
|
|
|
$
|
5.08
|
|
|
|
(12
|
%)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average costs (per Mcfe):
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expenses
|
|
$
|
1.55
|
|
|
$
|
1.03
|
|
|
|
50
|
%
|
Transportation costs
|
|
$
|
0.60
|
|
|
$
|
0.39
|
|
|
|
54
|
%
|
Production and property taxes
|
|
$
|
0.27
|
|
|
$
|
0.33
|
|
|
|
(18
|
%)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash-based general and administrative expense, net of related party reimbursement
|
|
$
|
0.71
|
|
|
$
|
1.01
|
|
|
|
15
|
%
|
Depreciation, depletion and amortization
|
|
$
|
0.89
|
|
|
$
|
0.47
|
|
|
|
87
|
%
|
*
|
Not
meaningful or applicable
|
**
|
Includes
realized and unrealized commodity derivative gains and losses
|
|
|
Twelve Months Ended
|
|
|
|
|
|
|
December 31,
|
|
|
Percent
|
|
(in thousands except per unit data)
|
|
2017
|
|
|
2016
|
|
|
Change
|
|
Revenue:
|
|
|
|
|
|
|
|
|
|
Natural gas sales
|
|
$
|
15,298
|
|
|
$
|
7,127
|
|
|
|
115
|
%
|
Oil sales
|
|
|
4,213
|
|
|
|
3,316
|
|
|
|
27
|
%
|
Commodity derivative gain (loss)
|
|
|
2,928
|
|
|
|
(2,259
|
)
|
|
|
*
|
|
Other income
|
|
|
34
|
|
|
|
11
|
|
|
|
209
|
%
|
Total revenues
|
|
|
22,473
|
|
|
|
8,195
|
|
|
|
174
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expenses
|
|
|
6,141
|
|
|
|
3,175
|
|
|
|
93
|
%
|
Transportation costs
|
|
|
2,172
|
|
|
|
1,645
|
|
|
|
32
|
%
|
Production and property taxes
|
|
|
1,276
|
|
|
|
820
|
|
|
|
56
|
%
|
General and administrative
|
|
|
9,528
|
|
|
|
8,645
|
|
|
|
10
|
%
|
General and administrative-related party reimbursement
|
|
|
(2,703
|
)
|
|
|
-
|
|
|
|
*
|
|
Depreciation, depletion and amortization
|
|
|
2,544
|
|
|
|
1,953
|
|
|
|
30
|
%
|
Accretion of asset retirement obligations
|
|
|
307
|
|
|
|
176
|
|
|
|
74
|
%
|
Impairment of oil and gas properties
|
|
|
-
|
|
|
|
4,299
|
|
|
|
*
|
|
Total expenses
|
|
|
19,265
|
|
|
|
20,713
|
|
|
|
(7
|
)%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income (loss)
|
|
$
|
3,208
|
|
|
$
|
(12,518
|
)
|
|
|
(126
|
)%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other income and (expense):
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense, net
|
|
$
|
(1,202
|
)
|
|
$
|
(367
|
)
|
|
|
228
|
%
|
Warrant derivative gain
|
|
|
3,133
|
|
|
|
-
|
|
|
|
*
|
|
Investment in affiliates
|
|
|
1,158
|
|
|
|
49
|
|
|
|
2,263
|
%
|
Other income
|
|
|
28
|
|
|
|
17
|
|
|
|
65
|
%
|
Total other income (expense)
|
|
$
|
3,117
|
|
|
$
|
(301
|
)
|
|
|
*
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production data:
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas (MMcf)
|
|
|
4,895
|
|
|
|
2,823
|
|
|
|
73
|
%
|
Oil and liquids (MBbl)
|
|
|
86
|
|
|
|
79
|
|
|
|
9
|
%
|
Combined (MMcfe)
|
|
|
5,414
|
|
|
|
3,297
|
|
|
|
64
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average prices before effects of hedges:
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas (per Mcf)
|
|
$
|
3.13
|
|
|
$
|
2.53
|
|
|
|
24
|
%
|
Oil and liquids (per Bbl)
|
|
$
|
48.99
|
|
|
$
|
41.97
|
|
|
|
17
|
%
|
Combined (per Mcfe)
|
|
$
|
3.60
|
|
|
$
|
3.17
|
|
|
|
14
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average prices after effects of hedges**:
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas (per Mcf)
|
|
$
|
3.72
|
|
|
$
|
1.89
|
|
|
|
97
|
%
|
Oil and liquids (per Bbl)
|
|
$
|
48.83
|
|
|
$
|
36.14
|
|
|
|
35
|
%
|
Combined (per Mcfe)
|
|
$
|
4.15
|
|
|
$
|
2.48
|
|
|
|
67
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average costs (per Mcfe):
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expenses
|
|
$
|
1.13
|
|
|
$
|
0.96
|
|
|
|
18
|
%
|
Transportation costs
|
|
$
|
0.40
|
|
|
$
|
0.50
|
|
|
|
(20
|
)%
|
Production and property taxes
|
|
$
|
0.24
|
|
|
$
|
0.25
|
|
|
|
(4
|
)%
|
Depreciation, depletion and amortization
|
|
$
|
0.47
|
|
|
$
|
0.59
|
|
|
|
(20
|
)%
|
|
*
|
Not
meaningful or applicable
|
|
**
|
Includes
realized and unrealized commodity derivative gains and losses
|
Six Months Ended June 30, 2018 Compared
to Six Months Ended June 30, 2017
Oil, natural gas, natural
gas liquids sales
- Revenues from sales of oil, natural gas and natural gas liquids increased approximately 89% to
approximately $19.2 million for the six months ended June 30, 2018 from approximately $10.2 million for the six months ended
June 30, 2017. This increase was primarily due to the consolidation of Carbon California on February 1, 2018 which
contributed approximately $9.7 million in oil, natural gas, and natural gas liquids sales.
Commodity derivative gains and
losses
- To achieve more predictable cash flows and to reduce our exposure to downward price fluctuations, we enter into
derivative contracts using fixed price swap contracts and costless collars. Because we do not designate these derivatives as cash
flow hedges, they do not receive hedge accounting treatment and all mark-to-market gains or losses, as well as settlement gains
or losses on the derivative instruments, are currently recognized in our results of operations. The unrealized gains and losses
represent the changes in the fair value of these contracts as oil and natural gas futures prices fluctuate relative to the fixed
price we will receive from these contracts. For the six months ended June 30, 2018 and 2017, we had commodity derivative losses
of approximately $6.6 million and gains of approximately $3.1 million, respectively.
Lease operating expenses
-
Lease operating expenses for the six months ended June 30, 2018 increased approximately 124% compared to the six months ended
June 30, 2017. This increase is primarily attributable to the consolidation of Carbon California. On a per Mcfe basis, lease operating
expenses increased from $1.03 per Mcfe for the six months ended June 30, 2017 to $1.54 per Mcfe for the six months ended June
30, 2018. This increase was primarily attributable to the consolidation of Carbon California, which is comprised of oil properties
that have higher lease operating expenses per unit of production compared to Carbon’s Appalachian based production that
is primarily comprised of natural gas properties.
Transportation costs
-
Transportation costs for the six months ended June 30, 2018 increased approximately 132% compared to the six months ended June
30, 2017. This increase is attributable to an increase in production as a result of the consolidation of Carbon California which
occurred on February 1, 2018. On a per Mcfe basis, these expenses increased from $0.39 per Mcfe for the six months ended June
30, 2017, to $0.60 per Mcfe for the six months ended June 30, 2018. The increase on a per Mcfe basis is primarily due to higher
transportation and processing costs per unit for the Carbon California properties as compared to our Appalachia properties.
Production and property taxes
-
Production and property taxes increased from approximately $855,000 for the six months ended June 30, 2017 to approximately $1.0
million for the six months ended June 30, 2018. This increase is primarily attributable to the consolidation of Carbon California
as of February 1, 2018. Production and property taxes were $0.27 and $0.33 per Mcfe for the six months ended June 30, 2018 and
2017, respectively. Production taxes averaged approximately 5.2% and 4.5% of oil and natural gas sales for the six months ended
June 30, 2018 and 2017, respectively. Ad valorem tax rates, which can fluctuate by year, are determined by individual counties
where we have production and are assessed on our sales one or two years in arrears depending on the location of the production.
Depreciation, depletion and amortization
(DD&A)
- DD&A increased from approximately $1.2 million for the six months ended June 30, 2017 to approximately
$3.5 million for the six months ended June 30, 2018, primarily due to an increase in oil and natural gas production. On a per
Mcfe basis, DD&A increased from $0.47 per Mcfe for the six months ended June 30, 2017 to $0.88 per Mcfe for the six months
ended June 30, 2018. The increase in depletion rate is primarily attributable to the consolidation of Carbon California in the
first quarter of 2018 which increased our blended depletion rate.
General and administrative expenses
-
Cash-based general and administrative expenses, net of related party reimbursement, increased from approximately $2.7 million
for the six months ended June 30, 2017, to approximately $2.8 million for the six months ended June 30, 2018. Non-cash stock-based
compensation and other general and administrative expenses for the six months ended June 30, 2018 and 2017 are summarized in the
following table:
General and administrative expenses
|
|
Six Months Ended
June
30,
|
|
|
Increase /
|
|
(in thousands)
|
|
2018
|
|
|
2017
|
|
|
(Decrease)
|
|
|
|
|
|
|
|
|
|
|
|
Stock-based compensation
|
|
$
|
483
|
|
|
$
|
539
|
|
|
$
|
(56
|
)
|
Other general and administrative expenses
|
|
|
5,008
|
|
|
|
2,955
|
|
|
|
2,053
|
|
General and administrative - related party reimbursement
|
|
|
(2,213
|
)
|
|
|
(300
|
)
|
|
|
(1,913
|
)
|
General and administrative expense, net
|
|
$
|
3,278
|
|
|
$
|
3,194
|
|
|
$
|
84
|
|
Interest expense
-
Interest expense increased from approximately $522,000 for the six months ended June 30, 2017, to approximately $2.2 million
for the six months ended June 30, 2018, primarily due to the consolidation of Carbon California on February 1, 2018, higher interest
rates on our Existing Credit Facility and higher debt balances on our Existing Credit Facility for the three months ended June
30, 2018 compared to the same period in 2017.
2017
Compared to 2016
Oil
and natural gas sales
- Revenues from sales of oil and natural gas increased 87% to approximately $19.5 million for the
year ended December 31, 2017 from approximately $10.4 million for the year ended December 31, 2016. Oil revenues for the year
ended December 31, 2017 increased 27% compared to the year ended December 31, 2016, primarily due to a 16% increase in oil prices
and a 9% increase in oil production. Natural gas revenues in the year ended December 31, 2017 increased 115% over the same period
in 2016 primarily due to an increase in gas production of 73% and a 23% in natural gas prices. The increases in production were
primarily attributable to properties acquired in the EXCO Acquisition, which occurred in the fourth quarter of 2016.
Commodity
derivative gains (loss)
- To achieve more predictable cash flows and to reduce our exposure to downward price fluctuations,
we enter into derivative contracts using fixed price swap contracts and costless collars. Because we do not designate these derivatives
as cash flow hedges, they do not receive hedge accounting treatment and all mark-to-market gains or losses, as well as settlement
gains or losses on the derivative instruments, are currently recognized in our results of operations. The unrealized gains and
losses represent the changes in the fair value of these contracts as oil and natural gas futures prices fluctuate relative to
the fixed price we will receive from these contracts. For the years ended December 31, 2017 and 2016, we had commodity derivative
gains of approximately $2.9 million and losses of approximately $2.3 million, respectively.
Lease operating expenses
-
Lease operating expenses for the year ended December 31, 2017 increased 93% compared to the year ended December 31, 2016. This
increase is principally attributable to the acquisition of properties acquired in the EXCO Acquisition. On a per Mcfe basis, lease
operating expenses increased from $0.96 per Mcfe for the year ended December 31, 2016 to $1.13 per Mcfe, for the year ended December
31, 2017. This increase was primarily attributable to decrease in personnel related costs during 2016 attributable to cost reduction
measures (including wage freezes, preventative maintenance operations only and vendor negotiations) implemented by us in response
to lower commodity prices.
Transportation and gathering
costs
- Transportation and gathering costs increased by 32% from the year ended December 31, 2016 to the year ended December
31, 2017, primarily attributable to the increased production as a result of the properties acquired in the EXCO Acquisition. On
a per Mcfe basis, transportation costs decreased from $0.50 per Mcfe for the year ended December 31, 2016 to $0.40 per Mcfe for
the year ended December 31, 2017 primarily due to lower transportation costs per unit for the property acquired in the EXCO Acquisition
compared to our other natural gas properties.
Production and property taxes
-
Production and property taxes increased 56% from approximately $820,000 for the year ended December 31, 2016 to approximately
$1.3 million for the year ended December 31, 2017. This increase is primarily attributable to increased oil and natural gas sales
as a result of property acquired in the EXCO Acquisition. Production taxes average approximately 4.1% and 4.0% of oil and natural
gas sales for the year ended December 31, 2017 and 2016, respectively. Property taxes rates, which can fluctuate by year, are
determined by individual counties where we have production and are assessed on our oil and natural gas revenues one or two years
in arrears depending upon the location of the production.
Depreciation, depletion and amortization
(“DD&A”)
- DD&A increased from approximately $2.0 million for the year ended December 31, 2016 to approximately
$2.5 million for the year ended December 31, 2017 primarily due to increased oil and natural gas production, offset, in part,
by a decrease in the depletion rate. The decrease in the depletion rate is primarily attributable to the properties acquired in
the EXCO Acquisition which reduced our blended depletion rate. On a per Mcfe basis, DD&A decreased from $0.59 per Mcfe for
the year ended December 31, 2016 to $0.47 per Mcfe for the year ended December 31, 2017.
Impairment of oil and gas properties-
Due to lower commodity prices in 2016, we had impairment expenses of approximately $4.3 million for the year ended December
31, 2016. We did not record an impairment for the year ended December 31, 2017. The ceiling limitation calculation is not intended
to be indicative of the fair market value of our proved reserves or future results. Impairment charges do not affect cash flow
from operating activities but do adversely affect our net income and various components of our balance sheet. Any recorded impairment
is not reversible at a later date.
General and administrative expenses
-
Cash-based general and administrative expenses increased from approximately $6.2 million for the year ended December 31, 2016
to approximately $8.4 million for the year ended December 31, 2017. The increase was primarily attributable to personnel-related
and other costs associated in connection with our role as manager of Carbon Appalachia and Carbon California and decreases in
personnel related costs during the year ended December 31, 2016 attributable to cost reduction measures implemented by us as response
to low commodity prices. This increase was offset by reimbursements of approximately $2.7 million received from Carbon Appalachia
and Carbon California in connection with our role as manager of them. Non-cash-based compensation decreased from approximately
$2.4 million for the year ended December 31, 2016 to approximately $1.1 million for the year ended December 31, 2017. We estimated
that it was probable that certain of the performance units granted in 2014 and 2015 would vest and compensation costs of approximately
$442,000 and $1.1 million related to those performance units were recognized for the year ended December 31, 2017 and 2016. Non-cash
stock-based compensation and other general and administrative expenses and related party reimbursements for the years ended December
31, 2017 and 2016 are summarized in the following table:
General and administrative expenses
|
|
Year Ended December 31,
|
|
|
Increase /
|
|
(in thousands)
|
|
2017
|
|
|
2016
|
|
|
(Decrease)
|
|
|
|
|
|
|
|
|
|
|
|
Stock-based compensation
|
|
$
|
1,106
|
|
|
$
|
2,440
|
|
|
$
|
(1,334
|
)
|
Cash-based general and administrative expenses
|
|
|
8,422
|
|
|
|
6,205
|
|
|
|
2,217
|
|
Related party reimbursements
|
|
|
(2,703
|
)
|
|
|
-
|
|
|
|
(2,703
|
)
|
Total general and administrative expenses, net
of related party reimbursement
|
|
$
|
6,825
|
|
|
$
|
8,645
|
|
|
$
|
(1,820
|
)
|
Interest
expense
- Interest expense increased from approximately $367,000 for the year ended December 31, 2016 to approximately
$1.2 million for the year ended December 31, 2017 primarily due to higher outstanding debt balances related to borrowings (i)
to complete the EXCO Acquisition and (ii) to fund our share of 2017 acquisitions in Carbon Appalachia. In addition, our effective
interest rate was higher in 2017 as compared to 2016.
Carbon
Appalachia
The
following table sets forth selected historical consolidated statement of operations and production data for Carbon Appalachia.
|
|
Six Months Ended
June 30,
2018
|
|
|
|
(in thousands
except
production
data)
|
|
Revenue:
|
|
|
|
Natural gas sales
|
|
$
|
25,556
|
|
Oil sales
|
|
|
813
|
|
Gas transportation
|
|
|
1,476
|
|
Marketing
|
|
|
17,046
|
|
Commodity derivative gain
|
|
|
(469
|
)
|
Total revenues
|
|
|
44,422
|
|
|
|
|
|
|
Expenses:
|
|
|
|
|
Lease operating expenses
|
|
|
10,961
|
|
Transportation, gathering and compression
|
|
|
5,921
|
|
Production and property taxes
|
|
|
2,278
|
|
Gas purchase-marketing
|
|
|
13,912
|
|
General and administration
|
|
|
1,383
|
|
Depreciation, depletion, and amortization
|
|
|
2,934
|
|
Accretion of asset retirement obligations
|
|
|
265
|
|
|
|
|
2,102
|
|
Total expenses
|
|
|
39,756
|
|
|
|
|
|
|
Operating income
|
|
|
4,666
|
|
|
|
|
|
|
Other expense:
|
|
|
|
|
Interest expense
|
|
|
(1,187
|
)
|
Net income
|
|
$
|
3,479
|
|
|
|
|
|
|
Production data:
|
|
|
|
|
Natural gas (Mcf)
|
|
|
8,348,569
|
|
Oil (Bbl)
|
|
|
13,879
|
|
Combined (Mcfe)
|
|
|
8,431,843
|
|
|
|
April 3,
2017
(Inception)
through
June 30,
2017
|
|
|
|
(in thousands
except
production
data)
|
|
Revenue:
|
|
|
|
Natural gas sales
|
|
$
|
1,007
|
|
Oil sales
|
|
|
154
|
|
Gas transportation
|
|
|
241
|
|
Marketing
|
|
|
-
|
|
Commodity derivative gain
|
|
|
155
|
|
Total revenues
|
|
|
1,557
|
|
|
|
|
|
|
Expenses:
|
|
|
|
|
Lease operating expenses
|
|
|
233
|
|
Transportation, gathering and compression
|
|
|
147
|
|
Production and property taxes
|
|
|
35
|
|
Gas purchase-marketing
|
|
|
-
|
|
General and administration
|
|
|
845
|
|
Depreciation, depletion, and amortization
|
|
|
493
|
|
Accretion of asset retirement obligations
|
|
|
4
|
|
Management and operating fees, related party
|
|
|
-
|
|
Total expenses
|
|
|
1,757
|
|
|
|
|
|
|
Operating income
|
|
|
(200
|
)
|
|
|
|
|
|
Other expense:
|
|
|
|
|
Class B units issuance
|
|
|
-
|
|
Interest expense
|
|
|
(129
|
)
|
Net income
|
|
$
|
(329
|
)
|
|
|
|
|
|
Production data:
|
|
|
|
|
Natural gas (Mcf)
|
|
|
286,289
|
|
Oil (Bbl)
|
|
|
3,759
|
|
Combined (Mcfe)
|
|
|
308,843
|
|
|
|
April 3,
2017
(Inception)
through
December 31,
2017
|
|
|
|
(in thousands
except
production
data)
|
|
Revenue:
|
|
|
|
Natural gas sales
|
|
$
|
16,128
|
|
Oil sales
|
|
|
685
|
|
Gas transportation
|
|
|
911
|
|
Marketing
|
|
|
11,315
|
|
Commodity derivative gain
|
|
|
2,545
|
|
Total revenues
|
|
|
31,584
|
|
|
|
|
|
|
Expenses:
|
|
|
|
|
Lease operating expenses
|
|
|
5,587
|
|
Transportation, gathering and compression
|
|
|
4,160
|
|
Production and property taxes
|
|
|
1,464
|
|
Gas purchase-marketing
|
|
|
9,290
|
|
General and administration
|
|
|
2,044
|
|
Depreciation, depletion, and amortization
|
|
|
2,439
|
|
Accretion of asset retirement obligations
|
|
|
198
|
|
Management and operating fees, related party
|
|
|
1,582
|
|
Total expenses
|
|
|
26,764
|
|
|
|
|
|
|
Operating income
|
|
|
4,820
|
|
|
|
|
|
|
Other expense:
|
|
|
|
|
Class B units issuance
|
|
|
924
|
|
Interest expense
|
|
|
891
|
|
Net income
|
|
$
|
3,005
|
|
|
|
|
|
|
Production data:
|
|
|
|
|
Natural gas (Mcf)
|
|
|
5,304,208
|
|
Oil (Bbl)
|
|
|
14,288
|
|
Combined (Mcfe)
|
|
|
5,389,936
|
|
Carbon
California
The
following table sets forth selected historical statement of operations and production data for Carbon California.
|
|
February 15,
2017
(Inception)
through
December 31,
2017
|
|
|
|
(in thousands
except
production
data)
|
|
Revenue:
|
|
|
|
Natural gas sales
|
|
$
|
1,036
|
|
Oil sales
|
|
|
7,024
|
|
Natural gas liquids sales
|
|
|
556
|
|
Commodity derivative loss
|
|
|
(1,381
|
)
|
Total revenues
|
|
|
7,235
|
|
|
|
|
|
|
Expenses:
|
|
|
|
|
Lease operating expenses
|
|
|
3,726
|
|
Transportation costs
|
|
|
1,442
|
|
Production and property taxes
|
|
|
527
|
|
General and administrative
|
|
|
2,177
|
|
Depreciation, depletion and amortization
|
|
|
1,304
|
|
Accretion of asset retirement obligations
|
|
|
192
|
|
Management and operating fees, related party
|
|
|
525
|
|
Total operating expenses
|
|
|
9,893
|
|
Operating loss
|
|
|
(2,658
|
)
|
Other expense:
|
|
|
|
|
Class B units issuance
|
|
|
1,854
|
|
Interest expense
|
|
|
2,040
|
|
Net loss
|
|
$
|
(6,552
|
)
|
|
|
|
|
|
Production data:
|
|
|
|
|
Natural gas (Mcf)
|
|
|
351,287
|
|
Oil (Bbl)
|
|
|
141,219
|
|
NGLs (Bbl)
|
|
|
23,410
|
|
Combined (Mcfe)
|
|
|
1,339,061
|
|
Liquidity
and Capital Resources
Our
exploration, development and acquisition activities may require us to make significant operating and capital expenditures. Historically,
we have used cash flow from operations and our Existing Credit Facility as our primary sources of liquidity and on occasion, we
have engaged in the sale of assets. Changes in the market prices for oil and natural gas directly impact our level of cash flow
generated from operations. The prices we receive for our production are determined by prevailing market conditions and greatly
influence our revenue, cash flow, profitability, access to capital and future rate of growth. We employ a commodity hedging strategy
in an attempt to moderate the effects of commodity price fluctuations on our cash flow.
The following tables reflect our outstanding
derivative agreements as of June 30, 2018:
Our Physical Delivery Contracts
and Oil and Gas Derivatives
|
|
Natural
Gas Swaps
|
|
|
Natural
Gas Collars
|
|
|
Oil
Swaps
|
|
|
|
|
|
|
Weighted
|
|
|
|
|
|
Weighted
|
|
|
|
|
|
Weighted
|
|
|
|
|
|
|
Average
|
|
|
|
|
|
Average
Price
|
|
|
|
|
|
Average
|
|
Year
|
|
MMBtu
|
|
|
Price
(1)
|
|
|
MMBtu
|
|
|
Range
(1)
|
|
|
Bbl
|
|
|
Price
(2)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2018
|
|
|
1,740,000
|
|
|
$
|
3.00
|
|
|
|
-
|
|
|
|
-
|
|
|
|
35,500
|
|
|
$
|
53.41
|
|
2019
|
|
|
2,596,000
|
|
|
$
|
2.86
|
|
|
|
-
|
|
|
|
-
|
|
|
|
48,000
|
|
|
$
|
53.76
|
|
(1)
|
NYMEX
Henry Hub Natural Gas futures contract for the respective period.
|
(2)
|
NYMEX Light Sweet Crude West Texas Intermediate future contract for the respective period.
|
Carbon California Physical Delivery Contracts and Oil
and Gas Derivatives
|
|
Natural
Gas Swaps
|
|
|
Natural
Gas Collars
|
|
|
Oil
Swaps
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted
Average
|
|
|
|
|
|
Average
Price
|
|
|
WTI
|
|
|
Weighted
Average
|
|
|
Brent
|
|
|
Weighted
Average
|
|
Year
|
|
MMBtu
|
|
|
Price
(1)
|
|
|
MMBtu
|
|
|
Range
(1)
|
|
|
Bbl
|
|
|
Price
(2)
|
|
|
Bbl
|
|
|
Price
(3)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2018
|
|
|
180,000
|
|
|
$
|
3.03
|
|
|
|
-
|
|
|
|
-
|
|
|
|
85,809
|
|
|
$
|
53.08
|
|
|
|
110,598
|
|
|
$
|
66.46
|
|
2019
|
|
|
-
|
|
|
$
|
-
|
|
|
|
360,000
|
|
|
$
|
2.60 - $3.03
|
|
|
|
139,797
|
|
|
$
|
51.96
|
|
|
|
137,486
|
|
|
$
|
66.35
|
|
2020
|
|
|
-
|
|
|
$
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
73,147
|
|
|
$
|
50.12
|
|
|
|
123,882
|
|
|
$
|
65.06
|
|
2021
|
|
|
-
|
|
|
$
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
$
|
-
|
|
|
|
28,641
|
|
|
$
|
66.35
|
|
(1)
|
NYMEX
Henry Hub Natural Gas futures contract for the respective period.
|
(2)
|
NYMEX
Light Sweet Crude West Texas Intermediate future contract for the respective period.
|
(3)
|
Brent
for the respective period.
|
For
our swap instruments, we receive a fixed price for the hedged commodity and pay a floating price to the counterparty. The fixed-price
payment and the floating-price payment are netted, resulting in a net amount due to or from the counterparty.
Costless
collars are designed to establish floor and ceiling prices on anticipated future oil and gas production. The ceiling establishes
a maximum price that we will receive for the volumes under contract, while the floor establishes a minimum price.
This
hedge program mitigates uncertainty regarding cash flow that we will receive with respect to a portion of our expected production
through 2020. Future hedging activities may result in reduced income or even financial losses to us. Please read “
Business—Risk
Management
” for additional discussion of our commodity derivative contracts. In the future, we may determine to
increase or decrease our hedging positions.
We
have derivative contracts with BP Energy Company pursuant to an ISDA Master Agreement. BP Energy Company is currently our only
derivative contract counterparty.
Management
Reimbursements
In our role as manager of Carbon California
and Carbon Appalachia, we receive management reimbursements. We received approximately $1.5 million for the six months ended June
30, 2018, from Carbon Appalachia, and $50,000 for the one month ended January 31, 2018, from Carbon California. These reimbursements
are included in general and administrative – related party reimbursement on our unaudited consolidated statements of operations.
Effective February 1, 2018, the management reimbursements received from Carbon California are eliminated at consolidation. This
elimination includes $350,000 for the period February 1, 2018, through June 30, 2018.
In addition to the management reimbursements,
approximately $595,000 in general and administrative expenses were reimbursed for the six months ended June 30, 2018, from Carbon
Appalachia, and $14,000 for the one month ended January 31, 2018, by Carbon California. The elimination of Carbon California in
consolidation includes approximately $42,000 in general and administrative expenses that were reimbursed for the period February
1, 2018, through June 30, 2018.
Total reimbursements from Carbon California
and Carbon Appalachia were approximately $1.0 million and $1.6 million, respectively, during the year ended December 31, 2017.
Operating Reimbursements
In our role as operator of Carbon Appalachia,
we receive reimbursements of operating expenses. These expenses are recorded directly to receivable – related party on our
unaudited consolidated balance sheets and are therefore not included in our operating expenses on our unaudited consolidated statements
of operations.
Historically, the primary source of liquidity
has been our credit facilities (described below). We may use other sources of capital, including the issuance of debt or equity
securities, to fund acquisitions or maintain our financial flexibility.
We believe that our financial flexibility
to adjust our spending levels will provide us with sufficient liquidity to meet our financial obligations should economic conditions
deteriorate. See “
Risk Factors
” for a discussion of the risks and uncertainties that affect our business
and financial and operating results.
Our
Credit Facility
Our
New Revolving Credit Facility
In
connection with the closing of this offering, we intend to enter into the New Revolving Credit Facility to replace our Existing
Credit Facility and the CAE Credit Facility. The New Revolving Credit Facility will contain a letters of credit sub-facility up
to $1.5 million.
The
initial borrowing base will be $100 million. The borrowing base will be subject to semi-annual redeterminations by the lenders
in their sole discretion in May and November.
The
New Revolving Credit Facility will be guaranteed by each of our existing and future subsidiaries. Our obligations and those of
our subsidiary guarantors under the New Revolving Credit Facility will be secured by a first lien on all of our and our subsidiaries’
assets.
Interest
is payable quarterly and accrues on borrowings under the New Revolving Credit Facility at a rate per annum equal to either (i)
the base rate plus an applicable margin between 0% and .75% or (ii) the Adjusted LIBOR rate plus an applicable margin between
2.75% and 3.75% at our option. The actual margin percentage is dependent on the borrowing base utilization percentage. We will
be obligated to pay certain fees and expenses in connection with the New Revolving Credit Facility, including a fee for any unused
amounts of 0.50%.
The New Revolving Credit Facility will
contain affirmative and negative covenants that, among other things, limit our ability to (i) incur additional debt; (ii) incur
additional liens; (iii) sell, transfer or dispose of assets; (iv) make certain dividends on, or repurchases of, equity; (v) make
certain investments; (vi) enter into sales-leaseback transactions; and (vii) make certain mergers and acquisitions. Dividends
will be permitted under the New Revolving Credit Facility so long as (a) no default exists or would exist pro forma for such dividend,
(b) the minimum revolver availability is at least 15% following such dividend, and (c) the Net Debt (as defined therein) to Adjusted
EBITDAX (as defined therein) ratio is not greater than 2.75 to 1.00 pro forma for such dividend measured at the time such dividends
are declared. Under the New Revolving Credit Facility, we will be required to maintain, on a consolidated basis, (i) a maximum
Total Net Debt/EBITDAX ratio of 3.5 to 1.0 beginning in the third quarter of 2018 and (ii) a minimum current ratio of 1.0 to 1.0
beginning in the third quarter of 2018.
We
may at any time repay the loans under the New Revolving Credit Facility, in whole or in part, without penalty. We will be required
to pay down borrowings under the New Revolving Credit Facility or provide additional security to the extent that outstanding loans
and letters of credit exceed the borrowing base.
We
will be required under the terms of the New Revolving Credit Facility to hedge at least 70% of our projected proved developed
producing volumes on a rolling 30-month basis. We are currently a party to an ISDA Master Agreement with BP Energy Company that
established standard terms for the derivative contracts and an inter-creditor agreement with LegacyTexas Bank and BP Energy Company
whereby any credit exposure related to the derivative contracts entered into by us and BP Energy Company is secured by the collateral
and backed by the guarantees supporting the New Revolving Credit Facility.
The
outstanding debt under our Existing Credit Facility and the CAE Credit Facility will be assigned to the lender syndicate under
the New Revolving Credit Facility, and, following the closing of this offering, our outstanding debt under the New Revolving Credit
Facility will be $ .
For
a description of the Existing Credit Facility and CAE Credit Facility that the New Revolving Credit Facility is replacing, see
Note 7 to our consolidated financial statements included in this prospectus.
Carbon
California’s Private Placement Notes
In connection with the CRC Acquisition,
Carbon California (i) entered into a Note Purchase Agreement (the “
Note Purchase Agreement
”) for the
issuance and sale of Senior Secured Revolving Notes to Prudential Legacy Insurance Company of New Jersey and Prudential Insurance
Company of America with a revolving borrowing capacity of $25.0 million (the “
Senior Revolving Notes
”)
which mature on February 15, 2022 and (ii) entered into a Securities Purchase Agreement (the “
Securities Purchase
Agreement
”) with Prudential for the issuance and sale of $10.0 million of Senior Subordinated Notes (the “
Subordinated
Notes
”) due February 15, 2024. We are not a guarantor of the Senior Revolving Notes or the Subordinated Notes. The
closing of the Note Purchase Agreement and the Securities Purchase Agreement on February 15, 2017, resulted in the sale and issuance
by Carbon California of (i) Senior Revolving Notes in the principal amount of $10.0 million and (ii) Subordinated Notes in the
original principal amount of $10.0 million. The maximum principal amount available under the Senior Revolving Notes is based upon
the borrowing base attributable to Carbon California’s proved oil and gas reserves which is to be determined upon delivery
of any reserve report. On May 1, 2018, the borrowing base increased to $41.0 million. There was $38.5 million of indebtedness
outstanding thereunder as of June 30, 2018. On May 1, 2018, Carbon California entered into a securities purchase agreement with
Prudential, which resulted in (i) the issuance and sale of $3.0 million of Senior Subordinated Notes due February 15, 2024 and
(ii) the issuance of 585 Class A units of Carbon California as partial consideration for the Subordinated Notes. The ability of
Carbon California to make distributions to its owners, including us, is dependent upon the terms of the Note Purchase Agreement
and Securities Purchase Agreement, which currently prohibit distributions unless they are agreed to by Prudential.
Interest
is payable quarterly and accrues on borrowings under the Senior Revolving Notes at a rate per annum equal to either (i) the prime
rate plus an applicable margin of 4.00% or (ii) the LIBOR rate plus an applicable margin of 5.00% at our option. Carbon California
is obligated to pay certain fees and expenses in connection with the Senior Revolving Notes, including a commitment fee for any
unused amounts of 0.50%. Interest is payable quarterly and accrues on the Subordinated Notes at a fixed rate of 12.0% per annum.
The
Senior Revolving Notes and the Subordinated Notes contain affirmative and negative covenants that, among other things, limit Carbon
California’s ability to (i) incur additional debt; (ii) incur additional liens; (iii) sell, transfer or dispose of assets;
(iv) merge or consolidate, wind-up, dissolve or liquidate; (v) make dividends and distributions on, or repurchases of, equity;
(vi) make certain investments; (vii) enter into certain transactions with our affiliates; (viii) enter into sales-leaseback transactions;
(ix) make optional or voluntary payments of debt; (x) change the nature of our business; (xi) change our fiscal year to make changes
to the accounting treatment or reporting practices; (xii) amend constituent documents; and (xiii) enter into certain hedging transactions.
The
affirmative and negative covenants are subject to various exceptions, including basket amounts and acceptable transaction levels.
In addition, (i) the Senior Revolving Notes require Carbon California’s compliance, on a consolidated basis, with (A) a
maximum Debt/EBITDA ratio of 4.0 to 1.0, stepping down to 3.5 to 1.0 starting with the quarter ending June 30, 2018, (B) a maximum
Senior Revolving Notes/EBITDA ratio of 2.5 to 1.0, (C) a minimum interest coverage ratio of 3.0 to 1.0 and (D) a minimum current
ratio of 1.0 to 1.0 and (ii) the Subordinated Notes require Carbon California’s compliance, on a consolidated basis, with
(A) a maximum Debt/EBITDA ratio of 4.5 to 1.0, stepping down to 4.0 to 1.0 starting with the quarter ending June 30, 2018, (B)
a maximum Senior Revolving Notes/EBITDA ratio of 3.0 to 1.0, (C) a minimum interest coverage ratio of 2.5 to 1.0, (D) an asset
coverage test whereby indebtedness may not exceed the product of 0.65 times Adjusted PV-10 set forth in the most recent reserve
report, (E) maintenance of a minimum borrowing base of $10,000,000 under the Senior Revolving Notes and (F) a minimum current
ratio of 0.85 to 1.00.
Carbon
California may at any time repay the Senior Revolving Notes, in whole or in part, without penalty. Carbon California must pay
down Senior Revolving Notes or provide mortgages of additional oil and natural gas properties to the extent that outstanding loans
and letters of credit exceed the borrowing base. Carbon California may not voluntarily prepay the Subordinated Notes prior to
February 15, 2019, and thereafter may do so subject to a premium of 3% which reduces to 0% from and after February 17, 2020. In
the event the Subordinated Notes are accelerated prior to February 15, 2019, Carbon California would owe a make-whole premium
calculated using a discount rate of 1% over United States Treasury securities rates, and otherwise calculated as provided in the
Securities Purchase Agreement.
Borrowings under the Senior Revolving
Notes and net proceeds from the Subordinated Notes issuances were used to fund the Mirada Acquisition, the CRC Acquisition and
the Seneca Acquisition. Additional borrowings under the Senior Revolving Notes may be used to fund field development projects
and to fund future complementary acquisitions and for general working capital purposes of Carbon California.
As of December 31, 2017 and March 31,
2018, Carbon California was in breach of its covenants; however, it obtained a waiver with respect to compliance with such covenants
as of December 31, 2017 and March 31, 2018. As of June 30, 2018, Carbon California was in compliance with its financial covenants.
See
Liquidity and Management’s Plans
within Note 1 to the December 31, 2017 Carbon California financial statements.
Sources and Uses of Cash
Our primary sources of liquidity and
capital resources are operating cash flow and borrowings under our credit facilities. Our primary uses of funds are expenditures
for acquisition, exploration and development activities, leasehold and property acquisitions, other capital expenditures and debt
service. We intend to use the proceeds of this offering to fund the Old Ironsides Buyout, pay down debt and other general corporate
purposes, including to fund potential expansion capital expenditures and acquisitions. See “
Use of Proceeds
.”
Low
prices for our oil and natural gas production may adversely impact our operating cash flow and amount of cash available for development
activities.
The following table presents net cash provided
by or used in operating, investing and financing activities.
|
|
Six
Months Ended
|
|
|
|
June
30,
|
|
(in
thousands)
|
|
2018
|
|
|
2017
|
|
|
|
|
|
|
|
|
Net
cash provided by operating activities
|
|
$
|
1,615
|
|
|
$
|
2,336
|
|
Net cash used
in investing activities
|
|
$
|
(40,197
|
)
|
|
$
|
(1,437
|
)
|
Net cash provided
by (used in) financing activities
|
|
$
|
40,962
|
|
|
$
|
(743
|
)
|
|
|
Year
Ended
|
|
|
|
December
31,
|
|
(in
thousands)
|
|
2017
|
|
|
2016
|
|
|
|
|
|
|
|
|
Net
cash provided by (used in) operating activities
|
|
$
|
3,920
|
|
|
$
|
(3,142
|
)
|
Net cash used in
investing activities
|
|
$
|
(8,533
|
)
|
|
$
|
(8,754
|
)
|
Net cash provided
by financing activities
|
|
$
|
5,405
|
|
|
$
|
12,449
|
|
Six Months Ended June 30, 2018 Compared
to Six Months Ended June 30, 2017
Net cash provided by or used in operating
activities is primarily affected by production volumes and commodity prices, net of the effects of settlements of our derivative
contracts, and changes in working capital. Operating cash flows decreased approximately $721,000 for the six months ended June
30, 2018 as compared to the same period in 2017. The decrease was primarily due to an increase in working capital and increased
cash interest payments.
Net
cash provided by or used in investing activities is primarily comprised of the acquisition, exploration and development of oil
and natural gas properties, net of dispositions of oil and natural gas properties in addition to expenditures to fund our equity
investment in Carbon Appalachia. Net cash used in investing activities increased approximately $38.8 million for the six months
ended June 30, 2018 as compared to the same period in 2017 primarily due to the Seneca Acquisition.
The
increase in cash provided by financing cash flows of approximately $41.7 million for the six months ended June 30, 2018 as compared
to the six months ended June 30, 2017 was primarily due to $30.9 million in proceeds from borrowings under our credit facilities,
$5.0 million in proceeds from the Preferred Stock and $5.0 million in proceeds from Prudential for the Seneca Acquisition.
Year
Ended 2017 Compared to Year Ended 2016
Net
cash provided by or used in operating activities is primarily affected by production volumes and commodity prices, net of the
effects of settlements of our derivative contracts, and changes in working capital. Operating cash flows increased approximately
$7.1 million for the year ended December 31, 2017 as compared to the same period in 2016. This increase was primarily due to increased
revenues from the acquisition of production of oil and natural gas properties in the Appalachia Basin in the fourth quarter of
2016 and higher oil and natural gas prices for the year ended December 31, 2017, as compared to the same period in 2016.
Net
cash provided by or used in investing activities is primarily comprised of the acquisition, exploration and development of oil
and natural gas properties, net of dispositions of oil and natural gas properties in addition to expenditures to fund our equity
investment in Carbon Appalachia. Net cash used in investing activities decreased approximately $221,000 for the year ended December
31, 2017 as compared to the same period in 2016. In addition, we increased capital expenditures for the development and acquisition
of properties and equipment for the year ended December 31, 2017 by approximately $891,000 compared to the year ended December
31, 2016. In addition, for the year ended December 31, 2017, we made an approximate $6.9 million equity investment in Carbon Appalachia;
whereas, during the year ended December 31, 2016, we received a cash distribution of $340,000 from Crawford County Gas Gathering
Company.
The
decrease in financing cash flows of approximately $7.0 million for the year ended December 31, 2017 as compared to the year ended
December 31, 2016 was primarily due to borrowings of $7.2 million to fund the purchase of oil and gas wells in the Appalachian
Basin in 2017, compared to $16.9 million proceeds used to fund the purchase of Appalachian Basin producing properties and payoff
our former credit facility in 2016.
Capital
Expenditures
Capital expenditures for the six months
ended June 30, 2018 and 2017 and the years ended December 31, 2017 and 2016 are summarized in the following table:
|
|
Six Months Ended
June 30,
|
|
(in thousands)
|
|
2018
|
|
|
2017
|
|
|
|
|
|
|
|
|
Unevaluated property acquisitions
|
|
$
|
100
|
|
|
$
|
215
|
|
Oil and gas asset purchase
|
|
|
39,039
|
|
|
|
-
|
|
Drilling and development
|
|
|
788
|
|
|
|
781
|
|
Other
|
|
|
545
|
|
|
|
186
|
|
Total capital expenditures
|
|
$
|
40,472
|
|
|
$
|
1,182
|
|
|
|
Year Ended
December 31,
|
|
(in thousands)
|
|
2017
|
|
|
2016
|
|
|
|
|
|
|
|
|
Acquisition of oil and gas properties:
|
|
|
|
|
|
|
Unevaluated properties
|
|
$
|
1
|
|
|
$
|
97
|
|
Oil and natural gas producing properties
|
|
|
289
|
|
|
|
8,117
|
|
|
|
|
|
|
|
|
|
|
Drilling and development
|
|
|
952
|
|
|
|
360
|
|
Pipeline and gathering
|
|
|
43
|
|
|
|
42
|
|
Other
|
|
|
306
|
|
|
|
201
|
|
Total capital expenditures
|
|
$
|
1,591
|
|
|
$
|
8,817
|
|
Capital
expenditures reflected in the table above represent cash used for capital expenditures.
We anticipate that the budget for the
second half of 2018 for exploration and development work on existing acreage will range between $0 million and $1.0 million for
us, between $1.0 million and $4.0 million for Carbon Appalachia, and between $5.0 million and $8.0 million for Carbon California.
We anticipate that the budget for 2019 for exploration and development work on existing acreage will range between $4.0 million
and $8.0 million for us, between $10.0 million and $25.0 million for Carbon Appalachia, and between $15.0 million and $21.0 million
for Carbon California.
Due to low commodity prices in recent
years, we have focused on the optimization and streamlining of our natural gas gathering and compression facilities and marketing
arrangements to provide greater flexibility in moving production to markets with more favorable pricing. Other factors impacting
the level of our capital expenditures include the cost and availability of oil field services, general economic and market conditions
and weather disruptions.
Off-balance
Sheet Arrangements
From time-to-time, we enter into off-balance
sheet arrangements and transactions that can give rise to off-balance sheet obligations. As of June 30, 2018, the off-balance
sheet arrangements and transactions that we entered into included (i) operating lease agreements, (ii) contractual obligations
for which the ultimate settlement amounts are not fixed and determinable, such as natural gas transportation contracts, and (iii)
oil and natural gas physical delivery contracts that are not expected to be net cash settled and are considered to be normal sales
contracts and not derivatives. We do not believe that any of these arrangements are reasonably likely to materially affect our
liquidity or availability of, or requirements for, capital resources.
Critical
Accounting Policies, Estimates, Judgments, and Assumptions
We
prepare our financial statements and the accompanying notes in conformity with GAAP, which require management to make estimates
and assumptions about future events that affect the reported amounts in the financial statements and the accompanying notes. We
identify certain accounting policies as critical based on, among other things, their impact on the portrayal of our financial
condition, results of operations, or liquidity and the degree of difficulty, subjectivity, and complexity in their deployment.
Critical accounting policies cover accounting matters that are inherently uncertain because the future resolution of such matters
is unknown. The following is a discussion of our most critical accounting policies.
Full
Cost Method of Accounting
The
accounting for our business is subject to special accounting rules that are unique to the oil and natural gas industry. There
are two allowable methods of accounting for oil and natural gas business activities: the full cost method and the successful efforts
method. The differences between the two methods can lead to significant variances in the amounts reported in financial statements.
We use the full cost method of accounting as defined by SEC Release No. 33-8995 and FASB ASC 932.
Under
the full cost method, separate cost centers are maintained for each country in which we incur costs. All costs incurred in the
acquisition, exploration, and development of properties (including costs of surrendered and abandoned leaseholds, delay lease
rentals, dry holes, and overhead related to exploration and development activities) are capitalized. The fair value of estimated
future costs of site restoration, dismantlement, and abandonment activities is capitalized, and a corresponding asset retirement
obligation liability is recorded.
Capitalized
costs applicable to each full cost center are depleted using the units-of-production method based on conversion to common units
of measure using one barrel of oil as an equivalent to six thousand cubic feet of natural gas. Changes in estimates of reserves
or future development costs are accounted for prospectively in the depletion calculations. Based on this accounting policy, our
December 31, 2017 and 2016 reserve estimates were used for our respective period depletion calculations. These reserve estimates
were calculated in accordance with SEC rules. See “
Business—Reserves
” and Notes 1 and 3 to
the consolidated financial statements for a more complete discussion of the rule and our estimated proved reserves as of December 31,
2017 and 2016.
Companies that use the full cost method
of accounting for oil and natural gas exploration and development activities are required to perform a quarterly ceiling test
for each cost center. The full cost ceiling test is a limitation on capitalized costs prescribed by SEC Regulation S-X Rule 4-10.
The ceiling test is not a fair value-based measurement. Rather, it is a standardized mathematical calculation. The test determines
a limit, or ceiling, on the book value of our oil and natural gas properties. That limit is basically the after tax present value
of the future net cash flows from proved oil and natural gas reserves. This ceiling is compared to the net book value of the oil
and natural gas properties reduced by any related net deferred income tax liability. If the net book value reduced by the related
deferred income taxes exceeds the ceiling, an impairment or non-cash write-down is required. Such impairments are permanent and
cannot be recovered even if the sum of the components noted above exceeds capitalized costs in future periods. The two primary
factors impacting this test are reserve levels and oil and natural gas prices and their associated impact on the present value
of estimated future net revenues. In 2017 and the six months ended June 30, 2018, we did not recognize a ceiling test impairment.
In 2016, we recognized an impairment of approximately $4.3 million. This impairment resulted primarily from the impact of a decrease
in the 12-month average trailing price for oil and natural gas utilized in determining the future net cash flows from proved reserves.
Lower oil and natural gas prices may not only decrease our revenues but may also reduce the amount of oil and natural gas that
we can produce economically and potentially lower our oil and natural gas reserves. Negative revisions to estimates of oil and
natural gas reserves and decreases in prices can have a material impact of the present value of estimated future net revenues
which may require us to recognize additional impairments of our oil and natural gas properties in future periods.
In
countries or areas where the existence of proved reserves has not yet been determined, leasehold costs, seismic costs, and other
costs incurred during the exploration phase remain capitalized as unproved property costs until proved reserves have been established
or until exploration activities cease. If exploration activities result in the establishment of proved reserves, amounts are reclassified
as proved properties and become subject to depreciation, depletion and amortization and the application of the ceiling limitation.
Unproved properties are assessed periodically to ascertain whether impairment has occurred. Unproved properties whose costs are
individually significant are assessed individually by considering the primary lease terms of the properties, the holding period
of the properties, and geographic and geologic data obtained relating to the properties. Where it is not practical to individually
assess properties whose costs are not individually significant, such properties are grouped for purposes of assessing impairment.
The amount of impairment assessed is added to the costs to be amortized in the appropriate full cost pool. Subject to industry
conditions, evaluation of most of our unproved properties and inclusion of these costs in proved property costs subject to amortization
are expected to be completed within five years.
Under
the alternative successful efforts method of accounting, surrendered, abandoned, and impaired leases, delay lease rentals, exploratory
dry holes, and overhead costs are expensed as incurred. Capitalized costs are depleted on a property-by-property basis. Impairments
are also assessed on a property-by-property basis and are charged to expense when assessed.
The
full cost method is used to account for our oil and natural gas exploration and development activities because we believe it appropriately
reports the costs of our exploration programs as part of an overall investment in discovering and developing proved reserves.
Oil
and Natural Gas Reserve Estimates
Our
estimates of proved reserves are based on the quantities of oil and natural gas that geological and engineering data demonstrate,
with reasonable certainty, to be recoverable in future years from known reservoirs under existing economic and operating conditions.
The accuracy of any reserve estimate is a function of the quality of available data, engineering and geological interpretation,
and judgment. For example, we must estimate the amount and timing of future operating costs, production and property taxes, development
costs, and workover costs, all of which may in fact vary considerably from actual results. In addition, as prices and cost levels
change from year to year, the estimate of proved reserves also changes. Any significant variance in these assumptions could materially
affect the estimated quantity and value of our reserves. Despite the inherent uncertainty in these engineering estimates, our
reserves are used throughout our financial statements. For example, since we use the units-of-production method to amortize our
oil and natural gas properties, the quantity of reserves could significantly impact our DD&A expense. Our oil and natural
gas properties are also subject to a “ceiling test” limitation based in part on the quantity of our proved reserves.
Reference should be made to “
Business—Reserves
”
and “
Risk Factors—Risks Related to Our Business—Reserve estimates depend on many assumptions that may
turn out to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect
the quantities and present value of our proved reserves
.”
Accounting
for Derivative Instruments
We
recognize all derivative instruments as either assets or liabilities at fair value. Under the provisions of authoritative derivative
accounting guidance, we may or may not elect to designate a derivative instrument as a hedge against changes in the fair value
of an asset or a liability (a “fair value hedge”) or against exposure to variability in expected future cash flows
(a “cash flow hedge”). The accounting treatment for the changes in fair value of a derivative instrument is dependent
upon whether or not a derivative instrument is a cash flow hedge or a fair value hedge, and upon whether or not the derivative
is designated as a hedge. Changes in fair value of a derivative designated as a cash flow hedge are recognized, to the extent
the hedge is effective, in other comprehensive income until the hedged item is recognized in earnings. Changes in the fair value
of a derivative instrument designated as a fair value hedge, to the extent the hedge is effective, have no effect on the consolidated
statement of operations, because changes in fair value of the derivative offsets changes in the fair value of the hedged item.
Where hedge accounting is not elected or if a derivative instrument does not qualify as either a fair value hedge or a cash flow
hedge, changes in fair value are recognized in earnings. We have elected not to use hedge accounting and as a result, all changes
in the fair values of our derivative instruments are recognized in commodity derivative gain or loss in our consolidated statements
of operations.
As of June 30, 2018 and December 31,
2017, the fair value of our derivative agreements was a net liability of approximately $8.0 million and a net asset of approximately
$225,000, respectively. As of December 31, 2016, the fair value of our derivative agreements was a liability of approximately
$1.9 million. The fair value measurement of commodity derivative assets and liabilities are measured based upon our valuation
model that considers various inputs including (a) quoted forward prices for commodities, (b) time value, (c) notional quantities,
(d) current market and contractual prices for the underlying instruments; and (e) the counterparty’s credit risk. Volatility
in oil and natural gas prices could have a significant impact on the fair value of our derivative contracts. See Note 11 to the
consolidated financial statements for further discussion. The values we report in our consolidated financial statements are as
of a point in time and subsequently change as these estimates are revised to reflect actual results, changes in market conditions
or other factors, many of which are beyond our control.
Due to the volatility of oil and natural
gas prices, the estimated fair values of our commodity derivative instruments are subject to large fluctuations from period to
period and we expect the volatility to continue. Actual gains or losses recognized related to our commodity derivative instruments
will likely differ from those estimated at June 30, 2018 and will depend exclusively on the price of the commodities on the specified
settlement dates provided by the derivative contracts.
Valuation
of Deferred Tax Assets
We
use the asset and liability method of accounting for income taxes. Under this method, income tax assets and liabilities are determined
based on differences between the financial statement carrying values of assets and liabilities and their respective income tax
bases (temporary differences). Income tax assets and liabilities are measured using the tax rates expected to be in effect when
the temporary differences are likely to reverse. The effect on income tax assets and liabilities of a change in tax rates is included
in earnings in the period in which the change is enacted. With the passage of the TCJA, we are required to remeasure deferred
income taxes at the lower 21% corporate rate as of the date the TCJA was signed into law even though the reduced rate is effective
January 1, 2018. The book value of income tax assets is limited to the amount of the tax benefit that is more likely than not
to be realized in the future.
In
assessing the need for a valuation allowance on our deferred tax assets, management considers whether it is more likely than not
that some portion or all of the deferred tax assets will be realized. The ultimate realization of deferred tax assets is dependent
upon whether future book income is sufficient to reverse existing temporary differences that give rise to deferred tax assets,
as well as whether future taxable income is sufficient to utilize net operating loss and credit carryforwards. Assessing the need
for, or the sufficiency of, a valuation allowance requires the evaluation of all available evidence, both positive and negative.
Positive evidence considered by management includes current book income in 2013, 2014 and 2017, forecasted book income if commodity
prices increase, and taxable proceeds from the Liberty participation agreements and the sale of our deep rights in leases in Kentucky
and West Virginia in 2014. Negative evidence considered by management includes book losses in certain years which were driven
primarily from ceiling test write-downs, which are not fair value-based measurements and current commodity prices which will impact
forecasted income or loss.
As of June 30, 2018 and December 31,
2017, management assessed the available positive and negative evidence to estimate if sufficient future taxable income would be
generated to use our deferred tax assets and determined that it is more-likely-than-not that the deferred tax assets will not
be realized in the near future. Based on this assessment, we recorded a net valuation allowance of approximately $13.3 million
on our deferred tax assets as of December 31, 2017.
Asset
Retirement Obligations
We
have obligations to remove tangible equipment and restore locations at the end of oil and natural gas production operations. FASB
ASC Topic 410,
Asset Retirement and Environmental Obligations
, requires that the discounted fair value of a liability for
an asset retirement obligation (“
ARO
”) be recognized in the period in which it is incurred with the
associated asset retirement cost capitalized as part of the carrying cost of the oil and natural gas asset. Estimating the future
restoration and removal costs, or ARO, is difficult and requires management to make estimates and judgments, because most of the
obligations are many years in the future, and contracts and regulations often have vague descriptions of what constitutes removal.
Asset removal technologies and costs are constantly changing, as are regulatory, political, environmental, safety, and public
relations considerations.
Inherent
in the calculation of the present value of our ARO are numerous assumptions and judgments, including the ultimate settlement amounts,
inflation factors, credit adjusted discount rates, timing of settlement, and changes in the legal, regulatory, environmental,
and political environments. To the extent future revisions to these assumptions impact the present value of the existing ARO liability,
a corresponding adjustment is made to the oil and natural gas property balance. Increases in the discounted ARO liability resulting
from the passage of time are reflected as accretion expense in the consolidated statements of operations.
Purchase
Price Allocation
Accounting
for the acquisition of a business requires the allocation of the purchase price to the various assets and liabilities acquired
based on their estimated fair value as of the acquisition date. Various assumptions are made when estimating fair values assigned
to proved and unproved oil and gas properties including: (i) reserves; (ii) production rates; (iii) future operating and development
costs; (iv) future commodity prices, including price differentials; (v) future cash flows; and (vi) a market participant-based
weighted average cost of capital rate. These inputs require significant judgement by management at the time of the valuation.
Revenue
Recognition
Oil
and natural gas revenues are recognized when production volumes are sold to a purchaser at a fixed or determinable price, delivery
has occurred, title has transferred and collectability is reasonably assured. Natural gas revenues are recognized on the basis
of our net working revenue interest. Net deliveries in excess of entitled amounts are recorded as a liability, while net deliveries
lower than entitled amounts are recorded as a receivable.
Equity
Method Investments
We
account for investments where we have the ability to exercise significant influence, but not control, under the equity method
of accounting. Income from equity method investments represents our proportionate share of net income generated by the equity
method investees. Equity method investments are assessed for impairment whenever changes in the facts and circumstances indicate
a loss in value has occurred, if the loss is deemed to be other than temporary. When the loss is deemed to be other than temporary,
the carrying value of the equity method investment is written down to fair value. Differences in the basis of the investments
and the separate net asset value of the investees, if any, are amortized into net income over the remaining useful lives of the
underlying assets.
Non-GAAP
Financial Measures
EBITDA
EBITDA represents cash flow from operating
activities plus interest expense and provision for income taxes. We disclose EBITDA, which is a non-GAAP liquidity measure, because
management believes this metric assists investors and analysts in assessing the ability of our assets to generate sufficient cash
flows to make dividends to our shareholders. You should not consider EBITDA as an alternative to net income (loss), determined
in accordance with GAAP, or as an alternative to cash flows from operating activities, determined in accordance with GAAP, as
an indicator of our cash flows.
EBITDA
has limitations as an analytical tool. Some of these limitations are:
|
●
|
EBITDA
does not reflect cash expenditures or future cash capital expenditures or contractual
commitments;
|
|
|
|
|
●
|
EBITDA
does not reflect changes in, or cash requirements for, our working capital needs;
|
|
|
|
|
●
|
EBITDA
does not reflect the significant interest expense, or the cash requirements necessary
to service interest or principal payments, on our debt;
|
|
|
|
|
●
|
EBITDA
does not reflect
payments made or future requirements for income taxes; and
|
|
|
|
|
●
|
Although
depreciation and amortization are non-cash charges, the assets being depreciated and
amortized will often have to be replaced in the future and EBITDA does not reflect any
cash requirements for such replacements.
|
Because of
these limitations, EBITDA should not be considered in isolation or as a substitute for measures calculated in accordance with
GAAP.
The
following table presents a reconciliation of EBITDA to cash flow from operating activities for each of the periods indicated (in
thousands):
|
|
Historical
|
|
|
|
Six
Months Ended
June 30
,
|
|
|
Year
Ended
December 31,
|
|
|
|
2018
|
|
|
2017
|
|
|
2017
|
|
|
2016
|
|
|
|
(in
thousands, except per share and production data)
|
|
|
|
(unaudited)
|
|
|
(unaudited)
|
|
|
|
|
|
|
|
Reconciliation
of EBITDA to Cash Flow from Operating Activities
|
|
|
|
|
|
|
|
|
|
|
|
|
EBITDA
|
|
$
|
3,818
|
|
|
$
|
2,858
|
|
|
$
|
5,048
|
|
|
$
|
(2,775
|
)
|
Interest
Expense
|
|
|
2,203
|
|
|
|
522
|
|
|
|
1,202
|
|
|
|
367
|
|
Provision
for Income Taxes
|
|
|
—
|
|
|
|
—
|
|
|
|
(74
|
)
|
|
|
—
|
|
Cash
Flow from Operating Activities
|
|
|
1,615
|
|
|
|
2,336
|
|
|
|
3,920
|
|
|
|
(3,142
|
)
|
BUSINESS
General
Carbon Energy Corporation, a Delaware
corporation formed in 2007 and formerly known as Carbon Natural Gas Company, is a growth-oriented, independent oil and natural
gas company engaged in the acquisition, exploration, development and production of oil, natural gas and natural gas liquids properties
in the United States. Our acreage positions provide multiple resource play opportunities and have been delineated largely through
drilling by us, as well as by other industry operators. Our primary business objective is to grow our reserves, production and
cash generated from operations over the long term, while paying, to the extent practicable, a quarterly dividend to our stockholders.
Our
assets, held through our majority-owned subsidiaries, are characterized by stable, long-lived producing properties in the Appalachian
Basin in Kentucky, Ohio, Tennessee, Virginia and West Virginia; the Ventura Basin in California; and the Illinois Basin in Illinois
and Indiana:
|
●
|
We
own 100% of the outstanding shares of Nytis USA, which in turn owns 98.1% of Nytis LLC. Nytis LLC holds the majority interest
in our operating subsidiaries other than Carbon Appalachia and Carbon California, including 47 consolidated partnerships and
17 non-consolidated partnerships.
|
|
●
|
We
hold a 53.92% proportionate share of the profits interest in Carbon California.
|
|
●
|
We
currently hold a 27.24% proportionate share of the profits interest in Carbon Appalachia. Effective upon the Old Ironsides
Buyout (which we intend to fund using proceeds from this offering), we will own 100% of Carbon Appalachia.
|
We have grown through our acquisition
activities since October of 2016. As of June 30, 2018, after giving effect to (i) the increase in Carbon’s ownership of
Carbon California from 17.81% to 56.41% on February 1, 2018 in connection with the exercise of the California Warrant by Yorktown
and the resulting consolidation of Carbon California for financial reporting purposes; (ii) the completion of the Seneca Acquisition
on May 1, 2018 and the resulting decrease in Carbon’s ownership of Carbon California from 56.41% to 53.92%; and (iii) the
increase in Carbon’s ownership of Carbon Appalachia to 100.0% in connection with the Old Ironsides Buyout, we owned working
interests in approximately 8,960 gross wells (8,200 net) and royalty interests in approximately 1,080 wells and had leasehold
positions in approximately 1,110,000 net developed acres and approximately 540,000 net undeveloped acres directly and through
our majority-owned subsidiaries.
The chart below shows a summary of
reserve data as of December 31, 2017 and average daily production data for June 2018 for Carbon California, Carbon Appalachia
and Nytis USA and pro forma for Carbon after giving effect to (i) the increase in Carbon’s ownership of Carbon California
from 17.81% to 56.41% on February 1, 2018 in connection with the exercise of the California Warrant by Yorktown and the resulting
consolidation of Carbon California for financial reporting purposes; (ii) the completion of the Seneca Acquisition on May 1, 2018
and the resulting decrease in Carbon’s ownership of Carbon California from 56.41% to 53.92%; and (iii) the increase in Carbon’s
ownership of Carbon Appalachia to 100.0% in connection with the Old Ironsides Buyout. The below information was prepared pursuant
to the guidelines of the Securities and Exchange Commission for reporting reserves and future net revenue:
|
|
Carbon
California
(1)
|
|
|
Carbon
Appalachia
(2)
|
|
|
Nytis
USA
(3)
|
|
|
Carbon
Pro Forma Including Non-Controlling Interests
(4)
|
|
|
Carbon
Pro Forma Excluding Non-Controlling Interests
(5)
|
|
Proved Reserves (Bcfe)
|
|
|
183.3
|
|
|
|
334.8
|
|
|
|
87.2
|
|
|
|
605.3
|
|
|
|
517.8
|
|
% PDP
|
|
|
42.5
|
%
|
|
|
99.9
|
%
|
|
|
99.9
|
%
|
|
|
82.5
|
%
|
|
|
88.9
|
%
|
% Natural Gas
|
|
|
22.1
|
%
|
|
|
99.7
|
%
|
|
|
93.5
|
%
|
|
|
75.3
|
%
|
|
|
73.9
|
%
|
Standardized Measure
($MM)
(6)
|
|
$
|
172.3
|
|
|
$
|
169.7
|
|
|
$
|
59.3
|
|
|
$
|
401.08
|
|
|
$
|
307.50
|
|
PV-10 ($MM)
(6)
|
|
$
|
172.3
|
|
|
$
|
169.7
|
|
|
$
|
70.2
|
|
|
$
|
412.22
|
|
|
$
|
318.24
|
|
Net Production (Mcfe/d)
(7)
|
|
|
11,765
|
|
|
|
40,673
|
|
|
|
16,394
|
|
|
|
68,832
|
|
|
|
61,123
|
|
Reserve Life (Years)
|
|
|
42.6
|
|
|
|
18.9
|
|
|
|
15.8
|
|
|
|
22.0
|
|
|
|
20.4
|
|
(1)
|
Presents 100%
of Carbon California on a historical basis as of December 31, 2017 for reserve data and for June 2018 for average daily production
data.
|
(2)
|
Presents 100%
of Carbon Appalachia on a historical basis as of December 31, 2017 for reserve data and for June 2018 for average daily production
data.
|
(3)
|
Presents 100%
of Nytis USA and its subsidiaries on a historical basis as of December 31, 2017 for reserve data and for June 2018 for average
daily production data.
|
(4)
|
Presents 100%
of Carbon on a pro forma basis including non-controlling interests in Carbon California and Nytis USA.
|
(5)
|
Presents 100%
of Carbon on a pro forma basis excluding non-controlling interests in Carbon California and Nytis USA.
|
(6)
|
PV-10 is a non-GAAP
financial measure and generally differs from Standardized Measure, the most directly comparable GAAP financial measure. See
“—
PV-10
” for more information.
|
(7)
|
Average net production
is provided for the month of June 2018.
|
During 2017 and the six months ended
June 30, 2018, our capital expenditures consisted principally of oil-related remediation, the Seneca Acquisition, return to production
and recompletion projects in California and the optimization and streamlining of our natural gas gathering and compression facilities
in Appalachia to provide more efficient and lower cost operations and greater flexibility in moving our production to markets
with more favorable pricing. Our current capital expenditure program is focused on the acquisition and development of oil and
natural gas properties in areas where we currently operate.
We believe that our asset and lease
position, combined with our low operating expense structure and technical expertise, provides us with a portfolio of opportunities
for the development of our oil and natural gas properties, including a large inventory of potential return to production, behind
pipe recompletion and proved undeveloped drilling projects. Our growth plan is centered on acquiring, developing, optimizing and
maintaining a portfolio of low risk, long-lived oil and natural gas properties that provide stable cash flows and attractive risk
adjusted rates of return.
Recent
Developments
Investments
in Affiliates
Carbon
Appalachia
Carbon Appalachia was formed in 2016
by us, Yorktown and Old Ironsides to acquire producing assets in the Appalachian Basin in Kentucky, Tennessee, Virginia and West
Virginia. Substantial operations commenced in April 2017. Prior to November 1, 2017, Yorktown held 7.95% of the voting interest
and 7.87% of the profits interest in Carbon Appalachia. On November 1, 2017, Yorktown exercised a warrant, pursuant to which Yorktown
obtained additional shares of common stock in us in exchange for the transfer and assignment by Yorktown of all of its rights
in Carbon Appalachia. Following the exercise of this warrant by Yorktown, we own 26.50% of the voting interest and 27.24% of the
profits interest, and Old Ironsides holds the remainder of the interests, in Carbon Appalachia.
Following the closing of this offering,
we expect to complete the Old Ironsides Buyout. Following the closing of the Old Ironsides Buyout, Carbon Appalachia will be our
wholly-owned subsidiary. Our obligation to consummate the Old Ironsides Buyout is conditioned on the completion of this offering.
In addition, the purchase agreement contains certain closing conditions and termination rights for each of Carbon and Old Ironsides
if the closing of the Old Ironsides Buyout has not occurred on or before October 15, 2018.
Carbon Appalachia’s board of
directors is composed of four members. We currently have the right to appoint one member to the board of directors, and Patrick
R. McDonald, our Chief Executive Officer, is our designee to the board of directors. We currently serve as the manager of Carbon
Appalachia and operate its day-to-day administration pursuant to the terms of the limited liability company agreement of Carbon
Appalachia and the management services agreement between Carbon Appalachia and us, subject to certain approval rights held by
the board of directors of Carbon Appalachia.
As of June 30, 2018, Carbon Appalachia
owned working interests in approximately 5,200 gross wells (4,800 net) and had leasehold positions in approximately 851,000 net
developed acres and approximately 373,000 net undeveloped acres.
Carbon California
Carbon California was formed in 2016
by us, Yorktown and Prudential to acquire producing assets in the Ventura Basin in California. Prior to February 1, 2018, we held
17.81% of the voting and profits interests, Yorktown held 38.59% of the voting and profits interests and Prudential held 43.59%
of the voting and profits interests in Carbon California. On February 1, 2018, Yorktown exercised the California Warrant, pursuant
to which Yorktown obtained additional shares of common stock in us in exchange for the transfer and assignment by Yorktown of
all of its rights in Carbon California. On May 1, 2018, Carbon California closed the Seneca Acquisition. Following the exercise
of the California Warrant by Yorktown and the Seneca Acquisition, we own 53.92% of the voting and profits interests, and Prudential
holds the remainder of the interests, in Carbon California.
Carbon California’s board of directors
is composed of five members. We currently have the right to appoint one member to the board of directors, and Patrick R. McDonald,
our Chief Executive Officer, is our designee to the board of directors. We currently serve as the manager of Carbon California
and operate its day-to-day administration pursuant to the terms of the limited liability company agreement of Carbon California
and the management services agreement between Carbon California and us, subject to certain approval rights held by the board of
directors of Carbon California.
As of June 30, 2018, Carbon California
owned working interests approximately 540 gross wells (340 net) and had leasehold positions in approximately 5,000 net developed
acres and approximately 11,800 net undeveloped acres.
Yorktown Ownership
Following the closing of this offering
and giving effect to the Pro Forma Adjustments, Yorktown will own % of the outstanding shares
of our common stock, assuming the conversion of the Preferred Stock (described herein) to shares of our common stock.
Recent Acquisitions
Historically, we have made acquisitions
through Nytis LLC, Carbon California or Carbon Appalachia, including numerous acquisitions during 2017 and 2018. For acquisitions
by Carbon Appalachia and Carbon California, we typically contribute a portion of the purchase price based on our ownership interest
to fund such acquisitions. In 2018, 2017 and 2016, we contributed an aggregate of $23.9 million to Carbon Appalachia, Carbon California
and Nytis LLC in connection with our acquisition activities. While Carbon Appalachia and Carbon California made other insignificant
acquisitions that are not specifically listed, the acquisitions described below most meaningfully affect the financial condition
of Carbon Appalachia and Carbon California, and, therefore, us. See “—
Acquisition and Divestiture Activities
”
for more information about our acquisitions and divestitures.
|
●
|
On
July 11, 2018, Nytis USA signed a Purchase and Sale Agreement to acquire 54 operated oil and gas wells covering approximately
55,000 gross acres (22,000 net), the associated mineral interests, and gas wells and associated facilities in the Appalachian
Basin for a purchase price of $3.0 million, subject to customary and standard purchase price adjustments (the “
Liberty
Acquisition
”). We contributed the full amount of the purchase price to Nytis USA to fund the purchase price.
The Liberty Acquisition closed on July 11, 2018 with an effective date as of January 1, 2018. The Liberty Acquisition is not
reflected in our pro forma financial statements.
|
|
●
|
In
October 2017, Carbon California signed a Purchase and Sale Agreement to acquire 309 operated and 1 non-operated oil wells
covering approximately 6,800 gross acres (6,500 net), and fee interests in and to certain lands, situated in the Ventura Basin,
together with associated wells, pipelines, facilities, equipment and other property rights for a purchase price of $43.0 million,
subject to customary and standard purchase price adjustments, from Seneca Resources Corporation (the “
Seneca Acquisition
”).
We contributed approximately $5.0 million to Carbon California to fund our portion of the purchase price, with the remainder
funded by Prudential and debt. We raised our $5.0 million through the issuance of 50,000 shares of Preferred Stock to Yorktown.
Upon the completion of this offering, the Preferred Stock will automatically convert into shares of common stock. The conversion
ratio at which the Preferred Stock will convert into common stock is equal to an amount per share of $100 plus all accrued
but unpaid dividends payable in respect thereof (together, the “
Liquidation Preference
”) divided
by the greater of (i) $8.00 per share or (ii) the price that is 15% less than the price per share of shares sold to the public
in this offering. See “
Description of Capital Stock—Preferred Stock
” for more information
on the terms of our Preferred Stock. The Seneca Acquisition closed on May 2018 with an effective date as of October 1, 2017.
|
|
●
|
In September 2017, but effective as of April 1, 2017 for oil and gas assets and September 29, 2017 for the corporate entity, a wholly-owned subsidiary of Carbon Appalachia acquired certain oil and gas assets, including associated mineral interests, certain gathering system assets, associated vehicles and equipment, and all of the outstanding shares of Cranberry Pipeline Corporation, a Delaware corporation (“
Cranberry Pipeline
”), for a purchase price of $41.3 million from Cabot Oil & Gas Corporation (the “
Cabot Acquisition
”). We contributed approximately $2.9 million to Carbon Appalachia to fund this acquisition. Cranberry Pipeline operates certain pipeline assets.
|
|
●
|
In August 2017, but effective as of May 1, 2017, a wholly-owned subsidiary of Carbon Appalachia acquired 865 oil and natural gas wells on approximately 320,300 acres, the associated mineral interests, and gas wells and associated facilities in the Appalachian Basin for a purchase price of approximately $21.5 million from EnerVest Energy Institutional Fund XII-A, L.P., EnerVest Energy Institutional Fund XII-WIB, L.P., EnerVest Energy Institutional Fund XII-WIC, L.P. and EnerVest Operating, L.L.C. (the “
EnerVest Acquisition
”). We contributed approximately $3.7 million to Carbon Appalachia to fund this acquisition.
|
|
●
|
In April 2017, but effective as of February 1, 2017 for oil and gas assets and April 3, 2017 for the corporate entity, a wholly-owned subsidiary of Carbon Appalachia acquired all of the issued and outstanding shares of Coalfield Pipeline Company, a Tennessee corporation (“
Coalfield Pipeline
”), and all of the membership interest in Knox Energy, LLC, a Tennessee limited liability company (“
Knox Energy
”), for a purchase price of $20.0 million from CNX Gas Company, LLC (the “
CNX Acquisition
”). We contributed approximately $0.2 million to Carbon Appalachia to fund this acquisition. Coalfield Pipeline and Knox Energy operate certain pipeline assets and 203 oil and natural gas wells on approximately 142,600 acres and own the associated mineral interests and vehicles and equipment.
|
|
●
|
In
February 2017, but effective as of January 1, 2017, Carbon California acquired 43 oil wells on approximately 1,400 gross acres
(1,400 net), the associated mineral interests and gas wells and vehicles and equipment in the Ventura Basin for a purchase
price of approximately $4.5 million from Mirada Petroleum, Inc. (the “
Mirada Acquisition
”). We were
not required to contribute any cash to Carbon California to fund this acquisition.
|
|
●
|
In
February 2017, but effective as of November 1, 2016, Carbon California acquired 191 oil wells on approximately 8,900 gross
acres (8,900 net), the associated mineral interests, oil and gas wells and associated facilities, a field office building,
land and vehicles and equipment in the Ventura Basin for a purchase price of $34.0 million from California Resources Petroleum
Corporation and California Resources Production Corporation (the “
CRC Acquisition
”). We were not
required to contribute any cash to Carbon California to fund this acquisition.
|
Reverse
Stock Split
Our stockholders and board of directors
approved a reverse stock split of our common stock, effective March 15, 2017, pursuant to which every 20 shares of issued and
outstanding common stock became one share of common stock and no fractional shares were issued. All references to the number of
shares of common stock and per share amounts give retroactive effect to the reverse stock split for all periods presented. In
connection with the reverse stock split, the number of authorized shares decreased from 200,000,000 to 10,000,000. On June 1,
2018, we increased the number of authorized shares of our common stock from 10,000,000 to 35,000,000.
Preferred
Stock Issuance to Yorktown
In connection with the closing of the
Seneca Acquisition, we raised $5.0 million through the issuance of 50,000 shares of Preferred Stock to Yorktown. Upon the completion
of this offering, the Preferred Stock will automatically convert into shares of common stock. The conversion ratio at which the
Preferred Stock will convert into common stock is equal to the Liquidation Preference divided by the greater of (i) $8.00 per
share or (ii) the price that is 15% less than the price per share of shares sold to the public in this offering. See “
Description
of Capital Stock—Preferred Stock
” for more information on the terms of our preferred stock.
Business Strategies
Our
primary business objective is to create stockholder value through consistent growth in cash flows, production and reserves through
drilling on our existing oil and gas properties and the acquisition of complementary properties. We focus on the development of
our existing leaseholds, which consist primarily of low risk, repeatable resource plays. We invest significantly in technical
staff and geological and engineering technology to enhance the value of our properties.
We
intend to accomplish our objective by executing the following strategies:
|
●
|
Capitalize
on the development of our oil and gas properties.
At the closing of this offering, our assets will consist of oil and
gas properties in the Appalachian, Ventura and Illinois Basins. We aim to continue to safely optimize returns from our existing
producing assets by using established technologies to maximize recoveries of in-place hydrocarbons. We expect the production
from our properties will increase as we continue to develop and optimize our properties by capitalizing on new technology
to enhance our production base.
|
|
●
|
Acquire complementary
properties
.
A
core part of our strategy is to grow our oil and gas asset base through the acquisition
of properties in the vicinity of our existing properties that feature similar reserve
mixes and production profiles. During 2017 and 2018, we partnered with Prudential to
finance the acquisitions of producing properties in the Ventura Basin through Carbon
California and with Old Ironsides to finance the acquisitions of producing properties
in the Appalachian Basin through Carbon Appalachia. We own a majority interest in Carbon
California and, upon completion of the Old Ironsides Buyout, will own 100% of Carbon
Appalachia and we plan to continue to aggregate complementary properties through these
entities, Nytis USA or other co-investment vehicles.
|
|
●
|
Reduce
operating costs through the aggregation and integration of acquired assets in our expanding operational footprint in both
the Appalachian and the Ventura Basins.
We plan to continue to realize economies of scale and efficiency gains from spreading
our fixed operating costs over a larger asset base. Historically, we have targeted overhead and well maintenance cost reductions,
field-level optimization and gathering system reconfigurations.
|
|
●
|
Acquire
and develop reserves in the form of a diverse mix of commodities with crude oil the primary objective in California and natural
gas the primary objective in Appalachia.
We believe that a diverse commodity mix will provide us with commodity optionality,
which will allow us to direct capital spending to develop the commodity that offers the best return on investment at the time.
|
|
●
|
Manage commodity
price exposure through an active hedging program.
We
maintain a hedging program designed to reduce exposure to fluctuations in commodity prices.
As of June 30, 2018, we had outstanding natural gas hedges of approximately 1.7 MMBtu
for the six months ended June 30, 2018 at an average price of $3.00 per MMBtu and approximately
2.6 MMBtu for 2019 at an average price of $2.86 per MMBtu. In addition, as of June 30,
2018, we had outstanding oil hedges of 35,500 barrels for 2018 at an average price of
$53.23 per barrel and 48,000 barrels for 2019 at an average price of $53.76 per barrel.
In addition to our hedging program, we also maintain active hedging programs at Carbon
California and Carbon Appalachia.
|
Competitive
Strengths
We
believe the following competitive strengths will allow us to successfully execute our business strategies and achieve our primary
business objective:
|
●
|
Significant
diversified portfolio of long-lived, low-decline reserves largely held by production.
As of December 31, 2017, after giving
effect to the Pro Forma Adjustments, the estimated proved oil, natural gas and NGL reserves attributable to interests in our
underlying acreage and that of Carbon California and Carbon Appalachia were 605.3 Bcfe (82.5% proved developed producing,
75.3% natural gas). During the six months ended June 30, 2018, our average daily production and that of Carbon California
and Carbon Appalachia was 72.08 MMcfe/d, resulting in an average reserve life of 22.0 years. As of June 30, 2018, we, Carbon
California and Carbon Appalachia owned interests in approximately 1.9 million gross (1.7 million net) acres in the Appalachian,
Illinois and Ventura Basins, of which over 73% was held by production with no capital obligations.
|
|
●
|
Experienced
and proven management team.
The members of our management team have an average of over 25 years of oil and gas experience
and an extensive track record of creating value for stockholders and business partners. Our management and operational teams
have extensive knowledge of the Appalachian, Illinois and Ventura Basins. We believe our management’s experience in
managing capital programs at major oil and gas companies, regional knowledge of our assets and ability to identify accretive
acquisitions will allow us to continue to grow our production, reserves and dividends.
|
|
●
|
Financial
flexibility to fund expansion.
In connection with the closing of this offering, we intend to enter into the New Revolving
Credit Facility to replace our Existing Credit Facility and the CAE Credit Facility at the closing of this offering. The New
Revolving Credit Facility will have an initial borrowing base of $100 million. We will have sufficient borrowing capacity
under our New Revolving Credit Facility and access to other sources of liquidity to possess the financial capacity to grow
the company. Subsequent to the closing of this offering, we expect to use our New Revolving Credit Facility for general corporate
purposes, including drilling and completion activities and acquisitions.
|
|
●
|
Benefit from low cost
operations.
The
shallow nature of our drilling activities and producing wells results in relatively low
lease operating costs. Lease operating costs for the six months ended June 30, 2018 averaged
$1.11/Mcfe, $1.10/Mcfe and $16.70/Boe for us, Carbon Appalachia and Carbon California,
respectively, compared to the period ended December 31, 2017 when the lease operating
costs averaged $1.13/Mcfe, $0.98/Mcfe and $16.71/Boe.
|
|
●
|
Scalable
business model.
We believe that our business structure gives us a relative advantage to grow through acquisitions without
significantly increasing our cost structure. Our land, accounting, engineering, geology, information technology and business
development departments have a scalable business model that allows us to manage our existing assets and absorb additional
acquisitions at minimal additional costs.
|
|
●
|
Benefit from favorable realized commodity
pricing in both the Appalachian and Ventura Basins.
In
the Appalachian Basin, we and Carbon Appalachia averaged a minimal pricing differential of $0.249/MMbtu and $0.407/MMbtu during
the six months ended June 30, 2018 and the period ended December 31, 2017, respectively, as we and Carbon Appalachia targeted
delivery of our and their gas to interstate pipelines that exit from the southern region of the Appalachian Basin. In the
Ventura Basin, the price per barrel of oil during the six months ended June 30, 2018 and the period ended December 31, 2017
for our production yielded approximately 106% of the NYMEX WTI benchmark price as a result of its proximity to the southern
California refining market and the API gravity of its produced oil.
|
Operational
Areas
Our
oil and gas properties are located in the Appalachia, Illinois and Ventura Basins.
Appalachian
Basin
As of June 30, 2018, we directly owned
working interests in approximately 3,200 gross wells (3,000 net) and royalty interests located in Kentucky, Ohio, Tennessee and
West Virginia, and had leasehold positions in approximately 189,000 net developed acres and approximately 221,000 net undeveloped
acres. As of June 30, 2018, net production was approximately 16,400 Mcfe per day. These interests are located in the Berea Sandstone,
Devonian Shale, Seelyville Coal Seam and Lower Huron Shale formations and other zones which produce oil and natural gas.
As of June 30, 2018, Carbon Appalachia
owned working interests in approximately 5,200 gross wells (4,800 net) located in Kentucky, Tennessee, Virginia and West Virginia,
and had leasehold positions in approximately 851,000 net developed acres and approximately 373,000 net undeveloped acres. As of
June 30, 2018, net production was approximately 48,000 Mcfe per day. These interests are located in the Devonian Shale, Chattanooga
Shale, Lower Huron Shale, Monteagle and Big Line formations and other zones which produce oil and natural gas.
The chart below shows a summary of
our and our 27.24% proportionate share in Carbon Appalachia’s reserve data in the Appalachian Basin as of and for the year
ended December 31, 2017 and average daily production data for June 2018:
|
|
Estimated
Total Proved Reserves
|
|
|
Average
Net Daily
|
|
|
Average
|
|
|
|
Oil
(MMBbls)
|
|
|
Natural
Gas
(Bcf)
|
|
|
Total
(Bcfe)
|
|
|
Production
(Mcfe/D)
|
|
|
Reserve
Life (years)
|
|
Carbon
|
|
|
0.9
|
|
|
|
78.7
|
|
|
|
84.2
|
|
|
|
16,394
|
|
|
|
17.6
|
|
Carbon Appalachia
(1)
|
|
|
0.1
|
|
|
|
90.8
|
|
|
|
91.2
|
|
|
|
48,300
|
|
|
|
20.7
|
|
Total
|
|
|
1.0
|
|
|
|
169.5
|
|
|
|
175.4
|
|
|
|
64,694
|
|
|
|
19.1
|
|
(1)
|
Following
the closing of this offering, we expect to complete the Old Ironsides Buyout. Following the closing of the Old Ironsides Buyout,
Carbon would own 100% of the issued and outstanding ownership interests in Carbon Appalachia, and Carbon Appalachia would
become a wholly-owned subsidiary of Carbon. Our proportionate share in Carbon Appalachia shown in this table reflects our
proportionate share on December 31, 2017.
|
Ventura
Basin
As of June 30, 2018, Carbon California
owned working interests in approximately 540 gross wells (340 net) located in California and had leasehold positions in approximately
5,000 net developed acres and approximately 11,800 net undeveloped acres. As of June 30, 2018, net oil and natural gas sales
were approximately 9,000 Mcfe per day. These interests are located in the Miocene-Age formation and other zones which produce
oil and natural gas.
The chart below shows a summary of
our 17.81% proportionate share in Carbon California’s reserve data in the Ventura Basin as of and for the year ended December
31, 2017 and average daily production data for June 2018:
|
|
Estimated Total Proved Reserves
|
|
|
Average Net
Daily
|
|
|
Average
|
|
|
|
Oil
(MMBbls)
|
|
|
NGLs (MMBbls)
|
|
|
Natural Gas
(Bcf)
|
|
|
Total
(Bcfe)
|
|
|
Production
(Mcfe/D)
|
|
|
Reserve
Life (years)
|
|
Carbon
California
(1)
|
|
|
1.6
|
|
|
|
0.2
|
|
|
|
3.0
|
|
|
|
14.1
|
|
|
|
5,621
|
|
|
|
30.4
|
|
(1)
|
Effective
as of February 1, 2018, our proportionate share in Carbon California increased to 56.41%. Effective as of May 1, 2018, our
proportionate share in Carbon California decreased to 53.92%. Our proportionate share in Carbon California shown in this table
reflects our ownership interest on December 31, 2017.
|
Illinois
Basin
As of June 30, 2018, we directly owned
working interests in 58 gross (29 net) coalbed methane wells in the Illinois Basin and had a leasehold position in approximately
1,900 net developed acres and approximately 58,000 net undeveloped acres. As of June 30, 2018, net natural gas sales were approximately
500 Mcf per day. These interests are located in the Seelyville Coal Seam formation and other zones which produce oil and natural
gas.
The chart below shows a summary of
our reserve data in the Illinois Basin as of and for the year ended December 31, 2017 and average daily production data for June
2018:
|
|
Estimated Total Proved Reserves
|
|
|
Average
Net Daily
|
|
|
Average
|
|
|
|
Oil
(MMBbls)
|
|
|
Natural Gas
(Bcf)
|
|
|
Total
(Bcfe)
|
|
|
Production
(Mcfe/D)
|
|
|
Reserve
Life (years)
|
|
Carbon
|
|
|
-
|
|
|
|
0.4
|
|
|
|
0.4
|
|
|
|
465
|
|
|
|
2.5
|
|
Acquisition
and Divestiture Activities
We
pursue acquisitions for investment which meet our criteria for investment returns and which are consistent with our field development
strategy. The acquisition of properties in our existing operating areas enable us to leverage our cost control abilities, technical
expertise and existing land and infrastructure positions. Our acquisition program is focused on acquisitions of properties which
have relatively low base decline, preferable field development opportunities and undeveloped acreage. The following is a summary
of our acquisitions and divestitures for 2018, 2017 and 2016. See “
Management’s Discussion and Analysis of Financial
Condition and Results of Operations
” and Note 4 to the consolidated financial statements for more information on
our acquisitions.
Old
Ironsides Buyout
. We intend to use a portion of the proceeds from this offering to complete the Old Ironsides Buyout. Following
the closing of the Old Ironsides Buyout, Carbon Appalachia will be our wholly-owned subsidiary. See “
—Investments
in Affiliates
” for more information on the terms of the Old Ironsides Buyout.
Acquisitions
– Appalachian Basin
Liberty Acquisition.
On July
11 2018, Nytis USA signed a Purchase and Sale Agreement to acquire 54 operated oil and gas wells covering approximately 55,000
gross acres (22,000 net), the associated mineral interests, and gas wells and associated facilities in the Appalachian Basin for
a purchase price of $3.0 million, subject to customary and standard purchase price adjustments (the “
Liberty Acquisition
”).
We contributed the full amount of the purchase price to Nytis USA to fund the purchase price. The Liberty Acquisition closed on
July 11, 2018 with an effective date as of January 1, 2018. The Liberty Acquisition is not reflected in our pro forma financial
statements.
Our management’s review of the
estimated proved reserves relating to the Liberty Acquisition indicated estimated proved reserves of 0.306 MMBoe, with an estimated
proved reserve life index of approximately 39 years, as of December 31, 2017, which estimated proved reserves were determined
using $51.338 per barrel of oil and $2.976 per MMBtu of gas. Such prices were determined using the average of the historical first-day-of-the-month
prices for the twelve months ended December 31, 2017 in accordance with SEC guidelines. Approximately 86.3% of these reserves
were oil, approximately 100% were proved developed and approximately 83% were proved developed producing at December 31, 2017.
Management’s estimate of the average daily production for June 2018 from the Liberty assets was approximately 86 Boe, which
was comprised of approximately 85% crude oil and 15% natural gas.
Reserve engineering is a complex and
subjective process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact way, and
the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation
and judgment. As a result, estimates prepared by one engineer may vary from those prepared by another. Estimates of proved reserves
for our oil and gas properties as of December 31, 2018 will be prepared by CGA using the information available at that time.
Upon completion of their review, the estimate of the proved reserves for our oil and gas properties as of December 31, 2018
will be different from the estimate of the proved reserves for our oil and gas properties as of December 31, 2017 shown above,
and the estimates of proved reserves relating to the acquisition of oil and gas properties referred to above as the Liberty Acquisition
as of December 31, 2018 will be different from our management’s estimates of such reserves as of December 31, 2017
as described above.
Cabot
Acquisition
. On September 29, 2017, but effective April 1, 2017 for oil and gas properties and September 29, 2017 for the
corporate entity, a wholly-owned subsidiary of Carbon Appalachia completed the acquisition of natural gas producing properties,
including associated mineral interests, certain gathering system assets, associated vehicles and equipment, and all of the outstanding
shares of Cranberry Pipeline, which operates certain pipeline assets, located predominantly in the state of West Virginia from
Cabot Oil & Gas Corporation. The purchase price was $41.3 million, subject to normal and customary adjustments. We contributed
approximately $2.9 million to Carbon Appalachia to fund this acquisition. The acquired assets consisted of the following:
|
●
|
Approximately
3,000 natural gas wells and over 3,100 miles of associated natural gas gathering pipelines and compression facilities. As
of December 31, 2017, these wells were producing approximately 33,300 net Mcfe per day (99.7% natural gas).
|
|
●
|
Approximately
701,700 net acres of oil and natural gas mineral interests.
|
|
●
|
Average
working and net revenue interest of the acquired wells of 95.2% and 85.3%, respectively.
|
|
●
|
Estimated
proved developed producing reserves at December 31, 2017 of approximately 279.4 Bcfe (99.7% natural gas).
|
EnerVest
Acquisition
. On August 15, 2017, but effective as of May 1, 2017, a wholly-owned subsidiary of Carbon Appalachia completed
the acquisition of natural gas producing properties, the associated mineral interests, gas wells and associated facilities and
vehicles and equipment located predominantly in the state of West Virginia from EnerVest Energy Institutional Fund XII-A, L.P.,
EnerVest Energy Institutional Fund XII-WIB, L.P., EnerVest Energy Institutional Fund XII-WIC, L.P. and EnerVest Operating, L.L.C.
The purchase price was $21.5 million, subject to normal and customary adjustments. We contributed approximately $3.7 million to
Carbon Appalachia to fund this acquisition. The acquired assets consisted of the following:
|
●
|
Approximately
865 oil and natural gas wells and over 310 miles of associated natural gas gathering pipelines and compression facilities.
As of December 31, 2017, these wells were producing approximately 7,555 net Mcfe per day (100% natural gas).
|
|
●
|
Approximately
320,325 net acres of oil and natural gas mineral interests.
|
|
●
|
Average
working and net revenue interest of the acquired wells of 86.6% and 83.0%, respectively.
|
|
●
|
Estimated
proved developed producing reserves at December 31, 2017 of approximately 35.6 Bcfe (100% natural gas).
|
CNX
Acquisition
. On April 3, 2017, but effective as of February 1, 2017 for oil and gas properties and April 3, 2017 for the corporate
entity, a wholly-owned subsidiary of Carbon Appalachia completed the acquisition of all of the issued and outstanding shares of
Coalfield Pipeline and all of the membership interest in Knox Energy from CNX Gas Company, LLC. Coalfield Pipeline and Knox Energy
own producing assets in Tennessee. The purchase price for the acquired assets was $20.0 million. We contributed approximately
$0.2 million to Carbon Appalachia to fund this acquisition. The acquired assets consisted of the following:
|
●
|
Approximately
203 oil and natural gas wells and over 180 miles of associated natural gas gathering pipelines and compression facilities.
As of December 31, 2017, these wells were producing approximately 3,608 net Mcfe per day (93.5% natural gas).
|
|
●
|
Approximately
142,625 net acres of oil and natural gas mineral interests.
|
|
●
|
Average
working and net revenue interest of the acquired wells of 74.3% and 64.3%, respectively.
|
|
●
|
Estimated
proved developed producing reserves at December 31, 2017 of approximately 19.3 Bcfe (93.5% natural gas).
|
EXCO
Acquisition.
In October 2016, Nytis LLC completed an acquisition consisting of producing natural gas wells and natural gas
gathering facilities. The purchase price for the acquired assets was $9.0 million, subject to customary closing adjustments, plus
certain assumed obligations, from Exco Production Company (WV), LLC, BG Production Company (WV), LLC and Exco Resources (PA) LLC
(the “
EXCO Acquisition
”). We contributed approximately $9.0 million to Nytis USA for it to fund its
portion of the purchase price to Nytis LLC to fund this acquisition. The acquired assets consisted of the following:
|
●
|
Approximately
2,250 natural gas wells and over 1,120 miles of associated natural gas gathering pipelines and compression facilities. As
of December 31, 2017, these wells were producing approximately 13,070 net Mcfe per day (93.5% natural gas).
|
|
●
|
Approximately
411,372 net acres of oil and natural gas mineral interests.
|
|
●
|
Average
working and net revenue interest of the acquired wells of 92% and 77.3%, respectively.
|
|
●
|
Estimated
proved developed producing reserves at December 31, 2017 of approximately 51.8 Bcfe (93.5% natural gas).
|
Acquisitions
– Ventura Basin
Seneca Acquisition.
On October
20, 2017, Carbon California entered into a Purchase and Sale Agreement to acquire operated and non-operated oil wells covering
lands, and fee interests in and to certain lands situated in the Ventura Basin, together with associated wells, pipelines, facilities,
equipment and other property rights from Seneca Resources Corporation. The purchase price was $43.0 million, subject to customary
and standard purchase price adjustments. We contributed approximately $5.0 million to Carbon California to fund our portion of
the purchase price, with the remainder funded by Prudential and debt. We raised our $5.0 million through the issuance of 50,000
shares of Preferred Stock to Yorktown. Upon the completion of this offering, the Preferred Stock will automatically convert into
shares of common stock. The conversion ratio at which the Preferred Stock will convert into common stock is equal to the Liquidation
Preference divided by the greater of (i) $8.00 per share or (ii) the price that is 15% less than the price per share of shares
sold to the public in this offering. See “
Description of Capital Stock—Preferred Stock
” for more
information on the terms of our Preferred Stock. The Seneca Acquisition closed on May 2018 with an effective date as of October
1, 2017.
Our management’s review of the
estimated proved reserves relating to the Seneca Acquisition indicated estimated proved reserves of 17.3 MMBoe, with an estimated
proved reserve life index of approximately 47 years, as of December 31, 2017, which estimated proved reserves were determined
using $51.34 per barrel of oil and $2.976 per MMBtu of gas. Such prices were determined using the average of the historical first-day-of-the-month
prices for the twelve months ended December 31, 2017 in accordance with SEC guidelines. Approximately 77% of these reserves were
oil and NGLs, approximately 66% were proved developed and approximately 39% were proved developed producing as of December 31,
2017. Management’s estimate of the average daily production for June 2018 from the Seneca assets was approximately 915 Boe,
which was comprised of approximately 70% crude oil, 8% NGLs and 22% natural gas. In the six months ended June 30, 2018, the price
per barrel of oil for our production from the Seneca assets represented an approximately 107% premium to the NYMEX West Texas
Intermediate (“
NYMEX WTI
”) benchmark price.
Reserve
engineering is a complex and subjective process of estimating underground accumulations of oil and natural gas that cannot be
measured in an exact way, and the accuracy of any reserve estimate is a function of the quality of available data and of engineering
and geological interpretation and judgment. As a result, estimates prepared by one engineer may vary from those prepared by another.
Estimates of proved reserves for our oil and gas properties as of December 31, 2018 will be prepared by CGA using the information
available at that time. Upon completion of their review, the estimate of the proved reserves for our oil and gas properties as
of December 31, 2018 will be different from the estimate of the proved reserves for our oil and gas properties as of December
31, 2017 shown above, and the estimates of proved reserves relating to the acquisition of oil and gas properties referred to above
as the Seneca Acquisition as of December 31, 2018 will be different from our management’s estimates of such reserves
as of December 31, 2017 as described above.
Mirada
Acquisition.
On February 15, 2017, but effective as of January 1, 2017, Carbon California completed the acquisition of oil
and gas leases, the associated mineral interests and gas wells and vehicles and equipment from Mirada Petroleum, Inc. The purchase
price was $4.5 million. We were not required to contribute any cash to Carbon California to fund this acquisition. The acquired
assets consisted of the following:
|
●
|
Approximately
43 oil wells. As of December 31, 2017, these wells were producing approximately 101 net Boe per day (46% oil and natural gas
liquids).
|
|
●
|
Approximately
1,400 net acres of oil and natural gas mineral interests.
|
|
●
|
Average
working and net revenue interest of the acquired wells of 98.3% and 76.5%, respectively.
|
|
●
|
Estimated
proved developed producing reserves at December 31, 2017 of approximately 32,847 Boe (46% oil and natural gas liquids).
|
CRC
Acquisition.
On February 15, 2017 Carbon California also completed the acquisition of oil and gas leases, the associated mineral
interests, oil and gas wells and associated facilities, a field office building, land and vehicles and equipment from California
Resources Petroleum Corporation and California Resources Production Corporation. The purchase price was $34.0 million. We were
not required to contribute any cash to Carbon California to fund this acquisition. The acquired assets consisted of the following:
|
●
|
Approximately
191 oil wells. As of December 31, 2017, these wells were producing approximately 638 net Boe per day (77% oil and natural
gas liquids).
|
|
●
|
Approximately
8,939 net acres of oil and natural gas mineral interests.
|
|
●
|
Average
working and net revenue interest of the acquired wells of 99.9% and 92.4%, respectively.
|
|
●
|
Estimated
proved developed producing reserves at December 31, 2017 of approximately 203,355 Boe (77% oil and natural gas liquids).
|
Equity
Investments in Affiliates
Carbon
Appalachia
Our
Carbon Appalachia Ownership Interests
We
own 26.50% of the voting interest and 27.24% of the profits interest in Carbon Appalachia through our ownership of Class A Units
and Class C Units in Carbon Appalachia. In addition, we own 100% of the Class B Units in Carbon Appalachia, which do not currently
participate in distributions from Carbon Appalachia. Pursuant to the terms of the Amended and Restated Limited Liability Company
Agreement of Carbon Appalachia, once the holders of the Class A Units have received a full return of their aggregate capital contributions
plus an internal rate of return of 10%, the Class B Units begin participating in distributions from Carbon Appalachia, with 80%
of distributions allocated to the holders of the Class A Units and Class C Units and 20% of the distributions allocated to the
holders of Class B Units. Carbon Appalachia currently intends to make quarterly distributions in 2018 to its members, including
us.
Following the closing of this offering,
we expect to complete the Old Ironsides Buyout. Following the closing of the Old Ironsides Buyout, we would own 100% of the issued
and outstanding ownership interests in Carbon Appalachia, and Carbon Appalachia would become a wholly-owned subsidiary of us.
In addition, the purchase agreement contains certain closing conditions and termination rights for each of Carbon and Old Ironsides
if the closing of the Old Ironsides Buyout has not occurred on or before October 15, 2018.
Carbon
Appalachia Credit Facility
In connection and concurrently with
the CNX Acquisition, Carbon Appalachia Enterprises entered into the CAE Credit Facility, which has been used to partially fund
each of Carbon Appalachia’s acquisitions. The current borrowing base under the CAE Credit Facility is $50.0 million, which
increased to $70.0 million on April 30, 2018. We are not a guarantor of the CAE Credit Facility. As of June 30, 2018, there was
approximately $38.0 million outstanding under the CAE Credit Facility. The ability of Carbon Appalachia to make distributions
to its owners, including us, is dependent upon the terms of the CAE Credit Facility, which currently prohibits distributions unless
they are agreed to by the lender. See Note 5 to the Carbon Appalachia consolidated financial statements.
In
connection with the closing of this offering, we intend to enter into the New Revolving Credit Facility to replace our Existing
Credit Facility and the CAE Credit Facility at the closing of this offering. The New Revolving Credit Facility will contain a
letters of credit sub-facility up to $1.5 million and will have an initial borrowing base of $100 million. The outstanding debt
under our Existing Credit Facility and the CAE Credit Facility will be assigned to the lender syndicate under the New Revolving
Credit Facility, and, following the closing of this offering, our outstanding debt under the New Revolving Credit Facility will
be $ . Entry into the New Revolving Credit Facility will be conditioned upon, among
other things, the completion of this offering.
Carbon
Appalachia Accounting Treatment
Based
on our ownership of 26.50% of the voting interest and 27.24% of the profits interest, our ability to appoint a member to the board
of directors and our role as manager of Carbon Appalachia, we account for our investment in Carbon Appalachia under the equity
method of accounting as we believe we can exert significant influence on Carbon Appalachia. We use the hypothetical liquidation
at book value (“
HLBV
”) method to determine our share of profits or losses in Carbon Appalachia and adjust
the carrying value of our investment accordingly. The HLBV method is a balance-sheet approach that calculates the amount each
member of an entity would receive if the entity were liquidated at book value at the end of each measurement period. The change
in the allocated amount to each member during the period represents the income or loss allocated to that member. From the commencement
of operations on April 3, 2017 through December 31, 2017, Carbon Appalachia generated net income, of which our share is approximately
$1.1 million. Upon the successful completion of this offering and closing of the Old Ironsides Buyout, Carbon Appalachia would
become a wholly-owned subsidiary and would be consolidated for financial reporting purposes.
Carbon
California
Our
Carbon California Ownership Interests
We
own 53.92% of the voting and profits interests in Carbon California through our ownership of Class A Units and Class B Units in
Carbon California. The Class A Units and Class B Units participate pro rata in distributions from Carbon California. Carbon California
does not currently pay distributions to its members, including us.
Carbon
California Senior Revolving Notes and Subordinated Notes
In connection with the CRC Acquisition,
Carbon California (i) entered into a Note Purchase Agreement (the “
Note Purchase Agreement
”) for the
issuance and sale of Senior Secured Revolving Notes to Prudential Legacy Insurance Company of New Jersey and Prudential Insurance
Company of America with a revolving borrowing capacity of $25.0 million (the “
Senior Revolving Notes
”)
which mature on February 15, 2022 and (ii) entered into a Securities Purchase Agreement (the “
Securities Purchase
Agreement
”) with Prudential for the issuance and sale of $10.0 million of Senior Subordinated Notes (the “
Subordinated
Notes
”) due February 15, 2024. We are not a guarantor of the Senior Revolving Notes or the Subordinated Notes. The
closing of the Note Purchase Agreement and the Securities Purchase Agreement on February 15, 2017, resulted in the sale and issuance
by Carbon California of (i) Senior Revolving Notes in the principal amount of $10.0 million and (ii) Subordinated Notes in the
original principal amount of $10.0 million. The maximum principal amount available under the Senior Revolving Notes is based upon
the borrowing base attributable to Carbon California’s proved oil and gas reserves which is to be determined at least semi-annually.
The current borrowing base is $41.0 million. There was $38.5 million of indebtedness outstanding thereunder as of June 30, 2018.
On May 1, 2018, Carbon California entered into a securities purchase agreement with Prudential, which resulted in (i) the issuance
and sale of $3.0 million of Senior Subordinated Notes due February 15, 2024 and (ii) the issuance of 585 Class A units of Carbon
California as partial consideration for the Subordinated Notes. The ability of Carbon California to make distributions to its
owners, including us, is dependent upon the terms of the Note Purchase Agreement and Securities Purchase Agreement, which currently
prohibit distributions unless they are agreed to by Prudential Legacy Insurance Company of New Jersey and Prudential Insurance
Company of America.
Borrowings under the Senior Revolving Notes
and net proceeds from the Subordinated Notes issuances were used to fund the Mirada Acquisition, the CRC Acquisition and the Seneca
Acquisition. Additional borrowings from the Senior Revolving Notes may be used to fund field development projects and to fund future
complementary acquisitions and for general working capital purposes of Carbon California. See Note 5 to the Carbon California financial
statements.
As of December 31, 2017 and March 31,
2018, Carbon California was in breach of its covenants; however, it obtained a waiver with respect to compliance with such covenants
as of December 31, 2017 and March 31, 2018. As of June 30, 2018, Carbon California was in compliance with its financial covenants.
Management expects Carbon California will be in compliance with its covenants during the remainder of 2018. See
Liquidity and
Management’s Plans
within Note 1 to the Carbon California financial statements.
Carbon California Accounting Treatment
Effective February 1, 2018, Carbon California
became consolidated for financial reporting purposes. From February 15, 2017 through January 31, 2018, based on our ownership of
17.81% of the voting and profits interests during that period, our ability to appoint a member to the board of directors and our
role of manager of Carbon California, we accounted for our investment in Carbon California under the equity method of accounting
as we believed we could exert significant influence. We used the HLBV method to determine our share of profits or losses in Carbon
California and adjust the carrying value of our investment accordingly. From the commencement of operations on February 15, 2017
through January 31, 2018, Carbon California incurred a net loss, of which our share (as a holder of Class B units for that period)
was zero.
Crawford County Gas Gathering Company
We have a 50% interest in Crawford
County Gas Gathering Company, LLC (“
CCGGC
”) which owns and operates pipelines and related gathering
and treatment facilities which service our natural gas production in the Illinois Basin. We account for our investment in CCGGC
under the equity method of accounting, and our share of income or loss is recognized in our consolidated statement of operations.
During the six months ended June 30, 2018 and 2017, we recorded equity method income of approximately $45,000 and $0, respectively,
related to this investment. During the twelve months ended December 31, 2017 and 2016, we recorded equity method income of approximately
$37,000 and equity method loss of approximately $17,000, respectively, related to this investment. During the year ended December
31, 2017, we received cash distributions from CCGGC of approximately $68,000. We did not receive any cash distributions from CCGGC
for the six months ended June 30, 2018.
Risk Management
We and hedge a portion of forecasted production
to reduce exposure to fluctuations in the prices of oil and natural gas and provide long-term cash flow predictability to pay dividends
or distributions, respectively, service debt and manage our business. By removing a portion of the price volatility associated
with future production, we expect to mitigate, but not eliminate, the potential effects of variability in cash flow from operations
due to adverse fluctuations in commodity prices.
While there are many different types of
derivatives available, we generally utilize swaps and collars designed to manage price risk more effectively.
The following tables reflect our, Carbon
Appalachia’s and Carbon California’s outstanding derivative hedges as of June 30, 2018:
Carbon Energy Corporation
|
|
Natural
Gas Swaps
|
|
|
Natural
Gas Collars
|
|
|
Oil
Swaps
|
|
|
|
|
|
|
Weighted
|
|
|
|
|
|
Weighted
|
|
|
|
|
|
Weighted
|
|
|
|
|
|
|
Average
|
|
|
|
|
|
Average Price
|
|
|
|
|
|
Average
|
|
Year
|
|
MMBtu
|
|
|
Price
|
|
|
MMBtu
|
|
|
Range
|
|
|
Bbl
|
|
|
Price
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2018
|
|
|
1,740,000
|
|
|
$
|
3.00
|
|
|
|
-
|
|
|
|
-
|
|
|
|
35,500
|
|
|
$
|
53.41
|
|
2019
|
|
|
2,596,000
|
|
|
$
|
2.86
|
|
|
|
-
|
|
|
|
-
|
|
|
|
48,000
|
|
|
$
|
53.76
|
|
Carbon Appalachia
(1)
|
|
Natural
Gas Swaps
|
|
|
Natural
Gas Collars
|
|
|
Oil
Swaps
|
|
|
|
|
|
|
Weighted
|
|
|
|
|
|
Weighted
|
|
|
|
|
|
Weighted
|
|
|
|
|
|
|
Average
|
|
|
|
|
|
Average Price
|
|
|
|
|
|
Average
|
|
Year
|
|
MMBtu
|
|
|
Price
|
|
|
MMBtu
|
|
|
Range
|
|
|
Bbl
|
|
|
Price
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2018
|
|
|
5,370,000
|
|
|
$
|
2.97
|
|
|
|
800,000
|
|
|
|
$2.85
- $3.19
|
|
|
|
7,500
|
|
|
$
|
50.81
|
|
2019
|
|
|
11,515,000
|
|
|
$
|
2.86
|
|
|
|
480,000
|
|
|
|
$2.85 - $3.19
|
|
|
|
12,000
|
|
|
$
|
50.35
|
|
2020
|
|
|
11,418,000
|
|
|
$
|
2.74
|
|
|
|
-
|
|
|
|
-
|
|
|
|
6,000
|
|
|
$
|
54.75
|
|
2021
|
|
|
2,598,000
|
|
|
$
|
2.69
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
$
|
-
|
|
(1)
|
Represents 100% of Carbon Appalachia’s outstanding derivative hedges at December 31, 2017, and not our proportionate share.
|
Carbon California
(1)
|
|
Natural
Gas Swaps
|
|
|
Natural
Gas Collars
|
|
|
Oil
Swaps
|
|
|
|
|
|
|
Weighted
|
|
|
|
|
|
Weighted
Average
|
|
|
|
|
|
Weighted
|
|
|
|
|
|
Weighted
|
|
|
|
|
|
|
Average
|
|
|
|
|
|
Price
|
|
|
WTI
|
|
|
Average
|
|
|
Brent
|
|
|
Average
|
|
Year
|
|
MMBtu
|
|
|
Price
(2)
|
|
|
MMBtu
|
|
|
Range
(2)
|
|
|
Bbl
|
|
|
Price
(3)
|
|
|
Bbl
|
|
|
Price
(4)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2018
|
|
|
180,000
|
|
|
$
|
3.03
|
|
|
|
-
|
|
|
|
-
|
|
|
|
85,809
|
|
|
$
|
53.08
|
|
|
|
110,598
|
|
|
$
|
66.46
|
|
2019
|
|
|
-
|
|
|
$
|
-
|
|
|
|
360,000
|
|
|
|
$2.60 - $3.03
|
|
|
|
139,797
|
|
|
$
|
51.96
|
|
|
|
137,486
|
|
|
$
|
66.35
|
|
2020
|
|
|
-
|
|
|
$
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
73,147
|
|
|
$
|
50.12
|
|
|
|
123,882
|
|
|
$
|
65.06
|
|
2021
|
|
|
-
|
|
|
$
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
$
|
-
|
|
|
|
28,641
|
|
|
$
|
66.35
|
|
(1)
|
Represents
100% of Carbon California’s outstanding derivative hedges at June 30, 2018, and not our proportionate share.
|
|
|
(2)
|
NYMEX
Henry Hub Natural Gas futures contract for the respective period.
|
|
|
(3)
|
NYMEX
Light Sweet Crude West Texas Intermediate future contract for the respective period.
|
|
|
(4)
|
Brent
for the respective period.
|
Reserves
The
tables below summarize our estimated proved oil and gas reserves and the estimated proved oil and gas reserves of Carbon Appalachia
and Carbon California as of December 31, 2017, which are based on reserve reports prepared by CGA, our independent petroleum engineers,
in accordance with the rules and regulations of the SEC regarding oil and natural gas reserve reporting. For more information
about our proved reserves, please read CG&A’s summary proved reserve reports, which are incorporated by reference into
this prospectus. Our estimated proved reserves increased in 2017 primarily due to revisions of previous estimates.
Carbon
Energy Corporation
The
table below summarizes our estimated proved oil and gas reserves as of December 31, 2017 and 2016, after consolidating the 47
partnerships in which we have a controlling interest through Nytis LLC.
Carbon
Energy Corporation
Estimated
Consolidated Proved Reserves
Including Non-Controlling Interests of Consolidated
Subsidiaries
(1)
|
|
December 31,
|
|
|
|
2017
|
|
|
2016
|
|
|
|
|
|
|
|
|
Proved developed reserves:
|
|
|
|
|
|
|
Natural gas (MMcf)
|
|
|
81,702
|
|
|
|
74,265
|
|
Oil and liquids (MBbl)
|
|
|
903
|
|
|
|
851
|
|
Total proved developed reserves (MMcfe)
|
|
|
87,120
|
|
|
|
79,371
|
|
|
|
|
|
|
|
|
|
|
Proved undeveloped reserves:
|
|
|
|
|
|
|
|
|
Natural gas (MMcf)
|
|
|
-
|
|
|
|
-
|
|
Oil and liquids (MBbl)
|
|
|
16
|
|
|
|
31
|
|
Total proved undeveloped reserves (MMcfe)
|
|
|
96
|
|
|
|
186
|
|
|
|
|
|
|
|
|
|
|
Total proved reserves (MMcfe)
|
|
|
87,216
|
|
|
|
79,557
|
|
|
|
|
|
|
|
|
|
|
Percent proved developed
|
|
|
99.9
|
%
|
|
|
99.8
|
%
|
|
|
|
|
|
|
|
|
|
Standardized Measure
(in thousands)
(2)
|
|
$
|
57,082
|
|
|
$
|
44,711
|
|
PV-10 (in thousands)
(3)
|
|
$
|
69,139
|
|
|
$
|
49,344
|
|
|
|
|
|
|
|
|
|
|
Average natural gas price used (per Mcf)
|
|
$
|
2.93
|
|
|
$
|
2.41
|
|
Average oil and liquids price used (per Bbl)
|
|
$
|
48.94
|
|
|
$
|
40.40
|
|
(1)
|
Our
estimated proved reserves and related future net revenues, PV-10 and Standardized Measure were determined using the unweighted
arithmetic average first-day-of-the-month prices for the prior 12 months for oil and natural gas, without giving effect to
commodity derivative contracts, and were held constant throughout the life of the properties. Prices were adjusted by lease
for quality, transportation fees, historical geographic differentials, marketing bonuses or deductions and other factors affecting
the price received at the wellhead.
|
(2)
|
Standardized
Measure represents the present value of the estimated future net revenues from proved oil or natural gas reserves after deducting
estimated production and ad valorem taxes, future capital costs, operating expenses and income taxes computed by applying
year end statutory tax rates, with consideration of future tax rates already legislated. The estimated future net revenues
are discounted at an annual rate of 10%, in accordance with the SEC’s practice, to determine their “present value.”
The present value is shown to indicate the effect of time on the value of the revenue stream and should not be construed as
being the fair market value of the properties. Estimates of future net revenues are made using oil and natural gas prices
and operating costs at the estimation date and held constant for the life of the reserves.
|
(3)
|
PV-10
is a non-GAAP financial measure and generally differs from Standardized Measure, the most directly comparable GAAP financial
measure, because it does not include the effects of federal income taxes on future net revenues. We and others in the industry
use PV-10 as a measure to compare the relative size and value of proved reserves held by companies without regard to the specific
tax characteristics of such entities. Please read “
—PV-10
.”
|
The
estimated quantities of proved reserves for the non-controlling interests of the consolidated partnerships as of December 31,
2017 were approximately 3.0 Bcfe, which was approximately 3% of total consolidated proved reserves.
The
following table summarizes our estimated quantities of proved reserves, excluding the non-controlling interests of the consolidated
partnerships, as of December 31, 2017 and 2016.
Carbon
Energy Corporation
Estimated
Consolidated Proved Reserves
Excluding
Non-Controlling Interests of Consolidated Partnerships
(1)
|
|
December 31,
|
|
|
|
2017
|
|
|
2016
|
|
Proved developed reserves:
|
|
|
|
|
|
|
Natural gas (MMcf)
|
|
|
78,665
|
|
|
|
71,125
|
|
Oil and liquids (MBbl)
|
|
|
903
|
|
|
|
851
|
|
Total proved developed reserves (MMcfe)
|
|
|
84,802
|
|
|
|
76,231
|
|
|
|
|
|
|
|
|
|
|
Proved undeveloped reserves:
|
|
|
|
|
|
|
|
|
Natural gas (MMcf)
|
|
|
-
|
|
|
|
-
|
|
Oil and liquids (MBbl)
|
|
|
16
|
|
|
|
31
|
|
Total proved undeveloped reserves (MMcfe)
|
|
|
94
|
|
|
|
186
|
|
|
|
|
|
|
|
|
|
|
Total proved reserves (MMcfe)
|
|
|
84,176
|
|
|
|
76,417
|
|
|
|
|
|
|
|
|
|
|
Percent developed
|
|
|
99.9
|
%
|
|
|
99.7
|
%
|
|
|
|
|
|
|
|
|
|
Standardized Measure
(in thousands)
(2)
|
|
$
|
55,107
|
|
|
$
|
44,711
|
|
PV-10 (in thousands)
(3)
|
|
$
|
67,165
|
|
|
$
|
47,659
|
|
|
|
|
|
|
|
|
|
|
Average natural gas price used (per Mcf)
|
|
$
|
2.93
|
|
|
$
|
2.41
|
|
Average oil and liquids price used (per Bbl)
|
|
$
|
48.94
|
|
|
$
|
40.40
|
|
(1)
|
Our
estimated proved reserves and related future net revenues, PV-10 and Standardized Measure were determined using the unweighted
arithmetic average first-day-of-the-month prices for the prior 12 months for oil and natural gas, without giving effect to
commodity derivative contracts, and were held constant throughout the life of the properties. Prices were adjusted by lease
for quality, transportation fees, historical geographic differentials, marketing bonuses or deductions and other factors affecting
the price received at the wellhead.
|
|
|
(2)
|
Standardized
Measure represents the present value of the estimated future net revenues from proved oil or natural gas reserves after deducting
estimated production and ad valorem taxes, future capital costs, operating expenses and income taxes computed by applying
year end statutory tax rates, with consideration of future tax rates already legislated. The estimated future net revenues
are discounted at an annual rate of 10%, in accordance with the SEC’s practice, to determine their “present value.”
The present value is shown to indicate the effect of time on the value of the revenue stream and should not be construed as
being the fair market value of the properties. Estimates of future net revenues are made using oil and natural gas prices
and operating costs at the estimation date and held constant for the life of the reserves.
|
|
|
(3)
|
PV-10
is a non-GAAP financial measure and generally differs from Standardized Measure, the most directly comparable GAAP financial
measure, because it does not include the effects of federal income taxes on future net revenues. We and others in the industry
use PV-10 as a measure to compare the relative size and value of proved reserves held by companies without regard to the specific
tax characteristics of such entities. Please read “
—PV-10
.”
|
The
following table shows a summary of the changes in quantities of our estimated proved oil and gas reserves for the year ended December
31, 2017.
|
|
2017
|
|
|
|
Oil
|
|
|
Natural Gas
|
|
|
Total
|
|
|
|
MBbls
|
|
|
MMcf
|
|
|
MMcfe
|
|
|
|
|
|
|
|
|
|
|
|
Proved reserves, beginning of year
|
|
|
882
|
|
|
|
74,265
|
|
|
|
79,557
|
|
Revisions of previous estimates
|
|
|
107
|
|
|
|
12,195
|
|
|
|
12,835
|
|
Extensions and discoveries
|
|
|
16
|
|
|
|
138
|
|
|
|
232
|
|
Production
|
|
|
(86
|
)
|
|
|
(4,896
|
)
|
|
|
(5,414
|
)
|
Purchases of reserves in-place
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
Sales of reserves in-place
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
Proved reserves, end of year
|
|
|
919
|
|
|
|
81,702
|
|
|
|
87,210
|
|
Carbon
Appalachia
The
following table summarizes Carbon Appalachia’s estimated quantities of proved reserves and our 27.24% proportionate share
in Carbon Appalachia’s estimated quantities of proved reserves as of December 31, 2017.
Carbon
Appalachia
Estimated
Proved Reserves
|
|
December 31, 2017
|
|
|
|
Carbon Appalachia
|
|
|
Carbon’s Share
|
|
|
|
|
|
|
|
|
Proved developed reserves:
|
|
|
|
Natural gas (MMcf)
|
|
|
333,175
|
|
|
|
90,757
|
|
Oil and liquids (MBbl)
|
|
|
264
|
|
|
|
72
|
|
Total proved developed reserves (MMcfe)
|
|
|
334,759
|
|
|
|
91,189
|
|
|
|
|
|
|
|
|
|
|
Proved undeveloped reserves:
|
|
|
|
|
|
|
|
|
Natural gas (MMcf)
|
|
|
-
|
|
|
|
-
|
|
Oil and liquids (MBbl)
|
|
|
-
|
|
|
|
-
|
|
Total proved undeveloped reserves (MMcfe)
|
|
|
-
|
|
|
|
-
|
|
|
|
|
|
|
|
|
|
|
Total proved reserves (MMcfe)
|
|
|
334,759
|
|
|
|
91,189
|
|
|
|
|
|
|
|
|
|
|
Percent developed
|
|
|
100
|
%
|
|
|
100
|
%
|
|
|
|
|
|
|
|
|
|
Average natural gas price used (per Mcf)
|
|
$
|
2.96
|
|
|
$
|
2.96
|
|
Average oil and liquids price used (per Bbl)
|
|
$
|
48.60
|
|
|
$
|
48.60
|
|
The
following table shows a summary of the changes in quantities of 100% of Carbon Appalachia’s estimated proved oil and gas
reserves for the period from April 3, 2017 (inception) through December 31, 2017.
|
|
2017
|
|
|
|
Oil
|
|
|
Natural Gas
|
|
|
Total
|
|
|
|
MBbls
|
|
|
MMcf
|
|
|
MMcfe
|
|
|
|
|
|
|
|
|
|
|
|
Proved reserves, inception
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
Purchases
of reserves in-place
(1)
|
|
|
278
|
|
|
|
338,479
|
|
|
|
340,147
|
|
Production
|
|
|
(14
|
)
|
|
|
(5,304
|
)
|
|
|
(5,388
|
)
|
Proved reserves, end of year
|
|
|
264
|
|
|
|
333,175
|
|
|
|
334,759
|
|
(1)
|
Purchases
of reserves-in-place represent our aggregate share for the year ended December 31, 2017. We held a 2.98%, 16.04%, 19.37%,
and 27.24% proportionate share of Carbon Appalachia for the period April 3, 2017 through August 14, 2017; August 15, 2017
through September 28, 2017; September 29, 2017 through October 31, 2017; and November 1, 2017 through December 31, 2017, respectively.
|
Carbon
California
The
following table summarizes Carbon California’s estimated quantities of proved reserves and our 17.81% proportionate share
in Carbon California’s estimated quantities of proved reserves as of December 31, 2017.
Carbon
California
Estimated
Proved Reserves
|
|
December 31, 2017
|
|
|
|
Carbon California
|
|
|
Carbon’s Share
|
|
|
|
|
|
|
|
|
Proved developed reserves:
|
|
|
|
Natural gas (MMcf)
|
|
|
12,319
|
|
|
|
2,194
|
|
Oil and liquids (MBbl)
|
|
|
6,563
|
|
|
|
1,169
|
|
Total proved developed reserves (MMcfe)
|
|
|
51,697
|
|
|
|
9,207
|
|
|
|
|
|
|
|
|
|
|
Proved undeveloped reserves:
|
|
|
|
|
|
|
|
|
Natural gas (MMcf)
|
|
|
4,590
|
|
|
|
818
|
|
Oil and liquids (MBbl)
|
|
|
3,827
|
|
|
|
682
|
|
Total proved undeveloped reserves (MMcfe)
|
|
|
27,554
|
|
|
|
4,907
|
|
|
|
|
|
|
|
|
|
|
Total proved reserves (MMcfe)
|
|
|
79,251
|
|
|
|
14,114
|
|
|
|
|
|
|
|
|
|
|
Percent developed
|
|
|
65
|
%
|
|
|
65
|
%
|
|
|
|
|
|
|
|
|
|
Average natural gas price used (per Mcf)
|
|
$
|
3.07
|
|
|
$
|
3.07
|
|
Average oil and liquids price used (per Bbl)
|
|
$
|
50.98
|
|
|
$
|
50.98
|
|
The
following table shows a summary of the changes in quantities of 100% of Carbon California’s estimated proved oil and gas
reserves for the period of February 15, 2017 (inception) through December 31, 2017.
|
|
2017
|
|
|
|
Oil
|
|
|
Natural Gas
|
|
|
NGL
|
|
|
Total
|
|
|
|
MBbls
|
|
|
MMcf
|
|
|
MBbls
|
|
|
MMcfe
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved reserves, inception
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
Purchases of reserves in-place
|
|
|
9,260
|
|
|
|
17,260
|
|
|
|
1,294
|
|
|
|
80,586
|
|
Production
|
|
|
(141
|
)
|
|
|
(351
|
)
|
|
|
(23
|
)
|
|
|
(1,335
|
)
|
Proved reserves, end of year
|
|
|
9,119
|
|
|
|
16,909
|
|
|
|
1,271
|
|
|
|
79,251
|
|
Preparation
of Reserves Estimates
Our
estimates of proved oil and natural gas reserves as of December 31, 2017 and 2016 and Carbon Appalachia and Carbon California’s
estimates of proved oil and natural gas reserves as of December 31, 2017 were based on the average fiscal-year prices for oil
and natural gas (calculated as the unweighted arithmetic average of the first-day-of-the month price for each month within the
12-month period ended December 31, 2017 and 2016, respectively). Proved developed oil and gas reserves are reserves that can be
expected to be recovered through existing wells with existing equipment and operating methods. Proved undeveloped oil and gas
reserves are reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively
major expenditure is required for recompletion. Proved undeveloped reserves on undrilled acreage are limited to those locations
on development spacing areas that are offsetting economic producers that are reasonably certain of economic production when drilled.
Proved undeveloped reserves for other undrilled development spacing areas are claimed only where it can be demonstrated with reasonable
certainty that there is continuity of economic production from the existing productive formation. Proved undeveloped reserves
are included when they are scheduled to be drilled within five years.
SEC
rules dictate the types of technologies that a company may use to establish reserve estimates including the extraction of non-traditional
resources, such as natural gas extracted from shales as well as bitumen extracted from oil sands. See Note 18 to the consolidated
financial statements for additional information regarding our estimated proved reserves.
Uncertainties
are inherent in estimating quantities of proved reserves, including many factors beyond our control. Reserve engineering is a
subjective process of estimating subsurface accumulations of oil and natural gas that cannot be measured in an exact manner, and
the accuracy of any reserve estimate is a function of the quality of available data and its interpretation. As a result, estimates
by different engineers often vary, sometimes significantly. In addition, physical factors such as the results of drilling, testing,
and production subsequent to the date of an estimate, as well as economic factors such as changes in product prices or development
and production expenses, may require revision of such estimates. Accordingly, quantities of oil and natural gas ultimately recovered
will vary from reserve estimates. See “
Risk Factors
,” for a description of some of the risks and uncertainties
associated with our business and reserves.
Reserve
estimates are based on production performance, data acquired remotely or in wells, and are guided by petrophysical, geologic,
geophysical and reservoir engineering models. Estimates of our proved reserves were based on deterministic methods. In the case
of mature developed reserves, reserve estimates are determined by decline curve analysis and in the case of immature developed
and undeveloped reserves, by analogy, using proximate or otherwise appropriate examples in addition to volumetric analysis. The
technologies and economic data used in estimating our proved reserves include empirical evidence through drilling results and
well performance, well logs and test data, geologic maps and available downhole and production data. Further, the internal review
process of our wells and related reserve estimates includes but is not limited to the following:
|
●
|
A
comparison is made and documented of actual data from our accounting system to the data utilized in the reserve database.
Current production, revenue and expense information obtained from our accounting records is subject to external quarterly
reviews, annual audits and additional internal controls over financial reporting. This process is designed to create assurance
that production, revenues and expenses are accurately reflected in the reserve database.
|
|
●
|
A
comparison is made and documented of land and lease records to ownership interest data in the reserve database. This process
is designed to create assurance that the costs and revenues utilized in the reserves estimation match actual ownership interests.
|
|
●
|
A
comparison is made of property acquisitions, disposals, retirements or transfers to the property records maintained in the
reserve database to verify that all are accounted for accurately.
|
|
●
|
Natural
gas pricing for the first flow day of every month is obtained from Platts Gas Daily. Oil pricing for the first flow day of
every month is obtained from the U.S. Energy Information Administration. At the reporting date, 12-month average prices are
determined. Regional variations in pricing and related deductions are similarly obtained and a 12-month average is calculated
at year end.
|
For
the years ended December 31, 2017 and 2016 for us and the periods ended December 31, 2017 for Carbon Appalachia and Carbon California,
CGA reviewed with us technical personnel field performance and future development plans. Following these reviews, we furnished
our internal reserve database and supporting data to CGA in order for them to prepare their independent reserve estimates and
final report. We restrict access to our database containing reserve information to select individuals from our engineering department.
CGA’s independent reserve estimates and final report are for our, Carbon Appalachia’s and Carbon California’s
interests in the respective oil and gas properties and represents 100% of the total proved hydrocarbon reserves owned by us, Carbon
Appalachia and Carbon California or 96% of the consolidated proved hydrocarbon reserves presented in our consolidated financial
statements. CGA’s report does not include the hydrocarbon reserves owned by the non-controlling interests of our consolidated
partnerships. We calculated the estimated reserves and related PV-10 of the non-controlling interests of the consolidated partnerships’
oil and gas properties by multiplying CGA’s independent reserve estimates for such properties by the respective non-controlling
interests in those properties.
Our
Vice President of Engineering, Richard Finucane, and our manager of Acquisitions and Divestitures, Todd Habliston, are responsible
for overseeing the preparation of the reserve estimates with consultations from our internal technical and accounting staff. Mr.
Finucane has been involved in reservoir engineering in the Appalachian Basin since 1982 and has worked as an oil and natural gas
engineer since 1978 and holds a B.S. in Civil Engineering from the University of Tennessee (highest honors) and is admitted as
an expert in oil and natural gas matters in civil and regulatory proceedings in Kentucky, Virginia and West Virginia. Mr. Habliston
has over 30 years of oil and gas experience and has served as Adjunct Professor at the Colorado School of Mines. Mr. Habliston
earned a B.S. in Chemical and Petroleum Refining Engineering from the Colorado School of Mines and an MBA from Purdue University.
He is a registered Professional Engineer and is a member of SPE, SPEE, AAPG, API and IPAA.
PV-10
PV-10
is a non-GAAP financial measure. We believe that the presentation of PV-10 is relevant and useful to investors because it presents
the discounted future net cash flows attributable to our estimated net proved reserves prior to taking into account future corporate
income taxes, and it is a useful measure for evaluating the relative monetary significance of our oil and gas properties. It is
not intended to represent the current market value of our estimated reserves. PV-10 should not be considered in isolation or as
a substitute for the standardized measure reported in accordance with GAAP, but rather should be considered in addition to the
standardized measure.
PV-10
is derived from the standardized measure, which is the most directly comparable GAAP financial measure. PV-10 is calculated using
the same inputs and assumptions as the standardized measure, with the exception that it omits the impact of future income taxes.
It is considered to be a pre-tax measurement.
The following table provides a reconciliation
of the standardized measure for us and our proportionate share of Carbon Appalachia and Carbon California to PV-10 at December
31, 2017 and 2016 (in thousands):
|
|
Year Ended December 31,
|
|
|
|
2017
|
|
|
2016
|
|
PV-10 (in thousands)
|
|
$
|
152,341
|
|
|
$
|
59,569
|
|
Future income taxes (in thousands)
|
|
|
(35,482
|
)
|
|
|
(14,858
|
)
|
Standardized Measure (in thousands)
|
|
$
|
116,859
|
|
|
$
|
44,711
|
|
Drilling
Activities
Based
on oil and natural gas prices during 2017, we reduced our, Carbon Appalachia’s and Carbon California’s drilling activities
to manage and optimize the utilization of our capital resources. During 2017, our capital expenditures consisted principally of
oil-related remediation, return to production and recompletion projects in California and the optimization and streamlining of
our natural gas gathering and compression facilities in Appalachia to provide more efficient and lower cost operations and greater
flexibility in moving our production to markets with more favorable pricing.
Carbon
Energy Corporation
The following table summarizes the
number of wells drilled for the years ended December 31, 2017, 2016 and 2015. Gross wells reflect the sum of all wells in which
we own an interest. Net wells reflect the sum of our working interests in gross wells. We did not drill any wells in the six months
ended June 30, 2018.
|
|
Year Ended December 31,
|
|
|
|
2017
|
|
|
2016
|
|
|
2015
|
|
|
|
Gross
|
|
|
Net
|
|
|
Gross
|
|
|
Net
|
|
|
Gross
|
|
|
Net
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Development wells:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Productive
(1)
|
|
|
2
|
|
|
|
1.2
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
Non-productive
(2)
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
Total development wells
|
|
|
2
|
|
|
|
1.2
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exploratory wells:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Productive
(1)
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
Non-productive
(2)
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
Total exploratory wells
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
(1)
|
A
well classified as productive does not always provide economic levels of activity.
|
|
|
(2)
|
A
non-productive well is a well found to be incapable of producing either oil or natural gas in sufficient quantities to justify
completion as an oil or natural gas well; also known as a dry well (or dry hole).
|
Carbon
Appalachia
No wells were drilled for the six months ended June 30,
2018 or the period ended December 31, 2017.
Carbon California
The following table summarizes our
17.81% proportionate share in the number of wells drilled for the year ended December 31, 2017. Gross wells reflect the sum of
all wells in which Carbon California owned an interest. Net wells reflect the sum of Carbon California’s working interests
in gross wells. Carbon California did not drill any wells in the six months ended June 30, 2018.
|
|
Year Ended
December 31,
|
|
|
|
2017
|
|
|
|
Gross
|
|
|
Net
|
|
Development wells:
|
|
|
|
|
|
|
Productive
(1)
|
|
|
1
|
|
|
|
1
|
|
Non-productive
(2)
|
|
|
-
|
|
|
|
-
|
|
Total development wells
|
|
|
1
|
|
|
|
1
|
|
|
|
|
|
|
|
|
|
|
Exploratory wells:
|
|
|
|
|
|
|
|
|
Productive
(1)
|
|
|
-
|
|
|
|
-
|
|
Non-productive
(2)
|
|
|
-
|
|
|
|
-
|
|
Total exploratory wells
|
|
|
-
|
|
|
|
-
|
|
(1)
|
A
well classified as productive does not always provide economic levels of activity.
|
|
|
(2)
|
A
non-productive well is a well found to be incapable of producing either oil or natural gas in sufficient quantities to justify
completion as an oil or natural gas well; also known as a dry well (or dry hole).
|
Oil
and Natural Gas Wells and Acreage
Productive
Wells
Productive
wells consist of producing wells and wells capable of production, including shut-in wells. A well bore with multiple completions
is counted as only one well. The following table summarizes our and our proportionate share in Carbon Appalachia’s and Carbon
California’s productive wells as of December 31, 2017.
|
|
December 31, 2017
|
|
|
|
Gross
|
|
|
Net
|
|
|
|
|
|
|
|
|
Carbon Energy Corporation
|
|
|
|
|
|
|
Gas
|
|
|
2,555
|
|
|
|
2,165
|
|
Oil
|
|
|
474
|
|
|
|
420
|
|
Total
|
|
|
3,029
|
|
|
|
2,585
|
|
|
|
|
|
|
|
|
|
|
Carbon Appalachia
|
|
|
|
|
|
|
|
|
Gas
|
|
|
4,378
|
|
|
|
3,802
|
|
Oil
|
|
|
33
|
|
|
|
24
|
|
Total
|
|
|
4,411
|
|
|
|
3,826
|
|
|
|
|
|
|
|
|
|
|
Carbon California
|
|
|
|
|
|
|
|
|
Gas
|
|
|
-
|
|
|
|
-
|
|
Oil
|
|
|
208
|
|
|
|
207
|
|
Total
|
|
|
208
|
|
|
|
207
|
|
Acreage
Carbon
Energy Corporation
The
following table summarizes our gross and net developed and undeveloped acreage by state as of December 31, 2017. Acreage related
to royalty, overriding royalty and other similar interests is excluded from this summary, as well as acreage related to any options
held by us to acquire additional leasehold interests.
|
|
December 31, 2017
|
|
|
|
Developed Acres
|
|
|
Undeveloped Acres
|
|
|
Total Acres
|
|
|
|
Gross
|
|
|
Net
|
|
|
Gross
|
|
|
Net
|
|
|
Gross
|
|
|
Net
|
|
Indiana
|
|
|
-
|
|
|
|
-
|
|
|
|
43,364
|
|
|
|
43,364
|
|
|
|
43,364
|
|
|
|
43,364
|
|
Illinois
|
|
|
3,758
|
|
|
|
1,879
|
|
|
|
24,216
|
|
|
|
14,608
|
|
|
|
27,974
|
|
|
|
16,487
|
|
Kentucky
|
|
|
10,778
|
|
|
|
9,710
|
|
|
|
95,159
|
|
|
|
69,333
|
|
|
|
105,937
|
|
|
|
79,043
|
|
Ohio
|
|
|
338
|
|
|
|
338
|
|
|
|
6,703
|
|
|
|
6,703
|
|
|
|
7,041
|
|
|
|
7,041
|
|
Tennessee
|
|
|
160
|
|
|
|
40
|
|
|
|
45,904
|
|
|
|
45,896
|
|
|
|
46,064
|
|
|
|
45,936
|
|
Virginia
|
|
|
732
|
|
|
|
679
|
|
|
|
-
|
|
|
|
-
|
|
|
|
732
|
|
|
|
679
|
|
West Virginia
|
|
|
187,858
|
|
|
|
176,326
|
|
|
|
54,021
|
|
|
|
42,497
|
|
|
|
241,879
|
|
|
|
218,823
|
|
Total
|
|
|
203,624
|
|
|
|
188,972
|
|
|
|
269,367
|
|
|
|
222,401
|
|
|
|
472,991
|
|
|
|
411,373
|
|
Carbon
Appalachia
The
following table summarizes our 27.24% proportionate share in Carbon Appalachia’s gross and net developed and undeveloped
acreage by state as of December 31, 2017. Acreage related to royalty, overriding royalty and other similar interests is excluded
from this summary, as well as acreage related to any options held by Carbon Appalachia to acquire additional leasehold interests.
|
|
December 31, 2017
|
|
|
|
Developed Acres
|
|
|
Undeveloped Acres
|
|
|
Total Acres
|
|
|
|
Gross
|
|
|
Net
|
|
|
Gross
|
|
|
Net
|
|
|
Gross
|
|
|
Net
|
|
Ohio
|
|
|
986
|
|
|
|
290
|
|
|
|
-
|
|
|
|
-
|
|
|
|
986
|
|
|
|
290
|
|
Virginia
|
|
|
2,212
|
|
|
|
2,045
|
|
|
|
32,113
|
|
|
|
32,113
|
|
|
|
34,325
|
|
|
|
34,159
|
|
West Virginia
|
|
|
230,817
|
|
|
|
198,863
|
|
|
|
46,448
|
|
|
|
45,070
|
|
|
|
277,265
|
|
|
|
243,932
|
|
Tennessee
|
|
|
18,778
|
|
|
|
17,926
|
|
|
|
20,977
|
|
|
|
20,925
|
|
|
|
39,755
|
|
|
|
38,851
|
|
Total
|
|
|
252,793
|
|
|
|
219,124
|
|
|
|
99,538
|
|
|
|
98,108
|
|
|
|
352,331
|
|
|
|
317,232
|
|
Carbon
California
The
following table summarizes our 17.81% proportionate share in Carbon California’s gross and net developed and undeveloped
acreage by state as of December 31, 2017. Acreage related to royalty, overriding royalty and other similar interests is excluded
from this summary, as well as acreage related to any options held by Carbon California to acquire additional leasehold interests.
|
|
December 31, 2017
|
|
|
|
Developed
|
|
|
Undeveloped
|
|
|
Total
|
|
|
|
Acres
|
|
|
Acres
|
|
|
Acres
|
|
|
|
Gross
|
|
|
Net
|
|
|
Gross
|
|
|
Net
|
|
|
Gross
|
|
|
Net
|
|
California
|
|
|
392
|
|
|
|
390
|
|
|
|
1,450
|
|
|
|
1,449
|
|
|
|
1,842
|
|
|
|
1,838
|
|
Undeveloped
Acreage Expirations
Carbon
Energy Corporation
The
following table sets forth our gross and net undeveloped acres by state as of December 31, 2017 which are scheduled to expire
through December 31, 2020 unless production is established within the spacing unit covering the acreage prior to the expiration
date or we extend the terms of a lease by paying delay rentals to the lessor.
|
|
December 31, 2017
|
|
|
|
2018
|
|
|
2019
|
|
|
2020
|
|
|
|
Gross
|
|
|
Net
|
|
|
Gross
|
|
|
Net
|
|
|
Gross
|
|
|
Net
|
|
Indiana
|
|
|
-
|
|
|
|
-
|
|
|
|
34,285
|
|
|
|
34,285
|
|
|
|
-
|
|
|
|
-
|
|
Illinois
|
|
|
6,143
|
|
|
|
3,071
|
|
|
|
2,908
|
|
|
|
1,454
|
|
|
|
3,099
|
|
|
|
1,549
|
|
Kentucky
|
|
|
8,471
|
|
|
|
5,083
|
|
|
|
10,223
|
|
|
|
6,290
|
|
|
|
9,648
|
|
|
|
8,175
|
|
West Virginia
|
|
|
-
|
|
|
|
-
|
|
|
|
3,625
|
|
|
|
3,625
|
|
|
|
11,574
|
|
|
|
11,574
|
|
Total
|
|
|
14,614
|
|
|
|
8,154
|
|
|
|
51,041
|
|
|
|
45,654
|
|
|
|
24,321
|
|
|
|
21,298
|
|
Carbon
Appalachia
The
following table sets forth our 27.24% proportionate share in Carbon Appalachia’s gross and net undeveloped acres by state
as of December 31, 2017 which are scheduled to expire through December 31, 2020 unless production is established within the spacing
unit covering the acreage prior to the expiration date or Carbon Appalachia extends the terms of a lease by paying delay rentals
to the lessor.
|
|
December 31, 2017
|
|
|
|
2018
|
|
|
2019
|
|
|
2020
|
|
|
|
Gross
|
|
|
Net
|
|
|
Gross
|
|
|
Net
|
|
|
Gross
|
|
|
Net
|
|
Ohio
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
Tennessee
|
|
|
1,416
|
|
|
|
1,416
|
|
|
|
478
|
|
|
|
457
|
|
|
|
58
|
|
|
|
48
|
|
Virginia
|
|
|
2
|
|
|
|
2
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
West Virginia
|
|
|
3,790
|
|
|
|
3,255
|
|
|
|
1,422
|
|
|
|
1,362
|
|
|
|
1,793
|
|
|
|
1,793
|
|
Total
|
|
|
5,207
|
|
|
|
4,673
|
|
|
|
1,900
|
|
|
|
1,819
|
|
|
|
1,851
|
|
|
|
1,841
|
|
Carbon
California
Carbon
California does not have any scheduled undeveloped acres to expire from December 31, 2017 through December 31, 2020.
Production,
Average Sales Prices and Production Costs
Carbon
Energy Corporation
The
following table reflects our production, average sales price, and production cost information for the years ended December 31,
2017, 2016 and 2015.
|
|
Year Ended December 31,
|
|
|
|
2017
|
|
|
2016
|
|
|
2015
|
|
|
|
|
|
|
|
|
|
|
|
Production data:
|
|
|
|
|
|
|
|
|
|
Natural gas (MMcf)
|
|
|
4,896
|
|
|
|
2,823
|
|
|
|
2,040
|
|
Oil and condensate (Bbl)
|
|
|
86,277
|
|
|
|
79,044
|
|
|
|
101,255
|
|
Combined (MMcfe)
|
|
|
5,414
|
|
|
|
3,297
|
|
|
|
2,646
|
|
Gas and oil production revenue (in thousands)
|
|
$
|
19,511
|
|
|
$
|
10,443
|
|
|
$
|
10,708
|
|
Commodity derivative gain (loss) (in thousands)
|
|
$
|
2,928
|
|
|
$
|
(2,259
|
)
|
|
$
|
852
|
|
Prices:
|
|
|
|
|
|
|
|
|
|
|
|
|
Average sales price before effects of hedging;
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas (per Mcf)
|
|
$
|
3.12
|
|
|
$
|
2.53
|
|
|
$
|
2.78
|
|
Oil and condensate (per Bbl)
|
|
$
|
48.84
|
|
|
$
|
41.95
|
|
|
$
|
49.83
|
|
Average sale price after effects of hedging:
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas (per Mcf)
|
|
$
|
3.72
|
|
|
$
|
1.89
|
|
|
$
|
3.01
|
|
Oil and condensate (per Bbl)
|
|
$
|
48.83
|
|
|
$
|
36.14
|
|
|
$
|
53.48
|
|
Average costs per Mcfe:
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating costs
|
|
$
|
1.13
|
|
|
$
|
0.96
|
|
|
$
|
1.10
|
|
Transportation costs
|
|
$
|
0.40
|
|
|
$
|
0.50
|
|
|
$
|
0.65
|
|
Production and property taxes
|
|
$
|
0.24
|
|
|
$
|
0.25
|
|
|
$
|
0.33
|
|
Carbon
Appalachia
The
following table reflects our 27.24% proportionate share in Carbon Appalachia’s production, average sales price, and production
cost information for the period ended December 31, 2017.
|
|
Period from Inception
Through December 31,
|
|
|
|
2017
|
|
Production data:
|
|
|
|
Natural gas (MMcf)
|
|
|
5,304
|
|
Oil and NGLs (Bbl)
|
|
|
14
|
|
Combined (MMcfe)
|
|
|
5,390
|
|
Gas, oil and NGL production revenue (in thousands)
|
|
$
|
16,813
|
|
Commodity derivative gain (in thousands)
|
|
$
|
2,545
|
|
Prices:
|
|
|
|
|
Average sales price before effects of hedging;
|
|
|
|
|
Natural gas (per Mcf)
|
|
$
|
3.04
|
|
Oil and NGLs (per Bbl)
|
|
$
|
47.94
|
|
Average sale price after effects of hedging:
|
|
|
|
|
Natural gas (per Mcf)
|
|
$
|
3.14
|
|
Oil and NGLs (per Bbl)
|
|
$
|
47.41
|
|
Average costs per Mcfe:
|
|
|
|
|
Lease operating costs
|
|
$
|
0.98
|
|
Transportation costs
|
|
$
|
0.35
|
|
Production and property taxes
|
|
$
|
0.27
|
|
Carbon
California
The
following table reflects our 17.81% proportionate share in Carbon California’s production, average sales price, and production
cost information for the year ended December 31, 2017.
|
|
Period Inception
Through December 31,
|
|
|
|
2017
|
|
Production data:
|
|
|
|
Natural gas (MMcf)
|
|
|
351
|
|
Oil and condensate (Bbl)
|
|
|
165
|
|
Combined (MMcfe)
|
|
|
1,339
|
|
Gas, NGL and oil production revenue (in thousands)
|
|
$
|
8,616
|
|
Commodity derivative (loss) (in thousands)
|
|
$
|
(1,381
|
)
|
Prices:
|
|
|
|
|
Average sales price before effects of hedging;
|
|
|
|
|
Natural gas (per Mcf)
|
|
$
|
2.95
|
|
Oil and condensate (per Bbl)
|
|
$
|
46.04
|
|
Average sale price after effects of hedging:
|
|
|
|
|
Natural gas (per Mcf)
|
|
$
|
3.26
|
|
Oil and condensate (per Bbl)
|
|
$
|
51.40
|
|
Average costs per BOE:
|
|
|
|
|
Lease operating costs
|
|
$
|
16.70
|
|
Transportation costs
|
|
$
|
6.46
|
|
Production and property taxes
|
|
$
|
2.37
|
|
Present
Activities
Our
current focus is on growth through acquisition of producing wells, rather than drilling wells.
Our
current drilling program includes only those wells required to be drilled under certain agreements.
Marketing
and Delivery Commitments
Our
oil and natural gas production is generally sold on a month-to-month basis in the spot market, priced in reference to published
indices. We believe that the loss of one or more of our purchasers would not have a material adverse effect on our ability to
sell our production, because any individual purchaser could be readily replaced by another purchaser, absent a broad market disruption.
We
currently do not have any delivery commitments.
We
and Carbon Appalachia acquired long-term firm transportation contracts that were entered into to ensure the transport of certain
gas production to purchasers. Any shortfall of capacity use upon acquisition was recorded as a liability and is included in firm
transportation obligations on the consolidated balance sheet of each entity.
Total firm transportation volumes and
related demand charges for the remaining term of these contracts at June 30, 2018 related to us are summarized in the table below.
Carbon
Energy Corporation
Period
|
|
Dekatherms
per day
|
|
|
Demand
Charges
(per Dth)
|
|
July 2018 – Mar 2020
|
|
|
3,230
|
|
|
|
$0.20 - $0.62
|
|
Apr 2020 – May 2020
|
|
|
2,150
|
|
|
$
|
0.20
|
|
Jun 2020 – May 2036
|
|
|
1,000
|
|
|
$
|
0.20
|
|
Carbon
Appalachia
(1)
Total firm transportation volumes and
related demand charges for the remaining term of these contracts at June 30, 2018 related to Carbon Appalachia are summarized
in the table below.
Period
|
|
Dekatherms
per day
|
|
|
Demand
Charges
(per Dth)
|
|
July 2018 – Oct 2020
|
|
|
6,300
|
|
|
$
|
0.21
|
|
July 2018 – May 2027
|
|
|
29,900
|
|
|
$
|
0.21
|
|
July 2018 – Aug 2022
|
|
|
19,441
|
|
|
$
|
0.56
|
|
(1)
|
Represents 100% of Carbon
Appalachia’s firm transportation obligations at June 30, 2018, and not our proportionate
share.
|
Competition
We encounter competition in all aspects
of business, including acquisition of properties and oil and natural gas leases, marketing oil and natural gas, obtaining services
and labor, and securing drilling rigs and other equipment and materials necessary for drilling and completing wells. Our ability
to increase reserves in the future will depend on our ability to generate successful prospects on existing properties, execute
development drilling programs, and acquire additional producing properties and leases for future development and exploration.
Competitors include independent oil and gas companies, major oil and gas companies and individual producers and operators within
and outside of the Appalachian, Illinois and Ventura Basins. A number of the companies with which we compete have larger staffs
and greater financial and operational resources than we have. Because of the nature of oil and natural gas assets and management’s
experience in developing reserves and acquiring properties, we believe that we effectively compete in our markets. See “
Risk
Factors
—
Risks Related to Our Business—Competition in the oil and natural gas industry is intense, making
it more difficult for us to acquire properties, market oil and natural gas and secure trained personnel.
”
Regulation
Federal,
state and local agencies have extensive rules and regulations applicable to oil and natural gas exploration, production and related
operations. These laws and regulations may change in response to economic or political conditions. Matters subject to current
governmental regulation and/or pending legislative or regulatory changes include the discharge or other release into the environment
of wastes and other substances in connection with drilling and production activities (including fracture stimulation operations),
bonds or other financial responsibility requirements to cover drilling risks and well plugging and abandonment, reclamation or
restoration costs, reports concerning our operations, the spacing of wells, unitization and pooling of properties, taxation, and
the use of derivative hedging instruments. Failure to comply with laws and regulations may result in the assessment of administrative,
civil and criminal penalties, the imposition of remedial obligations and the issuance of injunctions that could delay, limit or
prohibit certain of our operations. In the past, regulatory agencies have imposed price controls and limitations on production.
In order to conserve supplies of oil and gas, oil and gas conservation commissions and other agencies may restrict the rates of
flow of wells below actual production capacity, generally prohibit the venting or flaring of natural gas, and may impose certain
requirements regarding the ratability or fair apportionment of production from fields and individual wells. Further, a significant
spill from one of our facilities could have a material adverse effect on our results of operations, competitive position or financial
condition. The laws regulate, among other things, the production, handling, storage, transportation and disposal of oil and natural
gas, by-products from each and other substances and materials produced or used in connection with our operations. Although we
believe we are in substantial compliance with applicable laws and regulations, such laws and regulations may be amended or reinterpreted.
In addition, unforeseen environmental incidents may occur or past non-compliance with environmental laws or regulations may be
discovered. Therefore, we cannot predict the ultimate cost of compliance with these requirements or their effect on our operations.
Most states require drilling permits,
drilling and operating bonds and the filing of various reports and impose other requirements relating to the exploration and production
of oil and natural gas. Many states also have statutes or regulations regarding conservation matters including rules governing
the size of drilling and spacing units, the density of wells and the unitization of oil and natural gas properties. The federal
and state regulatory burden on the oil and natural gas industry increases our cost of doing business and affects our profitability.
Federal legislation and regulatory controls
have historically affected the prices received for natural gas production. The Federal Energy Regulatory Commission (“
FERC
”)
has jurisdiction over the transportation and sale or resale of natural gas in interstate commerce under the Natural Gas Act of
1938 (“
NGA
”), the Natural Gas Policy Act of 1978 (“
NGPA
”), and the regulations
promulgated under those statutes. Carbon Appalachia owns an intrastate natural gas pipeline through its ownership of the Cranberry
Pipeline, that provides interstate transportation and storage services pursuant to Section 311 of the NGPA, as well as intrastate
transportation and storage services that are regulated by the West Virginia Public Service Commission. For qualified intrastate
pipelines, FERC allows interstate transportation service “on behalf of” interstate pipelines or local distribution
companies served by interstate pipelines without subjecting the intrastate pipeline to the more comprehensive NGA jurisdiction
of FERC. We provide Section 311 service in accordance with a publicly available Statement of Operating Conditions filed with
FERC under rates that are subject to approval by the FERC. By Letter Order issued May 15, 2013, the FERC approved the current
Cranberry Pipeline rates. The May 15, 2013 Letter Order required Cranberry Pipeline to file a renewed rate petition by December
18, 2017. On November 21, 2017, FERC extended this filing deadline to December 18, 2018 in recognition of potential rate impacts
of the Cabot Acquisition.
In 2005, Congress enacted the Energy Policy
Act of 2005 (“
EPAct 2005
”), which amends the NGA to make it unlawful for any entity, including non-jurisdictional
producers such as Carbon, Carbon Appalachia and Carbon California, to use any deceptive or manipulative device or contrivance
in connection with the purchase or sale of natural gas or the purchase or sale of transportation services subject to regulation
by the FERC, or contravention of rules prescribed by FERC. EPAct 2005 also gives FERC authority to impose civil penalties for
violations of the NGA up to approximately $1,200,000 per day per violation, and this amount is adjusted for inflation on an annual
basis. The anti-manipulation rule does not apply to activities that relate only to intrastate or other non-jurisdictional sales
or gathering, but does apply to activities of otherwise non-jurisdictional entities to the extent the activities are conducted
“in connection with” natural gas sales, purchases or transportation subject to FERC jurisdiction. It therefore reflects
a significant expansion of FERC’s enforcement authority. We do not anticipate we will be affected any differently than other
producers of natural gas in respect of EPAct 2005.
In 2007, FERC issued rules requiring that
any market participant, including a producer such as Carbon, Carbon Appalachia or Carbon California, that engages in physical
sales for resale or purchases for resale of natural gas that equal or exceed 2.2 million MMBtus during a calendar year, must annually
report such sales or purchases to FERC, beginning on May 1, 2009. These rules are intended to increase the transparency of the
wholesale natural gas markets and to assist FERC in monitoring such markets and in detecting market manipulation. In 2008, FERC
issued its order on rehearing, which largely approved the existing rules, except FERC exempted from the reporting requirement
certain types of purchases and sales, including purchases and sales of unprocessed natural gas and bundled sales of natural gas
made pursuant to state regulated retail tariffs. In addition, FERC clarified that other end use purchases and sales are not exempt
from the reporting requirements. The monitoring and reporting required by the rules have increased our administrative costs. We
do not anticipate we, Carbon Appalachia or Carbon California will be affected any differently than other producers of natural
gas.
Gathering service, which occurs on pipeline
facilities located upstream of jurisdictional transmission services, is regulated by the states onshore and in state waters. Section
1(b) of the NGA exempts natural gas gathering facilities from regulation by FERC as a natural gas company under the NGA. Although
FERC has set forth a general test for determining whether facilities perform a nonjurisdictional gathering function or a jurisdictional
transmission function, FERC’s determinations as to the classification of facilities are done on a case-by-case basis. To
the extent that FERC issues an order that reclassifies certain non-jurisdictional gathering facilities as FERC-jurisdictional
transportation facilities, and depending on the scope of that decision, the costs of getting gas to point of sale locations may
increase. We believe that the natural gas pipelines in our gathering systems meet the traditional tests FERC has used to establish
a pipeline’s status as a gatherer not subject to regulation as a natural gas company. However, the distinction between FERC-regulated
transmission services and federally unregulated gathering services is the subject of ongoing litigation, so the classification
and regulation of our gathering facilities is subject to change based on future determinations by FERC, the courts or Congress.
In addition, state regulation of natural gas gathering facilities generally includes various occupational safety, environmental
and, in some circumstances, nondiscriminatory-take requirements. Although such regulation has not generally been affirmatively
applied by state agencies, natural gas gathering may receive greater regulatory scrutiny in the future.
Additional proposals and proceedings that
might affect the oil and natural gas industry are regularly considered by Congress, the states, FERC and the courts. For instance,
legislation has previously been introduced in Congress to amend the federal Safe Drinking Water Act to subject hydraulic fracturing
operations—an important process used in the completion of our oil and natural gas wells—to regulation under the Safe
Drinking Water Act. If adopted, this legislation could establish an additional level of regulation, and impose additional cost,
on our operations. We cannot predict when or whether any such proposal, or any additional new legislative or regulatory proposal,
may become effective. No material portion of our business is subject to renegotiation of profits or termination of contracts or
subcontracts at the election of the federal government.
Our sales of oil and natural gas are affected
by the availability, terms and cost of transportation. Interstate transportation of oil and natural gas by pipelines is regulated
by FERC pursuant to the Interstate Commerce Act, the NGA, the Energy Policy Act of 1992 and the rules and regulations promulgated
under those laws. Intrastate oil and natural gas pipeline transportation rates may also be subject to regulation by state regulatory
commissions. We do not believe that the regulation of oil transportation rates will affect our operations in any way that is materially
different that those of our competitors who are similarly situated.
Regulation of Pipeline Safety and Maintenance
The Pipeline and Hazardous Materials Safety
Administration (“
PHMSA
”) has established safety requirements pertaining to the design, installation,
testing, construction, operation and maintenance of gas pipeline facilities, including requirements that pipeline operators develop
a written qualification program for individuals performing covered tasks on pipeline facilities and implement pipeline integrity
management programs. PHMSA has the statutory authority to impose civil penalties for pipeline safety violations up to a maximum
of approximately $200,000 per day for each violation and approximately $2 million for a related series of violations. This maximum
penalty authority established by statute will continue to be adjusted periodically to account for inflation.
The Protecting Our Infrastructure of Pipelines
and Enhancing Safety Act of 2016 (“
PIPES 2016 Act
”), extended PHMSA’s statutory mandate under
prior legislation through 2019. In addition, the PIPES 2016 Act empowered PHMSA to address imminent hazards by imposing emergency
restrictions, prohibitions and safety measures on owners and operators of gas or hazardous liquid pipeline facilities without
prior notice or an opportunity for a hearing. Additionally, in April 2016, PHMSA proposed rules that would, if adopted, strengthen
existing integrity management requirements, expand assessment and repair requirements to pipelines in areas with medium population
densities and extend regulatory requirements to onshore gas gathering lines that are currently exempt. The issuance of a final
rule is uncertain at this time. The extension of regulatory requirements to our gathering pipelines would impose additional obligations
on us and could add material costs to our and their operations. States are largely preempted by federal law from regulating pipeline
safety for interstate lines but most states are certified by the U.S. Department of Transportation to assume responsibility for
enforcing federal intrastate pipeline regulations and inspection of intrastate pipelines. In practice, because states can adopt
stricter standards for intrastate pipelines than those imposed by the federal government for interstate lines, states vary considerably
in their authority and capacity to address pipeline safety. However, we do not expect that any such costs would be material to
our financial condition or results of operations. The adoption of new or amended regulations by PHMSA or the states that result
in more stringent or costly pipeline integrity management or safety standards could have a significant adverse effect on us and
similarly situated midstream operators. We cannot predict what future action the DOT will take, but we do not believe that any
regulatory changes will affect us in a way that materially differs from the way they will affect our competitors.
We believe our operations are in substantial
compliance with all existing federal, state and local pipeline safety laws and regulations.
Environmental
As an operator of oil and natural gas
properties in the U.S., we are subject to federal, state and local laws and regulations relating to environmental protection as
well as the manner in which various substances, including wastes generated in connection with exploration, production, and transportation
operations, are released into the environment. Compliance with these laws and regulations can affect the location or size of wells
and facilities, prohibit or limit the extent to which exploration and development may be allowed, and require proper closure of
wells and restoration of properties when production ceases. Failure to comply with these laws and regulations may result in the
assessment of administrative, civil, or criminal penalties, imposition of remedial obligations, incurrence of capital or increased
operating costs to comply with governmental standards, and even injunctions that limit or prohibit exploration and production
activities or that constrain the disposal of substances generated by oil field operations.
The most significant of these environmental laws that may apply
to our operations are as follows:
|
●
|
the
Comprehensive Environmental Response, Compensation and Liability Act, as amended (“
CERCLA
”) and
comparable state statutes which impose liability on owners and operators of certain sites and on persons who dispose of or
arrange for the disposal of hazardous substances at sites where hazardous substances releases have occurred or are threatening
to occur. Parties responsible for the release or threatened release of hazardous substances under CERCLA may by subject to
joint and several liability for the cost of cleaning up those substances and for damages to natural resources;
|
|
●
|
the
Oil Pollution Act of 1990 (“
OPA
”) subjects owners and operators of facilities to strict, joint and
several liability for containment and cleanup costs and certain other damages arising from oil spills, including the government’s
response costs. Spills subject to the OPA may result in varying civil and criminal penalties and liabilities;
|
|
●
|
the
Resource Conservation and Recovery Act, as amended (“
RCRA
”), and comparable state statues which
govern the treatment, storage and disposal of solid nonhazardous and hazardous waste and authorize the imposition of substantial
fines and penalties for noncompliance;
|
|
●
|
the
Federal Water Pollution Control Act, as amended, also known as the Clean Water Act (“
CWA
”), and
analogous state laws that govern the discharge of pollutants, including natural gas wastes, into federal and state waters,
including spills and leaks of hydrocarbons and produced water. These controls have become more stringent over the years, and
it is possible that additional restrictions will be imposed in the future. Permits are required to discharge pollutants into
certain state and federal waters and to conduct construction activities in those waters and wetlands. The CWA and comparable
state statutes provide for civil, criminal and administrative penalties for any unauthorized discharges of oil and other pollutants
and impose liability for the costs of removal or remediation of contamination resulting from such discharges;
|
|
●
|
the
Safe Drinking Water Act (“
SDWA
”), which governs the disposal of wastewater in underground injection
wells; and
|
|
●
|
the
Clean Air Act (“
CAA
”) and similar state and local requirements which govern the emission of pollutants
into the air. Greenhouse gas record keeping and reporting requirements under the CAA took effect in 2011 and impose increased
administrative and control costs. In recent years, the Environmental Protection Agency (“
EPA
”) issued
final rules to subject oil and natural gas operations to regulation under the New Source Performance Standards, or NSPS, and
National Emission Standards for Hazardous Air Pollutants, or NESHAPS, programs under the CAA, and to impose new and amended
requirements under both programs. The EPA rules include NSPS standards for completions of hydraulically fractured oil and
natural gas wells, compressors, controllers, dehydrators, storage tanks, natural gas processing plants and certain other equipment.
In addition, the EPA finalized a more stringent National Ambient Air Quality Standard (“
NAAQS
”)
for ozone in October 2015. This more stringent ozone NAAQS could result in additional areas being designated as non-attainment,
which may result in an increase in costs for emission controls and requirements for additional monitoring and testing, as
well as a more cumbersome permitting process. EPA promulgated final area designations for the majority of the country in November
2017, and for the remainder of the country excluding San Antonio, Texas, in April 2018. EPA must promulgate the
final area designations for San Antonio no later than July 2018.
|
Changes in environmental laws and regulations
occur frequently, and any changes that result in more stringent and costly waste handling, storage, transport, disposal, cleanup
or operating requirements could materially adversely affect our operations and financial condition, as well as those of the oil
and natural gas industry in general. For instance, recent scientific studies have suggested that emissions of certain gases, commonly
referred to as “greenhouse gases,” and including carbon dioxide and methane, may be contributing to the warming of
the Earth’s atmosphere. Based on these findings, the EPA has begun adopting and implementing a comprehensive suite of regulations
to restrict emissions of greenhouse gases under existing provisions of the CAA. Legislative and regulatory initiatives related
to climate change and greenhouse gas emissions could, and in all likelihood would, require us to incur increased operating costs
adversely affecting our profits and could adversely affect demand for the oil and natural gas we and they produce, depressing
the prices we receive for oil and natural gas. See “
Risk Factors—Risks Related to Regulatory Requirements—The
adoption of climate change legislation or regulations restricting emissions of “greenhouse gases” could result in
increased operating costs and reduced demand for the oil and natural gas we produce.
”
We currently operate or lease, and have
in the past operated or leased, a number of properties that have been subject to the exploration and production of oil and natural
gas. Although we have utilized operating and disposal practices that were standard in the industry at the time, hydrocarbons or
other wastes may have been disposed of or released on or under the properties operated or leased by us or on or under other locations
where such wastes have been taken for disposal. In addition, these properties may have been operated by third parties whose treatment
and disposal or release of hydrocarbons or other wastes was not under our control. These properties and the wastes disposed thereon
may be subject to laws and regulations imposing joint and several liability and strict liability without regard to fault or the
legality of the original conduct that could require us to remove previously disposed wastes or remediate property contamination,
or to perform well or pit closure or other actions of a remedial nature to prevent future contamination.
Oil and natural gas deposits exist in
shale and other formations. It is customary in our industry to recover oil and natural gas from these formations through the use
of hydraulic fracturing, combined with horizontal drilling. Hydraulic fracturing is the process of injecting substances such as
water, sand, and other additives under pressure into subsurface formations to create or expand fractures, thus creating a passageway
for the release of oil and natural gas.
Most of our and Carbon Appalachia’s
Appalachian Basin oil and natural gas reserves are subject to or have been subjected to hydraulic fracturing and we expect to
continue to employ hydraulic fracturing extensively in future wells that we drill and complete. The reservoir rock in these areas,
in general, has insufficient permeability to flow enough oil or natural gas to be economically viable without stimulation. The
controlling regulatory agencies for well construction have standards that are designed specifically in anticipation of hydraulic
fracturing. The cost of the stimulation process varies according to well location and reservoir.
We contract with established service companies
to conduct our hydraulic fracturing. The personnel of these service companies are trained to handle potentially hazardous materials
and possess emergency protocols and equipment to deal with potential spills and carry Safety Data Sheets for all chemicals. We
require these service companies to carry insurance covering incidents that could occur in connection with their activities. In
addition, these service companies are responsible for obtaining any regulatory permits necessary for them to perform their service
in the relevant geographic location. We have not had any incidents, citations or lawsuits resulting from hydraulic fracture stimulation
and we are not presently aware of any such matters.
In the well completion and production
process, an accidental release could result in possible environmental damage. All wells have manifolds with escape lines to containment
areas. High pressure valves for flow control are on the wellhead. Valves and piping are designed for higher pressures than are
typically encountered. Piping is tested prior to any procedure and regular safety inspections and incident drill records
are kept on those tests.
All fracturing is designed with the minimum
water requirements necessary since there is a cost of accumulating, storing and disposing of the water recovered from fracturing.
Water is drawn from nearby streams that are tributaries to the Ohio River and flow 365 days per year. Water recovered from the
fracturing is injected into EPA or state approved underground injection wells. In some instances, the operation of underground
injection wells has been alleged to cause earthquakes (induced seismicity) as a result of flawed well design or operation. This
has resulted in stricter regulatory requirements in some jurisdictions relating to the location and operation of underground injection
wells. In addition, the California Division of Oil, Gas & Geothermal Resources (“
DOGGR
”) adopted
regulations intended to bring California’s Class II Underground Injection Control (“
UIC
”) program
into compliance with the federal Safe Drinking Water Act, under which some wells may require an aquifer exemption. DOGGR began
reviewing all active UIC projects, regardless of whether an exemption is required. In addition, DOGGR has undertaken a comprehensive
examination of existing regulations and plans to issue additional regulations with respect to certain oil and gas activities in
2018, such as management of idle wells, pipelines and underground fluid injection. The potential adoption of federal, state and
local legislation and regulations in the areas in which we operate could restrict our ability to dispose of produced water gathered
from drilling and production activities, which could result in increased costs and additional operating restrictions or delays.
While hydraulic fracturing historically
has been regulated by state and natural gas commissions, the practice has become increasingly controversial in certain parts of
the country, resulting in increased scrutiny and regulation from federal agencies. The EPA has asserted federal regulatory authority
pursuant to the federal SDWA over hydraulic fracturing involving fluids that contain diesel fuel and published permitting guidance
in February 2014 for hydraulic fracturing operations that use diesel fuel in fracturing fluids in those states in which EPA is
the permitting authority. In recent years, the EPA has issued final regulations under the federal CAA establishing performance
standards for completions of hydraulically fractured oil and natural gas wells, compressors, controllers, dehydrators, storage
tanks, natural gas processing plants and certain other equipment, and also finalized rules in June 2016 that prohibit the discharge
of wastewater from hydraulic fracturing operations to publicly owned wastewater treatment plants. Many producing states, cities
and counties have adopted, or are considering adopting, regulations that could impose more stringent permitting, public disclosure
and well construction requirements on hydraulic fracturing operations or otherwise seek to ban fracturing activities altogether.
In addition, separate and apart from the referenced potential connection between injection wells and seismicity, concerns have
been raised that hydraulic fracturing activities may be correlated to induced seismicity. The scientific community and regulatory
agencies at all levels are studying the possible linkage between oil and gas activity and induced seismicity, and some state regulatory
agencies have modified their regulations or guidance to mitigate potential causes of induced seismicity. If legislation or regulations
are adopted at the federal, state or local level imposing any restrictions on the use of hydraulic fracturing, this could have
a significant impact on our financial condition, results of operations and cash flows. Additional burdens upon hydraulic fracturing,
such as reporting or permitting requirements, will result in additional expense and delay in our operations. Restrictions on hydraulic
fracturing could also reduce the amount of oil and natural gas that we are ultimately able to produce from our reserves. See “
Risk
Factors—Risks Related to Regulatory Requirements—Environmental legislation and regulatory initiatives, including those
relating to hydraulic fracturing and underground injection, could result in increased costs and additional operating restrictions
or delays
.”
Any of the above factors could have a
material adverse effect on our financial position, results of operations or cash flows and could make it more difficult or costly
for us to perform hydraulic fracturing.
We are subject to the requirements of
OSHA and comparable state statutes. The OSHA Hazard Communication Standard, the “community right-to-know” regulations
under Title III of the federal Superfund Amendments and Reauthorization Act and similar state statutes require us to organize
information about hazardous materials used, released or produced in our operations. Certain of this information must be provided
to employees, state and local governmental authorities and local citizens. We are also subject to the requirements and reporting
set forth in OSHA workplace standards.
We believe that it is reasonably likely
that the trend in environmental legislation and regulation will continue toward stricter standards. While we believe that we are
in substantial compliance with applicable environmental laws and regulations in effect at the present time and that continued
compliance with existing requirements will not have a material adverse impact on us, we cannot give any assurance that we will
not be adversely affected in the future. We have established internal guidelines to be followed in order to comply with environmental
laws and regulations in the U.S. Although we maintain pollution insurance against the costs of cleanup operations, public liability,
and physical damage, there is no assurance that such insurance will be adequate to cover all such costs or that such insurance
will continue to be available in the future.
Employees
As of June 30, 2018, our workforce
(including those employed by our subsidiaries Nytis LLC, Carbon California and Carbon California Operating Company) consisted
of 189 employees, all of which are full-time employees. None of the members of our workforce are represented by a union or covered
by a collective bargaining agreement. We believe we have a good relationship with the members of our workforce.
Geographical Data
We operate in one geographical area, the continental United
States. See Note 1 to the consolidated financial statements.
Offices
Our executive offices are located at 1700
Broadway, Suite 1170, Denver, Colorado 80290. We maintain an office in Lexington, Kentucky and Santa Paula, California from which
we conduct our oil and gas operations.
Title to Properties
Title to our oil and gas properties is
subject to royalty, overriding royalty, carried, net profits, working, and similar interests customary in the oil and gas industry.
Under the terms of our New Revolving Credit Facility, we have granted the lender a lien on a substantial majority of our properties.
In addition, our properties may also be subject to liens incident to operating agreements, as well as other customary encumbrances,
easements, and restrictions, and for current taxes not yet due. Our general practice is to conduct title examinations on material
property acquisitions. Prior to the commencement of drilling operations, a title examination and, if necessary, curative work
is performed. The methods of title examination that we have adopted are reasonable in the opinion of management and are designed
to ensure that production from our properties, if obtained, will be salable by us.
Legal Proceedings
We are subject to legal claims and proceedings
in the ordinary course of its business. Management believes that should the controversies be resolved against us, none of the
current pending proceedings would have a material adverse effect on us.
MANAGEMENT
Directors and Officers
The following sets forth information regarding
our directors and officers. We expect to appoint an additional independent director upon the completion of this offering such
that our board of directors will consist of seven members.
Name
|
|
Age
|
|
Position
|
Patrick R. McDonald
|
|
61
|
|
Chief Executive Officer and Director
|
Mark D. Pierce
|
|
64
|
|
President
|
Kevin D. Struzeski
|
|
59
|
|
Chief Financial Officer, Treasurer and Secretary
|
James H. Brandi
|
|
69
|
|
Chairman of the Board
|
David H. Kennedy
|
|
68
|
|
Director
|
Bryan H. Lawrence
|
|
75
|
|
Director
|
Peter A. Leidel
|
|
61
|
|
Director
|
Edwin H. Morgens
|
|
76
|
|
Director
|
Chief Executive Officer and Director
Patrick R. McDonald
. Mr. McDonald
is Chief Executive Officer of the Company and has been Chief Executive Officer, President and Director of Nytis USA since 2004.
From 1998 to 2003, Mr. McDonald was Chief Executive Officer, President and Director of Carbon Energy Corporation, an oil and gas
exploration and production company which in 2003 was merged with Evergreen Resources, Inc. From 1987 to 1997 Mr. McDonald was
Chief Executive Officer, President and Director of Interenergy Corporation, a natural gas gathering, processing and marketing
company which in December 1997 was merged with KN Energy Inc. Prior to that he worked as an exploration geologist with Texaco
International Exploration Company where he was responsible for oil and gas exploration efforts in the Middle East and Far East.
Mr. McDonald served as Chief Executive Officer of Forest Oil Corporation from June 2012 until the completion of its business combination
with Sabine Oil & Gas in December 2014. Mr. McDonald also is Chairman of the Board of Prairie Provident Resources (TSX: PPR),
an exploration and production company based in Calgary, Alberta, Canada. Mr. McDonald received a Bachelor’s degree in both
Geology and Economics from Ohio Wesleyan University and a Masters degree in Business Administration (Finance) from New York University.
Mr. McDonald is a Certified Petroleum Geologist and is a member of the American Association of the Petroleum Geologists and of
the Canadian Society of Petroleum Geologists.
Our Board of Directors believes that Mr. McDonald,
as our Chief Executive Officer and as the founder of Nytis USA, should serve as a director because of his unique understanding
of the opportunities and challenges that we face and his in-depth knowledge about the oil and natural gas business, and our long-term
growth strategies.
Other Directors
The following information pertains to
our non-employee directors, their principal occupations and other public company directorships for at least the last five years
and information regarding their specific experiences, qualifications, attributes and skills.
James H. Brandi
. Mr. Brandi has
been a Director since March 2012 and Chairman of the Board since October 2012. Mr. Brandi retired from a position as Managing
Director of BNP Paribas Securities Corp., an investment banking firm, where he served from 2010 until late 2011. From 2005 to
2010, Mr. Brandi was a partner of Hill Street Capital, LLC, a financial advisory and private investment firm which was purchased
by BNP Paribas in 2010. From 2001 to 2005, Mr. Brandi was a Managing Director at UBS Securities, LLC, where he was the Deputy
Global Head of the Energy and Power Groups. Prior to 2001, Mr. Brandi was a Managing Director at Dillon, Read & Co. Inc. and
later its successor firm, UBS Warburg, concentrating on transactions in the energy and consumer goods areas. Mr. Brandi currently
serves as a director of OGE Energy Corp (NYSE: OGE) and served as a director of Approach Resources, Inc.
Our Board of Directors believes that Mr.
Brandi should serve as director and our Chairman because of his experience on the board of directors of other public companies,
which our Board believes is beneficial to us as a public company. He also has extensive financial expertise from his education
background (Harvard MBA) and his 35 year career in investment banking. His background contributes to the Board of Directors’
oversight responsibility regarding the quality and integrity of our accounting and financial reporting process and the auditing
of our financial statements.
David H. Kennedy
. Mr. Kennedy has
been a Director since December 2014 and previously served as a director of the Company from February 2011 to March 2012. Mr. Kennedy
has served as Executive Advisor to Cadent Energy Partners since 2005. He was director and chairman of the audit committee of Logan
International Inc. from 2006 until the sale of the company in 2016. From 2001 - 2004, Mr. Kennedy served as an advisor to RBC
Energy Fund and served on the boards of several of its portfolio companies. From 1999 to 2003, Mr. Kennedy was a director of Carbon
Energy Corporation before its merger with Evergreen Resources in 2003. From 1996 to 2006, Mr. Kennedy was a director and chairman
of the audit committee of Maverick Tube Corporation, which was sold to Tenaris SA in 2006. He was a managing director of First
Reserve Corporation from its founding in 1981 until 1998, serving on numerous boards of its portfolio companies. From 1974 to
1981, Mr. Kennedy was with Price Waterhouse in San Francisco and New York in audit and tax services before leaving to join First
Reserve. He was a Certified Public Accountant.
Our Board of Directors believes that Mr.
Kennedy should serve as director because of his current and prior experience as a director of us together with his experience
on the board of directors of other public companies. His energy industry knowledge and financial expertise is important in his
role as Chairman of the Audit Committee and its oversight responsibility regarding the quality and integrity of our accounting
and financial reporting process and the auditing of our financial statements.
Bryan H. Lawrence
. Mr. Lawrence
has been a Director since February 2011 and of Nytis USA since 2005. Mr. Lawrence is a founder and member of Yorktown Partners
LLC which was established in September 1990. Yorktown Partners LLC is the manager of private equity partnerships that invest in
the energy industry. Mr. Lawrence had been employed at Dillon, Read & Co. Inc. since 1966, serving as a Managing Director
until the merger of Dillon Read with SBC Warburg in September 1997. Mr. Lawrence also serves as a Director of Star Gas Partners,
L.P. (NYSE: SGU), Hallador Energy Company (NASDAQ: HNRG) and certain non-public companies in the energy industry in which Yorktown
partnerships hold equity interests. Mr. Lawrence served as a director of Approach Resources, Inc. and Interenergy Corporation.
Our Board of Directors believes that Mr. Lawrence
should serve as a director because of his experience on the board of directors of other public companies, which our Board of Directors
believes is beneficial to us as a public company, as well as Mr. Lawrence’s relevant business experience in the energy
industry and his extensive financial expertise, which he has acquired through his years of experience in the investment banking
industry.
Peter A. Leidel
. Mr. Leidel
has been a Director since February 2011 and of Nytis USA since 2005. Mr. Leidel is a founder and member of Yorktown Partners LLC
which was established in September 1990. Yorktown Partners LLC is the manager of private equity partnerships that invest in the
energy industry. Previously, he was a Senior Vice President of Dillon, Read & Co. Inc. He was previously employed in corporate
treasury positions at Mobil Corporation and worked for KPMG Peat Marwick and the U.S. Patent and Trademark Office. Mr. Leidel
is a director of Mid-Con Energy Partners, L.P. (NASDAQ: MCEP), Extraction Oil & Gas, Inc. (NASDAQ: XOG) and certain non-public
companies in the energy industry in which Yorktown partnerships hold equity interests. Mr. Leidel served as a director of Carbon
Energy Corporation and Interenergy Corporation. He was a Certified Public Accountant.
Our Board of Directors believes that Mr. Leidel
should serve as a director because of his significant knowledge of our industry, his prior experience with our business and his
financial expertise, which is important as our Board of Directors exercises its oversight responsibility regarding the quality
and integrity of our accounting and financial reporting processes and the auditing of our financial statements.
Edwin H. Morgens
. Mr. Morgens has
been a Director since May 2012. Mr. Morgens is Chairman and Co-founder of Morgens, Waterfall, Vintiadis & Company, Inc., a
New York City investment firm that he founded in 1967. He is a former director of Wayside Technology Group, Inc., TransMontaigne,
Inc., Sheffield Exploration, Scientific American Magazine Inc. and the Henry J. Kaiser Family Foundation. He is currently a trustee
of the American Museum of Natural History, an Overseer of the Weill Cornell Medical College and emeritus trustee of Cornell University.
Our Board of Directors believes that Mr.
Morgens should serve as director because of his current and prior experience on the board of directors of other public companies
and his extensive financial expertise, which he has acquired through his years of experience in the financial investment advisory
industry.
Other Executive Officers
Mark D. Pierce
. Mr. Pierce has
been President since October 2012 and was Senior Vice President for Nytis LLC from 2009 to 2012. From 2005 until 2009, he was
Operations Manager for Nytis LLC. He began his career at Texaco, Inc. in 1975 and from 1977 until 1997 was employed by Ashland
Exploration, Inc. attaining the position of Vice President Eastern Region and Gas Marketing. His experience includes both domestic
and international work. He is a registered Petroleum Engineer in Kentucky, West Virginia and Ohio.
Kevin D. Struzeski
. Mr.
Struzeski has served as Treasurer and Secretary since 2011 and has been the Chief Financial Officer, Treasurer and Secretary of
Nytis USA since 2005. From 2003 to 2004, Mr. Struzeski was the Director of Treasury at Evergreen Resources, Inc., and
from 1998 to 2003, he was Chief Financial Officer, Secretary and Treasurer of Carbon Energy Corporation. Mr. Struzeski was also
Chief Financial Officer, Secretary and Treasurer of Carbon Energy Canada Corporation. Mr. Struzeski served as Accounting Manager
for Media One Group from 1997 to 1998 and prior to that was employed as Controller for Interenergy Corporation from 1995 to 1997.
Mr. Struzeski is a Certified Public Accountant.
Composition of our Board of Directors
Upon the closing of this offering, our
Board of Directors will consist of seven directors, each of whom is elected annually at the annual meeting of our stockholders
or through the affirmative vote of the holders of a majority of our voting stock in lieu of a meeting. Each director will continue
to serve as a director until such director’s successor is duly elected and qualified or until their earlier resignation,
removal or death.
Family Relationships
There are no family relationships between
or among any of the current directors or executive officers.
Involvement in Certain Legal Proceedings
During the past ten years, none of the
persons serving as our executive officers or directors have been the subject matter of any of the following legal proceedings
that are required to be disclosed pursuant to Item 401(f) of Regulation S-K including: (a) any bankruptcy petition filed by or
against any business of which such person was a general partner or executive officer either at the time of the bankruptcy or within
two years prior to that time; (b) any criminal convictions; (c) any order, judgment, or decree permanently or temporarily enjoining,
barring, suspending or otherwise limiting his involvement in any type of business, securities or banking activities; (d) any finding
by a court, the SEC or the CFTC to have violated a federal or state securities or commodities law, any law or regulation respecting
financial institutions or insurance companies, or any law or regulation prohibiting mail or wire fraud; or (e) any sanction or
order of any self-regulatory organization or registered entity or equivalent exchange, association or entity. Further, no such
legal proceedings are believed to be contemplated by governmental authorities against any director or executive officer.
In July 2015, Sabine Oil and Gas filed
for bankruptcy protection under Chapter 11. Mr. McDonald was a director of Sabine Oil and Gas and was a Chief Executive Officer
of Forest Oil Corporation, a predecessor of Sabine Oil and Gas. The Board does not believe this disclosure is material to an evaluation
of the ability or integrity of Mr. McDonald because of the extenuating circumstances relating to Sabine Oil and Gas’ business
and industry.
Director Independence
Under the NASDAQ rules, a director will
only qualify as an “independent director” if, in the opinion of our Board of Directors, that person does not have
a relationship that would interfere with the exercise of independent judgment in carrying out the responsibilities of a director.
Our Board of Directors has determined that Messrs. Brandi, Kennedy and Morgens are independent directors and the additional director
appointed upon the closing of this offering will also be an independent director as defined by the applicable NASDAQ rules. In
making such determination, our Board of Directors considered the relationships that each such non-employee director has with us
and all other facts and circumstances that our Board of Directors deemed relevant in determining their independence. In particular,
in considering the independence of our directors, our Board of Directors considered the association of certain of our directors
with the holders of more than 5% of our common stock as well as the effect of each of the transactions described in the “
Certain
Relationships and Related Party Transactions
” section of this prospectus.
There are no family relationships among any of our directors
or executive officers.
Code of Ethics
The Board has adopted a Board of Directors
Code of Business Conduct and Ethics, which applies to all of our directors. Our Code of Business of Conduct and Ethics covers
topics including, but not limited to, conflicts of interest, insider dealing, competition, discrimination and harassment, confidentiality,
bribery and corruption, sanctions and compliance procedures. A copy of our Board of Directors Code of Business Conduct and Ethics
is available at the “Corporate Governance” section of our website, http://www.carbonenergycorp.com/wp-content/uploads/2017/05/Board-of-Directors-Code-of-Conduct.pdf.
We also have an Employee Code of Conduct
which applies to all our employees and the employees of our subsidiaries. Our Code of Conduct covers topics including, but not
limited to, conflicts of interest, insider dealing, competition, discrimination and harassment, confidentiality, bribery and corruption,
sanctions and compliance procedures. A copy of the Code of Conduct is available at the “Corporate Governance” section
of our website, http://www.carbonenergycorp.com/wp-content/uploads/2017/05/Employee-Code-of-Conduct.pdf.
Committees of the Board
The Board has a standing Audit Committee
and a Compensation, Nominating and Governance Committee. The Board has adopted a formal written charter for each of these committees
that is available on our website at
www.carbonnaturalgas.com
.
Upon the closing of this offering, the
Audit Committee will be comprised of Messrs. Kennedy (Chairman), Morgens and our newly appointed independent director, each of
whom is an independent director under NASDAQ listing rules. The Board has determined that Mr. Kennedy qualifies as an “audit
committee financial expert” as defined by Securities and Exchange Commission rules.
The Audit Committee’s primary duties
and responsibilities are to assist the Board in monitoring the integrity of our financial statements, the independent registered
public accounting firm’s qualifications, performance and independence, management’s effectiveness of internal controls
and our compliance with legal and regulatory requirements. The Audit Committee is directly responsible for the appointment, retention,
compensation, evaluation and termination of our independent registered public accounting firm and has the sole authority to approve
all audit and permitted non-audit engagement fees and terms.
The Audit Committee was formed in September
2012 and held four meetings during 2017 and three meetings during the six months ended June 30, 2018.
Upon the closing of this offering, the
Compensation, Nominating and Governance Committee will be comprised of Messrs. Morgens (Chairman), Kennedy and our newly appointed
independent director, each of whom is an outside director for purposes of Section 162(m) of the Internal Revenue Code and a non-employee
director for purposes of Rule 16b-3 under the Exchange Act.
The Compensation, Nominating and Governance
Committee discharges the responsibilities of the Board with respect to our compensation programs and compensation of our executives
and directors. The Compensation, Nominating and Governance Committee has overall responsibility for determining the compensation
of our executive officers and reviewing director compensation. The Compensation, Nominating and Governance Committee is also charged
with the administration of our stock incentive plans.
Other functions of the Compensation, Nominating
and Governance Committee are to identify individuals qualified to become directors and recommend to the Board nominees for all
directorships, identify directors qualified to serve on Board committees and recommend to the Board members for each committee,
develop and recommend to the Board a set of corporate governance guidelines and otherwise take a leadership role in shaping our
corporate governance.
In identifying and evaluating nominees
for directors, the Compensation, Nominating and Governance Committee seeks to ensure that the Board possesses, in the aggregate,
the strategic, managerial and financial skills and experience necessary to fulfill its duties and to achieve its objectives, and
seeks to ensure that the Board is comprised of directors who have broad and diverse backgrounds, possessing knowledge in areas
that are of importance to us. In addition, the Compensation, Nominating and Governance Committee believes it is important that
at least one director have the requisite experience and expertise to be designated as an “audit committee financial expert.”
The Compensation, Nominating and Governance Committee looks at each nominee on a case-by-case basis regardless of who recommended
the nominee. In looking at the qualifications of each candidate to determine if their election would further the goals described
above, the Compensation, Nominating and Governance Committee takes into account all factors it considers appropriate, which may
include strength of character, mature judgment, career specialization, relevant technical skills or financial acumen, diversity
of viewpoint and industry knowledge. Each director nominee must display high personal and professional ethics, integrity and values
and sound business judgment.
The Compensation, Nominating and Governance
Committee also monitors corporate governance for the Board, which includes reviewing the Code of Business Conduct and Ethics and
evaluation of board and committee performance.
The Compensation, Nominating and Governance
Committee was formed in September 2012 and held four meetings during 2017 and two meetings during the six months ended June
30, 2018.
EXECUTIVE
COMPENSATION
This Executive Compensation section provides
an overview of (i) the elements of our compensation program for our named executive officers (“
NEOs
”),
(ii) the material compensation decisions made under that program and reflected in the executive compensation tables and (iii)
the material factors considered in making those decisions. We intend to provide our NEOs with compensation that is significantly
performance based. Our executive compensation program is designed to align pay with our performance on both short- and long-term
bases, link executive pay to the creation of value for stockholders and utilize compensation as a tool to assist us in attracting
and retaining high-caliber executives that we believe are critical to our long-term success.
Summary Compensation Table
Effective March 15, 2017 and pursuant
to the reverse stock split approved by the stockholders and Board of Directors, each 20 shares of issued and outstanding common
stock became one share of common stock and no fractional shares were issued. The tables in this section give retroactive effect
to the reverse stock split for all periods presented.
The following table sets forth information
relating to compensation awarded to, earned by or paid to our NEOs during the fiscal years ended December 31, 2017 and 2016.
Name and Principal Position
|
|
Year
|
|
Salary
($)
|
|
|
Stock
Awards
($)
(1)
|
|
|
Non-Equity
Incentive Plan Compensation
($)
(2)
|
|
|
All
Other Compensation
($)
(3)
|
|
|
Total
($)
|
|
Patrick R. McDonald
|
|
2017
|
|
|
383,750
|
|
|
|
144,000
|
|
|
|
438,725
|
|
|
|
62,159
|
|
|
|
1,028,634
|
|
Chief Executive Officer
|
|
2016
|
|
|
350,000
|
|
|
|
108,000
|
|
|
|
194,947
|
|
|
|
77,480
|
|
|
|
730,427
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Mark D. Pierce
|
|
2017
|
|
|
260,000
|
|
|
|
72,000
|
|
|
|
192,287
|
|
|
|
35,024
|
|
|
|
559,311
|
|
President
|
|
2016
|
|
|
236,000
|
|
|
|
108,000
|
|
|
|
85,442
|
|
|
|
9,264
|
|
|
|
438,706
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Kevin D. Struzeski
|
|
2017
|
|
|
270,000
|
|
|
|
72,000
|
|
|
|
201,247
|
|
|
|
40,549
|
|
|
|
583,796
|
|
Chief
Financial Officer, Treasurer and Secretary
(1)
|
|
2016
|
|
|
247,000
|
|
|
|
108,000
|
|
|
|
89,425
|
|
|
|
46,335
|
|
|
|
490,760
|
|
(1)
|
Reflects the full
grant date fair value of restricted stock awards granted in 2017 and 2016 calculated in accordance with FASB ASC Topic 718.
Please see Note 9 to our consolidated financial statements included in this prospectus.
|
|
|
(2)
|
Reflects payments
under the Annual Incentive Plan based on a combination of objective performance criteria and the discretion of the Compensation,
Nominating and Governance Committee. See discussion under Annual Incentive Plan below.
|
|
|
(3)
|
All other compensation
in 2017 and 2016 was comprised of (i) unused vacation, (ii) contributions made by us to our 401(k) plan, (iii) premiums paid
on life insurance policies on such employee’s life, and (iv) other taxable fringe benefits.
|
Narrative Disclosure to Summary Compensation Table
The Compensation, Nominating and Governance
Committee (the “
Committee
”) is charged with reviewing and approving the terms and structure of the compensation
of our executive officers. The Committee has not retained an independent compensation consultant to assist the Committee to review
and analyze the structure and terms of the compensation of our executive officers.
We consider various factors when evaluating
and determining the compensation terms and structure of its executive officers, including the following:
|
1.
|
the executive’s
leadership and operational performance and potential to enhance long-term value to our stockholders;
|
|
2.
|
our financial resources,
results of operations, and financial projections;
|
|
3.
|
performance compared
to the financial, operational and strategic goals established for us;
|
|
4.
|
the nature, scope
and level of the executive’s responsibilities;
|
|
5.
|
competitive market
compensation paid by other companies for similar positions, experience and performance levels; and
|
|
6.
|
the executive’s
current salary and the appropriate balance between incentives for long-term and short-term performance.
|
Our management is responsible for reviewing
the base salary, annual bonus and long-term compensation levels for other of our employees, and we expect this practice to continue
going forward. The Compensation, Nominating and Governance Committee is responsible for significant changes to, or adoption of,
employee benefit plans.
We believe that the compensation environment
for qualified professionals in the industry in which we operate is highly competitive. In order to compete in this environment,
the compensation of our executive officers is primarily comprised of the following four components:
|
●
|
stock incentive plan benefits;
|
|
●
|
annual Incentive Plan Payments; and
|
|
●
|
other employment benefits.
|
Base Salary.
Base salary, paid
in cash, is the first element of compensation to our officers. In determining base salaries for our key executive officers, we
aim to set base salaries at a level we believe enables us to hire and retain individuals in a competitive environment and to reward
individual performance and contribution to our overall business goals. The Board of Directors and the Committee believe that base
salary should be relatively stable over time, providing the executive a dependable, minimal level of compensation, which is approximately
equivalent to compensation that may be paid by competitors for persons of similar abilities. The Board of Directors and the Committee
believe that base salaries for our executive officers are appropriate for persons serving as executive officers of public companies
similar in size and complexity to us.
Stock Incentive Plan Benefits.
Each
of our executive officers is eligible to be granted awards under our equity compensation plans. We believe that equity based compensation
helps align management and executives’ interests with the interests of our stockholders. Our equity incentives are also
intended to reward the attainment of long-term corporate objectives by our executives. We also believe that grants of equity-based
compensation are necessary to enable us to be competitive from a total remuneration standpoint. We have no set formula
for granting awards to our executives or employees. In determining whether to grant awards and the amount of any awards, we take
into consideration discretionary factors such as the individual’s current and expected future performance, level of responsibilities,
retention considerations and the total compensation package.
Annual Incentive Plan.
Cash
payments made under the provisions of our Annual Incentive Plan (“
AIP
”) is another component of our
compensation plan. The Board of Directors and the Committee believes that it is appropriate that executive officers
and other employees have the potential to receive a portion of their annual compensation based upon the achievement of defined
objectives in order to encourage performance to achieve these key corporate objectives and to be competitive from a total remuneration
standpoint.
In general terms, the AIP is designed
to meet the following objectives:
|
●
|
provide an incentive
plan framework that is performance-driven and focused on objectives that were critical to our success during the plan period
dates;
|
|
●
|
offer competitive cash compensation opportunities
to the executive officers and all employees;
|
|
●
|
incentivize and reward outstanding achievement;
and
|
|
●
|
incentivize the creation of new assets, plays
and values.
|
The AIP provided cash pools for all employees.
Once the pools were established, awards were allocated by the executive officers to individuals based on their assessment as to
individual or group performances.
Payments in 2017 were determined under
the provisions of the Carbon Natural Gas Company 2016 Annual Incentive Plan whereby seventy percent of the AIP payments were determined
at the discretion of the Board taking into consideration the factors listed above and thirty percent of the AIP payments were
determined and weighted based upon the performance measures and objectives as follows:
Performance
Measure
|
|
Weighting
|
|
Objective
|
Lease Operating Expense
|
|
33 1/3%
|
|
$1.11/Mcfe (6:1 equivalent basis)
|
General and Administrative Expenses
|
|
33 1/3%
|
|
$4.2 million of cash-based general and administrative
expenses
|
Year-End Bank Debt
|
|
33 1/3%
|
|
Year-end bank debt of $9.045 million
|
Payments in 2016 were determined under
the provisions of the Carbon Natural Gas Company 2015 Annual Incentive Plan whereby seventy percent of the AIP payments were determined
at the discretion of the Committee taking into consideration the factors listed above and thirty percent of the AIP payments were
determined and weighted based upon the performance measures and objectives as follows:
Performance
Measure
|
|
Weighting
|
|
Objective
|
Lease Operating Expense
|
|
33 1/3%
|
|
$0.87/Mcfe (15:1 equivalent basis)
|
General and Administrative Expenses
|
|
33 1/3%
|
|
$5.4 million of cash-based general and administrative
expenses
|
Debt/EBITDA Ratio
|
|
33 1/3%
|
|
Debt/EBITDA ratio of 1.6
|
Other Compensation/Benefits.
Another
element of the overall compensation is to provide our executive officers various employment benefits, such as the payment of health
and life insurance premiums on behalf of the executive officers. Our executive officers are also eligible to participate
in our 401(k) plan on the same basis as other employees and we historically have made matching contributions to the 401(k) plan,
including for the benefit of our executive officers.
Pursuant to the employment agreements
with Messrs. McDonald, Pierce and Struzeski, such officers are entitled to certain payments upon termination of employment. See
Employment Contracts and Termination of Employment and Change-in-Control Arrangements below. Other than these arrangements, we
currently do not have any compensatory plans or arrangements that provide for any payments or benefits upon the resignation, retirement
or any other termination of any of our executive officers, as the result of a change in control, or from a change in any executive
officer’s responsibilities following a change in control.
Outstanding Equity Awards at December 31, 2017
The following table sets forth information
concerning unexercised warrants and unvested restricted stock and performance unit awards, each as held by our executive officers
as of December 31, 2017.
|
|
Equity
Incentive Plan Awards
|
|
Name
|
|
Number
of unvested restricted shares
(#)
|
|
|
Number
of unvested restricted shares
($)
(1)
|
|
|
Number
of unvested restricted shares
(#)
|
|
|
Number
of unvested restricted shares
($)
(1)
|
|
Patrick R. McDonald
|
|
|
40,000
|
|
|
|
440,000
|
|
|
|
78,080
|
|
|
|
858,880
|
|
Mark D. Pierce
|
|
|
30,000
|
|
|
|
330,000
|
|
|
|
44,040
|
|
|
|
484,440
|
|
Kevin D. Struzeski
|
|
|
30,000
|
|
|
|
330,000
|
|
|
|
44,040
|
|
|
|
484,440
|
|
(1)
|
Reflects the value
of unvested shares of restricted stock and performance unit awards held by our executive officers as of December 31, 2017,
measured by the closing market price of our common stock on December 31, 2017, which was $11.00 per share.
|
The following table reflects unvested
stock awards held by our executive officers as of December 31, 2017 that have time-based vesting. These stock awards will vest
as follows if the named executive officer has remained in continuous employment through the vesting date in each such year:
Award
Recipient
|
|
2018
|
|
|
2019
|
|
|
2020
|
|
|
Thereafter
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Patrick R. McDonald
|
|
|
20,000
|
|
|
|
13,334
|
|
|
|
6,666
|
|
|
|
-
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Mark D. Pierce
|
|
|
10,000
|
|
|
|
16,667
|
|
|
|
3,334
|
|
|
|
-
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Kevin D. Struzeski
|
|
|
10,000
|
|
|
|
16,667
|
|
|
|
3,334
|
|
|
|
-
|
|
The following table reflects unvested
performance stock awards held by our executive officers as of December 31, 2017 that vest upon the achievement of certain performance
measures relative to a defined peer group or the growth of certain performance measures over a defined period of time and, in
certain cases, based on continuous service. These performance stock awards will vest as follows if the named executive officer
has remained in continuous employment with us through the date of a change in control and if the executive officer earns 100%
of the performance stock awards based upon the achievement of certain performance measures relative to a defined peer group or
the growth of certain performance measures over a defined period of time for us.
Stock
Award Recipient
|
|
Change
of Control
|
|
|
Stock
Price and Defined Performance Measures Relative to Peer Group
|
|
Patrick
R. McDonald
|
|
|
18,080
|
|
|
|
60,000
|
|
Mark D. Pierce
|
|
|
9,040
|
|
|
|
37,500
|
|
Kevin D. Struzeski
|
|
|
9,040
|
|
|
|
37,500
|
|
Employment Contracts and Termination of Employment and Change-in-Control
Arrangements
Effective March 30, 2013, Messrs. McDonald,
Pierce and Struzeski entered into employment agreements with us. These agreements superseded employment agreements between Messrs.
McDonald and Struzeski and Nytis Exploration Company and between Mr. Pierce and Nytis LLC.
The agreement between us and Patrick R.
McDonald has a term through December 31, 2018, which term shall automatically be extended for successive terms of one-year provided,
however, that the Board of Directors may terminate the agreement at the end of the term or any additional term by giving written
notice of termination at least three months preceding the end of the then current term. In the event of the termination of Mr.
McDonald’s employment by us without cause or by Mr. McDonald with good reason, Mr. McDonald is to receive an amount equal
to 150% of his “Compensation,” defined as the arithmetic average of Mr. McDonald’s annual base salary, bonus
and other cash compensation for each of the three years prior to the termination and for a period of 24 months from the date of
termination, his medical, dental, disability and life insurance coverage at the same levels of coverage as in effect immediately
prior to his termination. In the event of termination of employment by us without cause or by Mr. McDonald with good reason within
two years after a change in control of us, he is to receive 275% of the Compensation (as defined above).
The agreements between us and Messrs.
Pierce and Struzeski have a term through December 31, 2018, which term shall automatically be extended for successive terms of
one-year provided, however, that the Board of Directors may terminate the agreement at the end of the term or any additional term
by giving written notice of termination at least three months preceding the end of the then current term. In the event of the
termination of Mr. Pierce’s or Mr. Struzeski’s employment by us without cause or by the executive with good reason,
they would receive an amount equal to 100% of his “Compensation,” defined as the arithmetic average of their annual
base salary, bonus and other cash compensation for each of the three years prior to the termination and the cost to provide benefits
for a period of 12 months from the date of termination at the same levels of coverage as in effect immediately prior to the date
of termination. In the event of termination of employment by us without cause or by the executive with good reason within two
years after a change in control of us, they would receive 200% of their Compensation (as defined above) and 100% of the annual
cost to us of the benefits provided to Messrs. Pierce and Struzeski.
Director Compensation
We use a combination of cash and equity
incentive compensation in the form of restricted stock to attract and retain qualified and experienced non-employee candidates
to serve on the Board. In setting this compensation, our Compensation, Nominating and Governance Committee considers the significant
amount of time and energy expended and the skill level required by our directors in fulfilling their duties. Grants of shares
of restricted stock vest upon the earlier of a change in control of us or the date a non-management director’s membership
on the Board is terminated other than for cause. We also reimburse expenses incurred by our non-employee directors to attend Board
and Board committee meetings.
The following table reports compensation
earned by or paid to our non-employee directors during 2017:
Name
|
|
Fees
earned or paid in cash
|
|
|
Stock
awards
($)
(1)
|
|
|
Option
awards
($)
|
|
|
Non-equity
incentive plan compensation
($)
|
|
|
Nonqualified
deferred compensation earnings
($)
|
|
|
All
other compensation
($)
|
|
|
Total
($)
|
|
James
H. Brandi
|
|
$
|
30,000
|
|
|
$
|
36,000
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
$
|
66,000
|
|
David H. Kennedy
|
|
$
|
20,000
|
|
|
$
|
28,800
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
$
|
48,800
|
|
Bryan H. Lawrence
|
|
|
*
|
|
|
$
|
28,800
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
$
|
28,800
|
|
Peter A. Leidel
|
|
|
*
|
|
|
$
|
28,800
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
$
|
28,800
|
|
Edwin H. Morgens
|
|
$
|
20,000
|
|
|
$
|
28,800
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
$
|
48,800
|
|
*
|
Mr. Lawrence and
Mr. Leidel are employees of Yorktown Energy Partners, L.P., and have elected not to be compensated in cash for their services
on the board of directors. Mr. Lawrence and Mr. Leidel each received stock awards.
|
(1)
|
Reflects the full
grant date fair value of restricted stock award granted in 2017 calculated in accordance with FASB ASC Topic 718.
|
Narrative Disclosure to Director Compensation Table
Each independent director is compensated
$20,000 for a board seat and $10,000 additional for being chairman of the Board of Directors
Each director was granted 4,000 restricted
shares which vest upon a change in control of us or the date their membership terminates for other than cause. In addition, the
chairman of the board of directors receives an additional 1,000 shares for a total of 5,000.
Compensation Committee Interlocks and Insider Participation
None of our officers or employees are
members of our Compensation, Nominating and Governance Committee. None of our executive officers serves on the board of directors
or compensation committee of a company that has an executive officer that serves on our Board of Directors or Compensation Committee.
No member of our Board of Directors is an executive officer of a company in which one of our executive officers serves as a member
of the board of directors or compensation committee of that company.
To the extent any member of our Compensation,
Nominating and Governance Committee and affiliates of theirs has participated in transactions with us, a description of those
transactions would be described in “
Certain Relationships and Related Party Transactions
.”
CERTAIN
RELATIONSHIPS AND RELATED PARTY TRANSACTIONS
The following sets forth information regarding
transactions between us (and our subsidiaries) and our officers, directors and significant stockholders since January 1, 2015.
Employment Agreements
See “
Executive Compensation
”
for a discussion of the employment agreements between Messrs. McDonald, Pierce and Struzeski and us.
Director Independence
Our Board consists of Messrs. Brandi,
Kennedy, Lawrence, Leidel, McDonald and Morgens. We utilize the definition of “independent” as it is set forth in
Rule 5605(a)(2) of the NASDAQ listing rules. Further, the Board considers all relevant facts and circumstances in its determination
of independence of all members of the Board (including any relationships). Based on the foregoing criteria, Messrs. Brandi, Kennedy
and Morgens are considered to be independent directors in accordance with NASDAQ listing rules. We plan to appoint an additional
independent director upon the completion of this offering.
Carbon California
Carbon California Operating Company
is our subsidiary and the operator of Carbon California through an operating agreement. The operating agreement includes reimbursements
and allocations made under the agreement. We received approximately $400,000 from Carbon California for the six months ended June
30, 2018. However, $350,000 of the amount received was eliminated in connection with the consolidation of Carbon California for
financial reporting purposes.
On February 15, 2017, we entered into
a management service agreement with Carbon California whereby we provide general management and administrative services.
We receive $600,000 annually, payable in four equal quarterly installments. We also received a one-time reimbursement of
$500,000 in connection with the CRC and Mirada Acquisitions. Carbon California reimburses us for all management related expenses
such as travel, required third-party geological and/or accounting consulting, and other necessary expenses incurred by us in the
normal course of managing Carbon California. For the six months ended June 30, 2018, we recorded $50,000 in total management
reimbursements. There were no outstanding management reimbursements unpaid as of June 30, 2018.
On February 15, 2017, in connection with
the commencement of operations of Carbon California, we issued to Yorktown the California Warrant. The exercise price for the California
Warrant was payable exclusively with Class A Units of Carbon California and the number of shares of our common stock for which
the California Warrant was exercisable was determined by dividing (a) the aggregate unreturned capital of Yorktown’s
Class A Units of Carbon California by (b) the exercise price. The California Warrant had a term of seven years and included certain
standard registration rights with respect to the shares of our common stock issuable upon exercise of the California Warrant. On
February 1, 2018, Yorktown exercised the California Warrant and received 1,527,778 shares of common stock in us.
Carbon Appalachia
Nytis is the operator of Carbon Appalachia
through an operating agreement. The operating agreement includes reimbursements and allocations made under the agreement. As of
June 30, 2018, we did not have any outstanding amounts due from Carbon Appalachia and included in accounts receivable –
related party on the consolidated balance sheets.
On April 3, 2017, we entered into a
management service agreement with Carbon Appalachia whereby we provide general management and administrative services. We
initially received a quarterly reimbursement of $75,000; however, after the EnerVest Acquisition in August 2017, the amount of
the reimbursement now varies quarterly based upon the percentage of our production in relation to the total of our production
and Carbon Appalachia’s total production. We also received a one-time reimbursement of $300,000 in connection with the CNX
Acquisition. As of June 30, 2018, we did not have any outstanding amounts due from Carbon Appalachia and included in accounts
receivable – related party on the consolidated balance sheets.
On April 3, 2017, in connection with the
commencement of operations of Carbon Appalachia, we issued to Yorktown the Appalachia Warrant. The exercise price for the Appalachia
Warrant was payable exclusively with Class A Units of Carbon Appalachia and the number of shares of our common stock for which
the Appalachia Warrant was exercisable was determined by dividing (a) the aggregate unreturned capital plus an internal rate
of return on such capital of Yorktown’s Class A Units of Carbon Appalachia by (b) the exercise price. The Appalachia Warrant
had a term of seven years and included certain standard registration rights with respect to the shares of our common stock issuable
upon exercise of the Appalachia Warrant. On November 1, 2017, Yorktown exercised the Appalachia Warrant and received 432,051 shares
of common stock in us
Preferred Stock Issuance to Yorktown
On April 6, 2018, we raised $5.0 million
through the issuance of 50,000 shares of the Preferred Stock to Yorktown. We used the proceeds from the sale of the Preferred
Stock to fund our portion of the purchase price for the Seneca Acquisition. Upon the completion of this offering, the Preferred
Stock will automatically convert into shares of common stock. The conversion ratio at which the Preferred Stock will convert into
common stock is equal to an amount per share of $100 plus all accrued but unpaid dividends payable in respect thereof (together,
the “
Liquidation Preference
”) divided by the greater of (i) $8.00 per share or (ii) the price that is
15% less than the price per share of shares sold to the public in this offering. See “
Description of Capital Stock—Preferred
Stock
” for more information on the terms of our preferred stock.
Yorktown Registration Rights
Under the Purchase Agreement between Carbon
Natural Gas Company and Yorktown Energy Partners XI, LP, dated April 6, 2018, the Appalachia Warrants and the California Warrant,
Yorktown may make one or more written demands requiring us to register the shares of our common stock owned by Yorktown. In addition,
Yorktown has piggyback rights entitling them to require us to register shares of their common stock in connection with any registration
statements filed by us, subject to certain exceptions. We have agreed to indemnify Yorktown (to the extent they are selling stockholders
in any such registration) against losses suffered by them in connection with any untrue or alleged untrue statement of a material
fact contained in any registration statement, prospectus or preliminary prospectus or any omission or alleged omission to state
therein a material fact required to be stated therein or necessary to make the statement therein not misleading, except insofar
as the same may be caused by or contained in any information furnished in writing to us by such selling stockholder for use therein.
Yorktown has waived its registration rights in connection with this offering.
SECURITY
OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
The following table sets forth, as
of September 5, 2018, the amount and percentage of our outstanding shares of common stock beneficially owned by (i) each person
(including any group) known to us that beneficially own more than 5% of our outstanding shares of common stock, (ii) each director,
(iii) each of our executive officers and (iv) all of our directors and executive officers as a group:
Except as otherwise
indicated, the person or entities listed below have sole voting and investment power with respect to all shares of our common
stock beneficially owned by them, except to the extent this power may be shared with a spouse. All information with respect to
beneficial ownership has been furnished by the respective directors, named executive officers or 5% or more stockholders, as the
case may be. Unless otherwise indicated, the address for each listed beneficial owner is 1700 Broadway, Suite 1170, Denver, Colorado
80290.
Name of Beneficial Owners
|
|
Shares
Beneficially Owned
(1)
|
|
|
Percent
of Class
(2)
|
|
5% Holders:
|
|
|
|
|
|
|
Yorktown Energy Partners V, L.P.
|
|
|
896,915
|
|
|
|
11.9
|
%
|
Yorktown Energy Partners VI, L.P.
|
|
|
896,915
|
|
|
|
11.9
|
%
|
Yorktown Energy Partners IX, L.P.
|
|
|
1,111,111
|
|
|
|
14.7
|
%
|
Yorktown
Energy Partners XI, L.P.
(3)
|
|
|
2,584,829
|
|
|
|
31.0
|
%
|
Arbiter
Partners Capital Management LLC
(4)
|
|
|
655,733
|
|
|
|
8.5
|
%
|
AWM
Investment Company Inc.
(5)
|
|
|
706,549
|
|
|
|
9.2
|
%
|
Directors
|
|
|
|
|
|
|
|
|
Patrick
R. McDonald
(6)
|
|
|
211,416
|
|
|
|
2.7
|
%
|
James
H. Brandi
(7)
|
|
|
-
|
|
|
|
-
|
|
David
H. Kennedy
(8)
|
|
|
8,154
|
|
|
|
*
|
|
Bryan
H. Lawrence
(9)
|
|
|
5,489,770
|
|
|
|
65.9
|
%
|
Peter
A. Leidel
(10)
|
|
|
5,489,770
|
|
|
|
65.9
|
%
|
Edwin
H. Morgens
(11)
|
|
|
83,334
|
|
|
|
1.1
|
%
|
Executive Officers
|
|
|
|
|
|
|
|
|
Mark
D. Pierce
(12)
|
|
|
78,651
|
|
|
|
1.0
|
%
|
Kevin
D. Struzeski
(13)
|
|
|
101,286
|
|
|
|
1.3
|
%
|
All directors and
executive officers as a group (8 persons)
(14)
|
|
|
5,972,610
|
|
|
|
71.7
|
%
|
*
|
Represents less
than 1%
|
(1)
|
The amounts and
percentages of common stock beneficially owned are reported on the bases of regulations of the SEC governing the determination
of beneficial ownership of securities. Under the rules of the SEC, a person is deemed to be a “beneficial owner”
of a security if that person has or shares voting power, which includes the power to vote or direct the voting of such security,
or investment power, which includes the power to dispose of or to direct the disposition of such security. Securities that
can be so acquired are deemed to be outstanding for purposes of computing such person’s ownership percentage, but not
for purposes of computing any other person’s percentage. Under these rules, more than one person may be deemed beneficial
owner of the same securities and a person may be deemed to be a beneficial owner of securities as to which such person has
no economic interest. Except as otherwise indicated in these footnotes, each of the beneficial owners has, to our knowledge,
sole voting and investment power with respect to the indicated shares of common stock. The amounts shown in the table are
based on the conversion of the Series B Convertible Preferred Stock assuming a public offering price of $
per share (the midpoint of the price range set forth on the cover page of this prospectus). See “
Description of Capital Stock—Preferred Stock
.”
|
(2)
|
Based
on 7,700,619 shares of our common stock issued and outstanding on September 5, 2018.
|
(3)
|
The amount reported
includes 50,000 shares of Series B convertible preferred stock which currently may be converted into up to 625,000 shares
of our common stock. The address for Yorktown is 410 Park Avenue, 19
th
Floor, New York, New York 10022.
|
(4)
|
Includes 444,444
shares owned by Arbiter Partners QP, LP. Arbiter Partners QP, LP holds sole voting and investment power over these shares.
Arbiter Partners Capital Management LLC acts as investment advisor on behalf of Arbiter Partners QP, LP and on behalf
of certain other managed accounts none of which hold more than five percent of our common stock. The address for Arbiter Partners
Capital Management LLC is 530 Fifth Avenue, 20
th
Floor, New York, New York 10036.
|
(5)
|
Consists of (i)
490,186 common stock shares owned by Special Situations Fund III QP, L.P. (“
SSFQP
”), (ii) 144,134
common stock shares owned by Special Situations Cayman Fund, L.P. (“
Cayman
”), and (iii) 72,229 common
stock shares owned by Special Situations Private Equity Fund L.P. (“
SSPE
”). AWM Investment Company,
Inc., a Delaware corporation (“
AWM
”), is the investment advisor to SSFQP, Cayman and SSPE. AWM holds
sole voting and investment power over these shares. The address for AWM is c/o Special Situations Funds, 527 Madison Avenue,
Suite 2600, New York, New York 10022.
|
(6)
|
Includes 24,136
shares owned by McDonald Energy, LLC over which Mr. McDonald has voting and investment power. Does not include 40,000 and
78,080 shares of unvested restricted and performance units, respectively.
|
(7)
|
Does not include
32,000 restricted shares of our common stock, which vest upon the earlier of a change in control of us or the date the director’s
membership on the Board is terminated other than for cause.
|
(8)
|
Does not include
16,000 restricted shares of our common stock which vest upon the earlier of a change in control of us or the date the director’s
membership on the Board is terminated other than for cause.
|
(9)
|
Includes (i) 896,915
common stock shares owned by Yorktown Energy Partners V, L.P., (ii) 896,915 common stock shares owned by Yorktown Energy Partners
VI, L.P., (iii) 1,111,111 common stock shares owned by Yorktown Energy Partners IX, L.P., (iv) 1,959,829 common stock shares
owned by Yorktown Energy Partners XI, L.P. and (v) 50,000 shares of Series B convertible preferred stock owned by Yorktown
Energy Partners XI, L.P. which currently may be converted into up to 625,000 shares of our common stock over which Mr. Lawrence
and Mr. Leidel have voting and investment power. Pursuant to applicable reporting requirements, Messrs. Lawrence
and Leidel are reporting indirect beneficial ownership of the entire amount of our securities owned by Yorktown but they disclaim
beneficial ownership of such shares. Does not include 28,000 restricted shares of our common stock, which vest
upon the earlier of a change in control of us or the date the director’s membership on the Board is terminated other
than for cause.
|
(10)
|
Includes (i) 896,915
common stock shares owned by Yorktown Energy Partners V, L.P., (ii) 896,915 common stock shares owned by Yorktown Energy Partners
VI, L.P., (iii) 1,111,111 common stock shares owned by Yorktown Energy Partners IX, L.P., (iv) 1,959,829 common stock shares
owned by Yorktown Energy Partners XI, L.P. and (v) 50,000 shares of Series B convertible preferred stock owned by Yorktown
Energy Partners XI, L.P. which currently may be converted into up to 625,000 shares of our common stock over which Mr. Lawrence
and Mr. Leidel have voting and investment power. Pursuant to applicable reporting requirements, Messrs. Lawrence
and Leidel are reporting indirect beneficial ownership of the entire amount of our securities owned by Yorktown but they disclaim
beneficial ownership of such shares. Does not include 28,000 restricted shares of our common stock, which vest
upon the earlier of a change in control of us or the date the director’s membership on the Board is terminated other
than for cause.
|
(11)
|
Does not include
28,000 restricted shares of our common stock, which vest upon the earlier of a change in control of us or the date the director’s
membership on the Board is terminated other than for cause.
|
(12)
|
Does not include
30,000 and 41,540 shares of unvested restricted stock and performance units, respectively.
|
(13)
|
Does not include
30,000 and 41,540 shares of unvested restricted stock and performance units, respectively.
|
(14)
|
The (i) shares over
which both Mr. Lawrence and Mr. Leidel have voting and investment power are the same shares and (ii) the shares of Series
B convertible preferred stock are the same and the percentage of total shares has not been aggregated for purposes of these
calculations.
|
DESCRIPTION
OF CAPITAL STOCK
The following description of our amended
and restated certificate of incorporation and amended and restated bylaws are summaries thereof and are qualified by reference
to our amended and restated certificate of incorporation and amended and restated bylaws, copies of which have been filed with
the SEC.
General
Pursuant to our amended and restated certificate
of incorporation, our capital stock consists of 11,000,000 authorized shares, of which 10,000,000 shares, par value $0.01 per
share, are designated as “common stock” and 1,000,000 shares, par value $0.01 per share, are designated as “preferred
stock.” There are currently 7,700,619 shares of common stock and 50,000 shares of preferred stock issued and outstanding.
On June 1, 2018, we increased the number of authorized shares of our common stock from 10,000,000 to 35,000,000. Following the
consummation of this offering, there will be shares
of common stock and no shares of preferred stock issued and outstanding.
Common Stock
Voting Rights.
Holders of common
stock are entitled to one vote per share on all matters to be voted upon by the stockholders. Holders of common stock do not have
cumulative voting rights in the election of directors.
Dividend Rights.
Holders of common
stock are entitled to receive ratably dividends if, as and when dividends are declared from time to time by our Board of Directors
out of funds legally available for that purpose, after all dividends required to be paid on outstanding preferred stock (as described
below), if any, have been fully paid. Under Delaware law, we can only pay dividends either out of “surplus” or out
of the current or the immediately preceding year’s net profits. Surplus is defined as the excess, if any, at any given time,
of the total assets of a corporation over its total liabilities and statutory capital. The value of a corporation’s assets
can be measured in a number of ways and may not necessarily equal their book value.
Liquidation Rights.
Upon liquidation,
dissolution or winding up of our affairs, whether voluntary or involuntary, the holders of common stock are entitled to receive
ratably the funds remaining for distribution to the stockholders after payment of liabilities and accrued but unpaid dividends
and liquidation preferences on any outstanding preferred stock.
Other Matters.
Our common stock
has no preemptive, subscription or conversion rights. There are no redemption or sinking fund provisions applicable to our common
stock. All outstanding shares of our common stock are fully paid and non-assessable, and the shares of our common stock offered
in this offering, upon payment and delivery in accordance with the underwriting agreement, will be fully paid and non-assessable.
Preferred Stock
Pursuant to our amended and restated certificate
of incorporation, shares of preferred stock will be issuable from time to time, in one or more series, with the designations and
the powers, preferences and relative, participating, optional or other special rights, and qualifications, limitations, or restrictions
thereof, including without limitation, the dividend rate, conversion rights, redemption price and liquidation preference, of such
preferred stock, and to fix the number of shares constituting any such series thereof as our Board of Directors from time to time
may adopt by resolution (and without further stockholder approval), subject to certain limitations. Each series will consist of
that number of shares as will be stated and expressed in the certificate of designations providing for the issuance of the stock
of the series, which number may be increased or decreased from time to time by our Board of Directors (but not below the number
of shares thereof then outstanding). If the number of shares of any series is to be so decreased, the shares constituting such
decrease shall resume the status of undesignated shares of preferred stock. All shares of any one series of preferred stock will
be identical.
Our Board of Directors has authorized
the issuance of 50,000 shares of Series B Convertible Preferred Stock, par value $0.01 per share (the “
Preferred Stock
”),
all of which are currently issued and outstanding. Upon the completion of this offering, the Preferred Stock will automatically
convert into shares of common stock. The conversion ratio at which the Preferred Stock will convert into common stock is equal
to an amount per share of $100 plus all accrued but unpaid dividends payable in respect thereof (together, the “
Liquidation
Preference
”) divided by the greater of (i) $8.00 per share or (ii) the price that is 15% less than the price per
share of shares sold to the public in this offering.
Voting Rights.
Holders of
Preferred Stock are entitled to the number of votes equal to the number of shares of our common stock into which their shares
of Preferred Stock are to be converted at the record date for the determination of the stockholders entitled to vote on the matter
in question, or, if no such record date is established, at the record date provided by the Delaware General Corporation Law (the
“
DGCL
”) for any vote or action by written consent. Except as provided by the DGCL or our amended and
restated certificate of incorporation, the Preferred Stock shall be entitled to vote on all matters submitted to a vote of stockholders,
voting together with our common stock as a single class.
Dividend Rights.
Holders
of Preferred Stock are entitled to receive, when and as declared by the Board of Directors and declared by us, out of funds that
are legally available therefor, cash dividends of six percent (6%) of the Preferred Stock issue price of $100.00 per share per
annum on each outstanding share of Preferred Stock. Such dividends shall be fully cumulative and accumulate daily, whether or
not we have profits, surplus or other funds legally available for the payment of dividends thereon by the Board of Directors.
Such dividends shall accrue from the date of issuance of the relevant shares of Preferred Stock and shall cease to accrue on the
date immediately preceding a date of redemption or conversion. After payment of all accrued dividends on shares of Preferred Stock,
shares of Preferred Stock will not participate in dividends payable in respect of our common stock or redemptions of shares of
our common stock.
Under Delaware law, we can only pay dividends
either out of “surplus” or out of the current or the immediately preceding year’s net profits. Surplus is defined
as the excess, if any, at any given time, of the total assets of a corporation over its total liabilities and statutory capital.
The value of a corporation’s assets can be measured in a number of ways and may not necessarily equal their book value.
Liquidation Rights.
Upon
liquidation, prior to any payment to the holders of our common stock or any other class or series of stock ranking junior to the
Preferred Stock on liquidation, the holders of shares of the Preferred Stock then outstanding shall be entitled to be paid out
of our assets legally available for distribution to our stockholders, an amount per share equal to the sum of (i) the Preferred
Stock issue price of $100.00 per share, plus (ii) all accrued but unpaid dividends payable in respect of such share of Preferred
Stock (such sum, the “
Liquidation Preference
”). If our assets available for distribution to the holders
of shares of Preferred Stock shall be insufficient to permit payment in full to such holders of the sums which such holders are
entitled to receive in such case, then all of the assets available for distribution to holders of shares of Preferred Stock shall
be distributed among and paid to such holders ratably in proportion to the amounts that would be payable to such holders if such
assets were sufficient to permit payment in full. Following payment of the Liquidation Preference, our entire remaining assets
and surplus funds legally available for distribution upon liquidation will be distributed ratably among the holders of our common
stock in proportion to the shares of common stock then held by them.
Conversion Rights
. Each
share of Preferred Stock is convertible by the holder of such share at any time at the option of the holder into a number of shares
of our common stock determined by dividing the Liquidation Preference by the conversion price, determined as provided below, in
effect at the time of the conversion (the “
Conversion Price
”). The Conversion Price of the Preferred
Stock is equal to the greater of (i) $8.00 per share or (ii) the price that is fifteen percent (15%) less than the lowest
price per share of shares sold in a single transaction, or series of related transactions, with aggregate gross proceeds to us
of at least $50,000,000.00 (a “
Next Equity Financing
”). Additionally, each share of Preferred Stock
will be automatically converted into common stock upon and in connection with the closing of the Next Equity Financing. The number
of shares of common stock into which each share of Preferred Stock shall be automatically converted will be determined by dividing
the Liquidation Preference by the Conversion Price.
Redemption Rights
. Subject
to the holders’ right of voluntary conversion, we shall, following April 5, 2021 and upon providing each holder of Preferred
Stock no less than 30 days’ notice thereof, at any time thereafter (and from time to time), be entitled at our option to
redeem, out of funds legally available therefor, all or any portion of the Preferred Stock. Each share of Preferred Stock shall
be redeemed for an amount in cash or property equal to either (i) its applicable Liquidation Preference (the “
Complete
Redemption Price
”) or (ii) its issue price of $100.00 per share (the “
Partial Redemption Price
”).
If we choose to redeem shares of the Preferred Stock by paying the Partial Redemption Price, the accrued but unpaid dividends
as of the date of redemption of such shares shall remain outstanding in the amount thereof as of the date of redemption of such
shares and shall accrue interest at the rate of 6% per annum, and the payment thereof shall continue to have priority over any
dividend to the holders of our common stock.
Other Matters.
The
Preferred Stock has no preemptive or subscription rights. There are no sinking fund provisions applicable to the Preferred Stock.
All outstanding shares of the Preferred Stock are fully paid and non-assessable.
Composition of Board of Directors; Election and Removal
of Directors; Number of Directors
In accordance with our amended and restated
certificate of incorporation and our amended and restated bylaws, the number of directors comprising our Board of Directors is
determined from time to time by resolution of our Board of Directors, provided that in no event shall the total number of directors
be less than three nor more than eleven.
Upon the closing of this offering, our
Board of Directors will consist of seven members. Each director is to hold office until his successor is duly elected and qualified
or until his earlier death, resignation or removal. Any vacancies on our Board of Directors may be filled only by the affirmative
vote of a majority of the remaining directors, although less than a quorum, or by a sole remaining director. Our amended and restated
certificate of incorporation provides that stockholders do not have the right to cumulative votes in the election of directors.
At any meeting of our Board of Directors, except as otherwise required by law, a majority of the total number of directors then
in office will constitute a quorum for all purposes. Please read “
Management—Committees of the Board.
”
Special Meetings of Stockholders
Our amended and restated bylaws provide
that special meetings of the stockholders may be called only by the majority of our Board of Directors, the chairman of our Board
of Directors, or the President of the Company, for such purposes as shall be designated in the notice or waiver of notice thereof.
Certain Corporate Anti-Takeover Provisions
Certain provisions in our amended and
restated certificate of incorporation and amended and restated bylaws may be deemed to have an anti-takeover effect and may delay,
deter or prevent a tender offer or takeover attempt that a stockholder might consider to be in its best interests, including attempts
that might result in a premium being paid over the market price for the shares held by stockholders.
Preferred Stock
Our amended and restated certificate of
incorporation contains provisions that permit our Board of Directors to issue, without any further vote or action by the stockholders,
shares of preferred stock in one or more series and, with respect to each such series, to fix the number of shares constituting
the series and the designations and the powers, preferences and relative, participating, optional or other special rights, and
qualifications, limitations, or restrictions thereof, including without limitation, the dividend rate, conversion rights, redemption
price and liquidation preference, of such preferred stock, and to fix the number of shares constituting any such series. Please
read “—
Preferred Stock
.”
Removal of Directors; Vacancies
Our stockholders will be able to remove
any director or the entire Board of Directors with or without cause by the vote of the holders of a majority of the shares entitled
to vote for the election of directors. Vacancies on our Board of Directors may be filled only by the affirmative vote of a majority
of the remaining directors, although less than a quorum, or by a sole remaining director.
No Cumulative Voting
Our amended and restated certificate of
incorporation provides that stockholders do not have the right to cumulate votes on behalf of any candidate in the election of
directors. Cumulative voting rights would have been available to the holders of our common stock if our amended and restated certificate
of incorporation had not specifically provided that cumulative voting was not available.
Forum Selection
Our amended and restated bylaws provide
that unless we consent in writing to the selection of an alternative forum, a state or federal court located within the State
of Delaware will be the sole and exclusive forum for:
|
●
|
any derivative action or proceeding brought
on our behalf;
|
|
●
|
any action asserting
a claim of breach of a fiduciary duty owed by any of our or our subsidiaries’ directors, officers or employees to us
or our stockholders;
|
|
●
|
any action asserting a claim arising pursuant
to any provision of the DGCL; or
|
|
●
|
any action asserting
a claim governed by the internal affairs doctrine, in each such case subject to such court’s having personal jurisdiction
over the indispensable parties named as defendants therein.
|
Our amended and restated bylaws also provide
that any person or entity purchasing or otherwise acquiring any interest in shares of our capital stock will be deemed to have
notice of this forum selection provision contained therein. However, it is possible that a court could find our forum selection
provision to be inapplicable or unenforceable.
Delaware Anti-Takeover Law
From the time that our common stock is
listed on the NASDAQ Capital Market, we will be subject to the restrictions imposed under Section 203 of the DGCL. Section 203
of the DGCL provides that, subject to exceptions specified therein, an “interested stockholder” of a Delaware corporation
shall not engage in any “business combination,” including general mergers or consolidations or acquisitions of additional
shares of the corporation, with the corporation for a three-year period following the time that such stockholder becomes an interested
stockholder unless:
|
●
|
prior to such time,
the board of directors of the corporation approved either the business combination or the transaction which resulted in the
stockholder becoming an interested stockholder;
|
|
●
|
upon consummation
of the transaction which resulted in the stockholder becoming an “interested stockholder,” the interested stockholder
owned at least 85% of the voting stock of the corporation outstanding at the time the transaction commenced (excluding specified
shares); or
|
|
●
|
on or subsequent
to such time, the business combination is approved by the board of directors of the corporation and authorized at an annual
or special meeting of stockholders, and not by written consent, by the affirmative vote of at least 66
2
/3% of the
outstanding voting stock not owned by the interested stockholder.
|
Under Section 203, the restrictions
described above also do not apply to specified business combinations proposed by an interested stockholder following the announcement
or notification of one of specified transactions involving the corporation and a person who had not been an interested stockholder
during the previous three years or who became an interested stockholder with the approval of a majority of the corporation’s
directors, if such transaction is approved or not opposed by a majority of the directors who were directors prior to any person
becoming an interested stockholder during the previous three years or were recommended for election or elected to succeed such
directors by a majority of such directors.
Except as otherwise specified in Section 203, an “interested
stockholder” is defined to include:
|
●
|
any person that
is the owner of 15% or more of the outstanding voting stock of the corporation, or is an affiliate or associate of the corporation
and was the owner of 15% or more of the outstanding voting stock of the corporation at any time within three years immediately
prior to the date of determination; and
|
|
●
|
the affiliates and associates of any such person.
|
Under some circumstances, Section 203
makes it more difficult for a person who is an interested stockholder to effect various business combinations with us for a three-year
period.
A Delaware corporation may “opt
out” of Section 203 with an express provision in its original certificate of incorporation or an express provision in its
certificate of incorporation or bylaws resulting from amendments approved by the holders of at least a majority of the corporation’s
outstanding voting shares. We do not intend to “opt out” of the provisions of Section 203. The statute could prohibit
or delay mergers or other takeover or change in control attempts and, accordingly, may discourage attempts to acquire us.
Amendment of Our Certificate of Incorporation
Our amended and restated certificate of
incorporation provides that the amended and restated certificate of incorporation can be amended with the affirmative vote of
a majority of the outstanding common stock entitled to vote thereon, provided that with respect to any proposed amendment of the
certificate of incorporation (including any certificate of designation relating to any series or class of preferred stock) which
would alter or change the powers, preferences or special rights of any class or series of preferred stock so as to adversely affect
them, the approval of a majority of the votes entitled to be cast by the holders of the shares of such class or series of preferred
stock affected by the proposed amendment, voting separately as a class, shall be obtained in addition to the approval of a majority
of the votes entitled to be cast by the holders of our common stock.
Amendment of Our Bylaws
Our amended and restated bylaws provide
that the amended and restated bylaws can be amended by the affirmative vote of a majority of the outstanding stock entitled to
vote thereon or by the affirmative vote of a majority of our Board of Directors or by unanimous written consent of our Board of
Directors.
Limitation of Liability and Indemnification
Our amended and restated bylaws limit
the liability of our directors to the maximum extent permitted by Delaware law. Delaware law provides that directors will not
be personally liable for monetary damages for breach of their fiduciary duties as directors, except with respect to liability:
|
●
|
for any breach of
the director’s duty of loyalty to us or our stockholders;
|
|
●
|
for acts or omissions
not in good faith or that involve intentional misconduct or a knowing violation of law;
|
|
●
|
for any unlawful
payments of dividends or unlawful stock repurchases or redemption as provided in Section 174 of the DGCL; or
|
|
●
|
for any transaction from which the director
derived any improper personal benefit.
|
However, if the DGCL is amended to authorize
corporate action further eliminating or limiting the personal liability of directors, then the liability of our directors will
be eliminated or limited to the fullest extent permitted by the DGCL, as so amended. The modification or repeal of this provision
of our amended and restated certificate of incorporation will not adversely affect any right or protection of a director existing
at the time of such modification or repeal.
Our amended and restated certificate of
incorporation and amended and restated bylaws provide that we will, to the fullest extent from time to time permitted by law,
indemnify our directors and officers against all liabilities and expenses in any suit or proceeding, arising out of their status
as an officer or director or their activities in these capacities. We will also indemnify any person who, at our request, is or
was serving as a director, officer, trustee, employee or agent of another corporation, partnership, joint venture, trust or other
enterprise. We may, by action of our Board of Directors, provide indemnification to our employees and agents within the same scope
and effect as the foregoing indemnification of directors and officers. In addition, we have entered into separate indemnification
agreements with each of our directors and executive officers, which are broader than the specific indemnification provisions contained
in the DGCL. These indemnification agreements require us, among other things, to indemnify our directors and officers against
liabilities that may arise by reason of their status or service as directors or officers, other than liabilities arising from
willful misconduct.
The right to be indemnified includes the
right of an officer or a director to be paid expenses, including attorneys’ fees, in advance of the final disposition of
any proceeding, provided that, if required by law, we receive an undertaking to repay such amount if it will be determined that
he or she is not entitled to be indemnified.
Our Board of Directors may take such action
as it deems necessary to carry out these indemnification provisions, including adopting procedures for determining and enforcing
indemnification rights and purchasing insurance policies. Our Board of Directors may also adopt bylaws, resolutions or contracts
implementing indemnification arrangements as may be permitted by law. Neither the amendment nor the repeal of these indemnification
provisions, nor the adoption of any provision of our amended and restated certificate of incorporation inconsistent with these
indemnification provisions, will eliminate or reduce any rights to indemnification relating to such person’s status or any
activities prior to such amendment, repeal or adoption.
We believe these provisions will assist
in attracting and retaining qualified individuals to serve as directors and officers.
Transfer Agent and Registrar
The transfer agent and registrar for our common stock is Continental
Stock Transfer & Trust Company.
Listing
We have applied to list our common stock on the NASDAQ Capital
Market under the symbol “CRBO.”
SHARES
ELIGIBLE FOR FUTURE SALE
Future sales of, or the perceived potential
for the sale of, our common stock in the public market may have an adverse effect on the market price for our common stock and
could impair our ability to raise capital through future sales of our securities.
Sales of Restricted Shares
Upon the closing of this offering, we
will have outstanding shares of common stock (or shares
of common stock if the underwriters’ option to purchase additional shares is exercised). Of these shares, shares
of common stock (or shares of common stock if the underwriters’
option to purchase additional shares is exercised) will be freely tradable without restriction or further registration under the
Securities Act, unless the shares are held by any of our “affiliates” as such term is defined in Rule 144 of
the Securities Act. All remaining shares of common stock held by existing stockholders will be deemed “restricted securities”
as such term is defined under Rule 144. The restricted securities were issued and sold by us in private transactions and
are eligible for public sale only if registered under the Securities Act or if they qualify for an exemption from registration
under Rule 144 or Rule 701 under the Securities Act, which rules are summarized below.
As a result of the lock-up agreements
described below and the provisions of Rule 144 and Rule 701 under the Securities Act, shares
of our common stock held by Yorktown and our directors and executive officers will be available for sale in the public market
upon the expiration of the lock-up agreements, beginning 180 days after the date of this prospectus and when permitted under Rule 144
or Rule 701.
Rule 144
In general, under Rule 144, a person
(or persons whose shares are aggregated) who is not deemed to have been an affiliate of ours at any time during the three months
preceding a sale, and who has beneficially owned restricted securities within the meaning of Rule 144 for a least six months
(including any period of consecutive ownership of preceding non-affiliated holders) would be entitled to sell those shares, subject
only to the availability of current public information about us. A non-affiliated person who has beneficially owned restricted
securities within the meaning of Rule 144 for at least one year would be entitled to sell those shares without regard to
the provisions of Rule 144.
A person (or persons whose shares are
aggregated) who is deemed to be an affiliate of ours and who has beneficially owned restricted securities within the meaning of
Rule 144 for at least six months would be entitled to sell within any three-month period a number of shares that does not
exceed the greater of 1% of the then outstanding shares of our common stock or the average weekly trading volume of our common
stock reported through the NASDAQ during the four calendar weeks preceding the filing of notice of the sale. Such sales are also
subject to certain manner of sale provisions, notice requirements and the availability of current public information about us.
Rule 701
In general, under Rule 701, any of
our employees, directors, officers, consultants or advisors who purchases shares from us in connection with a compensatory stock
or option plan or other written agreement before the effective date of this offering is entitled to sell such shares 180 days
after the effective date of this offering in reliance on Rule 144, without having to comply with the holding period requirement
of Rule 144 and, in the case of non-affiliates, without having to comply with the public information, volume limitation or
notice filing provisions of Rule 144. The SEC has indicated that Rule 701 will apply to typical stock options granted
by an issuer before it becomes subject to the reporting requirements of the Exchange Act, along with the shares acquired upon
exercise of such options, including exercises after the date of this prospectus.
Stock Issued Under Employee Plans
On January 26, 2012, we filed a registration
statement on Form S-8 under the Securities Act to register 12,600,000 shares of common stock, which amount was later reduced
due to the reverse stock split, initially reserved for issuance under the Carbon Natural Gas Company 2011 Stock Incentive Plan
(which amount may be increased in accordance with the terms of the plan). Shares registered under that registration statement
are available for sale in the open market following the effective date, unless such shares are subject to vesting restrictions
with us, Rule 144 restrictions applicable to our affiliates or the lock-up restrictions described below.
Registration Rights
We previously granted piggyback registration
rights to a fund associated with Yorktown and certain other stockholders, including Edwin Morgens, in connection with a private
placement completed in 2011. Please read “
Certain Relationships and Related Party Transactions—Yorktown Registration
Rights
” for more detail regarding these registration rights. All such registration rights have expired or have been
waived in connection with this offering.
Lock-Ups
We and our officers and directors have
agreed that, for a period of 180 days from the date of this prospectus, we and they will not, without the prior written consent
of RBC Capital Markets, LLC, dispose of or hedge any shares or any securities convertible into or exchangeable for our common
stock. For additional information, please read “
Underwriting
.”
MATERIAL
U.S. FEDERAL INCOME TAX CONSIDERATIONS FOR NON-U.S. HOLDERS
The following discussion summarizes the
material U.S. federal income tax considerations applicable to Non-U.S. Holders (as defined below) with respect to the purchase,
ownership and disposition of our common stock issued pursuant to this offering. This discussion is based upon the provisions of
the Internal Revenue Code of 1986, as amended (the “
Code
”), its legislative history, U.S. Treasury regulations
promulgated thereunder (“
Treasury Regulations
”), published rulings and judicial decisions, all as in
effect as of the date hereof. Those authorities are subject to change or differing interpretations, possibly with retroactive
effect, so as to result in U.S. federal income tax consequences different from those set forth below. No ruling has been, or will
be, sought from the U.S. Internal Revenue Service (the “
IRS
”) with respect to any of the U.S. federal
income tax consequences discussed below, and there can be no assurance that the IRS will not take a position contrary to the tax
consequences discussed below or that any position taken by the IRS would not be sustained.
This discussion only addresses Non-U.S.
Holders of our common stock that hold such common stock as a capital asset within the meaning of Section 1221 of the Code (generally,
property held for investment) and does not address the Medicare tax on certain investment income, tax consequences arising under
the laws of any foreign, state or local jurisdiction or any applicable tax treaty or any U.S. federal taxes (such as the federal
estate tax, alternative minimum tax or the federal gift tax) other than U.S. federal income taxes. In addition, this discussion
does not describe all aspects of U.S. federal income taxation that may be relevant to Non-U.S. Holders in light of their personal
circumstances and does not address the U.S. federal income tax consequences to Non-U.S. Holders that may be subject to special
treatment under U.S. federal income tax laws, including, without limitation:
|
●
|
brokers or dealers in securities or currency;
|
|
●
|
traders in securities that elect to use a mark-to-market
method of accounting for their securities;
|
|
●
|
banks, thrifts, insurance companies or other
financial institutions;
|
|
●
|
tax-exempt or governmental organizations;
|
|
●
|
qualified foreign
pension funds (or any entities all of the interests of which are held by a qualified foreign pension fund);
|
|
●
|
certain former citizens or long-term residents
of the United States;
|
|
●
|
persons subject to the alternative minimum tax;
|
|
●
|
passive foreign investment companies or controlled
foreign corporations;
|
|
●
|
persons that hold
our common stock as part of a hedging, constructive sale or conversion, synthetic security, wash sale, straddle or other integrated
investment or risk reduction transaction;
|
|
●
|
persons deemed to sell our common stock under
the constructive sale provisions of the Code; and
|
|
●
|
persons that acquired
our common stock through the exercise of employee stock options or otherwise as compensation or through a tax-qualified retirement
plan.
|
If an entity or arrangement classified
as a partnership for U.S. federal income tax purposes holds our common stock, the tax treatment of a partner of such partnership
will generally depend upon the status of the partner, certain determinations made at the partner level and the activities of the
partnership. If you are a partner of an entity or arrangement that is classified as a partnership for U.S. federal income tax
purposes holding our common stock, you should consult your own tax advisor.
This discussion is provided for general
information only and does not constitute legal advice to any potential purchaser of our common stock. Prospective purchasers of
our common stock are urged to consult their own tax advisors with respect to the U.S. federal income tax consequences of purchasing,
owning, and disposing of our common stock in light of their particular circumstances, any other U.S. federal tax consequences
(including any gift or estate tax consequences), and any consequences arising under any tax treaty or the laws of any state, local
or foreign taxing jurisdiction.
Non-U.S. Holder Defined
For purposes of this discussion, the term
“Non-U.S. Holder” means a beneficial owner of our common stock that is an individual, corporation, estate or trust,
other than:
|
●
|
an individual who is a citizen or resident of
the United States (for U.S. federal income tax purposes);
|
|
●
|
a corporation, or
other entity treated as a corporation for U.S. federal income tax purposes, created or organized in or under the laws of the
United States or any state thereof or the District of Columbia;
|
|
●
|
an estate the income of which is subject to
U.S. federal income taxation regardless of its source; or
|
|
●
|
a trust if (1) a
court within the United States is able to exercise primary supervision over the administration of the trust and one or more
U.S. persons have the authority to control all substantial decisions of the trust, or (2) the trust has a valid election in
effect under applicable Treasury Regulations to be treated as a U.S. person.
|
Distributions
Distributions of cash or property, if
any, made to a Non-U.S. Holder on our common stock will constitute dividends for U.S. federal income tax purposes to the extent
of our current or accumulated earnings and profits as determined under U.S. federal income tax principles. The amount of any such
distribution in excess of our current and accumulated earnings and profits will first be applied to reduce a Non-U.S. Holder’s
tax basis in such common stock, and any amount in excess of the Non-U.S. Holder’s tax basis will be treated as gain from
the sale or exchange of such common stock, the tax treatment of which is discussed under “
—Sale, Exchange or
Other Taxable Disposition of Common Stock
” below. Subject to the discussions under “
—Backup Withholding
and Information Reporting
” and “
—Foreign Account Tax Compliance Act
” below, we intend
to treat the entire amount of any distribution made to a Non-U.S. Holder on our common stock as subject to U.S. federal withholding
tax at a rate of 30% or such lower rate as may be specified by an applicable income tax treaty as to which the Non-U.S. Holder
appropriately claims the benefit. Dividends paid to a Non-U.S. Holder that are effectively connected with a trade or business
conducted by the Non-U.S. Holder within the United States (and, if required by an applicable income tax treaty, are attributable
to a permanent establishment or fixed base within the United States) are not subject to the U.S. federal withholding tax described
above if the Non-U.S. Holder meets the certification requirements described, and such dividends would be taxable as discussed,
under “
—Income or Gain Effectively Connected with a U.S. Trade or Business
” below.
A Non-U.S. Holder that wishes to claim
the benefit of an applicable treaty rate is required to satisfy applicable certification requirements (generally by providing
a properly completed and executed IRS Form W-8BEN or W-8BEN-E (or other applicable form) claiming such benefit). If a Non-U.S.
Holder is eligible for an exemption or a reduced rate of U.S. federal withholding tax pursuant to an income tax treaty, such Non-U.S.
Holder may generally obtain a refund of any excess amounts withheld by timely filing an appropriate claim for refund with the
IRS.
Sale, Exchange or Other Taxable Disposition of Common Stock
Subject to the discussions under “
—Backup
Withholding and Information Reporting
” and “
—Foreign Account Tax Compliance Act
”
below, any gain realized by a Non-U.S. Holder upon the sale, exchange, or other taxable disposition of our common stock generally
will not be subject to U.S. federal income tax or withholding tax unless:
|
●
|
such gain is effectively
connected with the Non-U.S. Holder’s conduct of a U.S. trade or business (and, if required by an applicable income tax
treaty, is attributable to a permanent establishment or a fixed base within the United States);
|
|
●
|
such Non-U.S. Holder
is an individual who was present in the United States for 183 days or more in the taxable year of the disposition, and certain
other conditions are met; or
|
|
●
|
we are or have been
a “United States real property holding corporation” for U.S. federal income tax purposes (a “
USRPHC
”)
during the shorter of the Non-U.S. Holder’s holding period or the five-year period ending on the date of disposition
of our common stock.
|
A Non-U.S. Holder described in the first
bullet point above will be subject to tax as described under “
—Income or Gain Effectively Connected with a U.S.
Trade or Business
” below.
A Non-U.S. Holder described in the second
bullet point above will be subject to a flat tax at a rate of 30% (or a lower applicable treaty rate) on the gain recognized from
the sale, exchange or other taxable disposition of our common stock, which generally may be offset by U.S. source capital losses.
Generally, a corporation is a USRPHC if
the fair market value of its United States real property interests equals or exceeds 50% of the sum of the fair market value of
its worldwide real property interests plus certain other assets used or held for use in a trade or business. We believe that we
currently are, and expect to remain for the foreseeable future, a USRPHC. However, provided that our common stock is and continues
to be regularly traded on an established securities market, only a Non-U.S. Holder that actually or constructively owns or owned,
at any time during the shorter of the five-year period ending on the date of the disposition or the Non-U.S. Holder’s holding
period for the common stock, more than 5% of our common stock will be subject to U.S. federal income tax and withholding tax on
gain realized on the disposition of our common stock as a result of our status as a USRPHC. If our common stock were not considered
to be regularly traded on an established securities market during the calendar year in which the relevant disposition occurs,
any Non-U.S. Holder (regardless of the percentage of stock owned) (or, if a Non-U.S. Holder’s stock ownership has exceeded
the 5% threshold specified above, such Non-U.S. Holder) would be subject to U.S. federal income tax on a taxable disposition of
our common stock (as described under “
—Income or Gain Effectively Connected with a U.S. Trade or Business
”
below), and a U.S. federal withholding tax at a rate of 15% would apply to the gross proceeds from such disposition.
Non-U.S. Holders should consult their
tax advisors regarding the application of the foregoing rules to the ownership and disposition of our common stock.
Income or Gain Effectively Connected with a U.S. Trade or
Business
If any dividend on our common stock or
gain from the sale, exchange or other taxable disposition of our common stock is effectively connected with a trade or business
conducted by a Non-U.S. Holder within the United States (and, if required by an applicable income tax treaty, is attributable
to a permanent establishment or fixed base within the United States), then the dividends or gain generally will be subject to
U.S. federal income tax at regular graduated income tax rates in generally the same manner as if the Non-U.S. Holder were a United
States person (as defined in the Code). If a Non-U.S. Holder is a corporation, that portion of its earnings and profits that is
effectively connected with its trade or business within the United States (and, if required by an applicable income tax treaty,
is attributable to a permanent establishment or fixed base within the United States) also may be subject to a “branch profits
tax” (at a rate of 30% or such lower rate as may be specified by an applicable income tax treaty). Effectively connected
dividends are generally not subject to withholding tax if the Non-U.S. Holder provides to the applicable withholding agent a properly
completed and executed IRS Form W-8ECI (or appropriate substitute or successor form) or IRS Form W-8BEN or W-8BEN-E (or appropriate
successor form) claiming exemption under an applicable income tax treaty, as applicable, subject to the discussion under “
—Foreign
Account Tax Compliance Act
” below.
Backup Withholding and Information Reporting
Any dividends paid to a Non-U.S. Holder
and the amount of tax, if any, withheld with respect to those payments must be reported annually to the IRS and to the Non-U.S.
Holder. Copies of these information returns may be made available under the provisions of an applicable income tax treaty to the
tax authorities in the country in which the Non-U.S. Holder resides or is established. Payments of dividends to a Non-U.S. Holder
generally will not be subject to backup withholding if the Non-U.S. Holder certifies to its foreign status on a properly completed
and executed IRS Form W-8BEN or W-8BEN-E (or other applicable or successor form) or otherwise establishes an exemption (and the
applicable withholding agent does not have actual knowledge or reason to know that the Non-U.S. Holder is a United States person).
Payments of the proceeds from a sale or
other disposition by a Non-U.S. Holder of our common stock effected by or through a U.S. office of a broker generally will be
subject to information reporting and backup withholding (at the applicable rate, which is currently 24%) unless the Non-U.S. Holder
establishes an exemption by certifying to its foreign status on a properly completed and executed IRS Form W-8BEN or W-8BEN-E
(or other applicable or successor form) and certain other conditions are met. Information reporting and backup withholding generally
will not apply to any payment of the proceeds from a sale or other disposition of our common stock effected outside the United
States by a non-U.S. office of a broker. However, unless such broker has documentary evidence in its records that the Non-U.S.
Holder is not a United States person and certain other conditions are met, or the Non-U.S. Holder otherwise establishes an exemption,
information reporting will apply to a payment of the proceeds of the disposition of our common stock effected outside the United
States by such a broker if it has certain relationships within the United States.
Backup withholding is not an additional
tax. The amount of any backup withholding will generally be allowed as a credit against the Non-U.S. Holder’s U.S. federal
income tax liability and may entitle the Non-U.S. Holder to a refund, provided that the Non-U.S. Holder timely files an appropriate
claim for refund with the IRS.
Foreign Account Tax Compliance Act
Sections 1471 through 1474 of the Code
and the Treasury Regulations and administrative guidance issued thereunder (referred to as “
FATCA
”)
generally impose withholding at a rate of 30% on dividends on, and the gross proceeds of a sale or taxable disposition (if such
sale or taxable disposition occurs after December 31, 2018) of, our common stock paid (or deemed paid) to a “foreign financial
institution” or a “non-financial foreign entity” (each as defined in the Code) (including, in some cases, when
such foreign financial institution or non-financial foreign entity is acting as an intermediary), unless: (1) in the case of a
foreign financial institution, such institution enters into an agreement with the U.S. government to withhold on certain payments,
and to collect and provide to the U.S. tax authorities substantial information regarding U.S. account holders of such institution
(which includes certain equity and debt holders of such institution, as well as certain account holders that are foreign entities
with U.S. owners); (2) in the case of a non-financial foreign entity, such entity certifies that it does not have any “substantial
United States owners” (as defined in the Code) or provides the withholding agent with a certification identifying its direct
and indirect substantial United States owners; or (3) the foreign financial institution or non-financial foreign entity otherwise
qualifies for an exemption from these rules. Intergovernmental agreements regarding FATCA between the United States and certain
other countries may modify the foregoing requirements. Under certain circumstances, a beneficial owner of our common stock might
be eligible for refunds or credits of such taxes.
Non-U.S. Holders are urged to consult
their own tax advisors regarding the possible implications of FATCA on their investment in our common stock.
THE PRECEDING DISCUSSION OF MATERIAL
U.S. FEDERAL INCOME TAX CONSIDERATIONS FOR NON-U.S. HOLDERS IS FOR GENERAL INFORMATION ONLY AND IS NOT TAX ADVICE. ANY POTENTIAL
PURCHASER OF OUR COMMON STOCK IS URGED TO CONSULT ITS OWN TAX ADVISOR REGARDING THE PARTICULAR U.S. FEDERAL (INCLUDING FEDERAL
ESTATE TAX AND FEDERAL GIFT TAX), STATE, LOCAL AND FOREIGN TAX CONSEQUENCES OF PURCHASING, OWNING AND DISPOSING OF OUR COMMON
STOCK, INCLUDING THE CONSEQUENCES OF ANY PROPOSED CHANGES IN APPLICABLE LAWS.
UNDERWRITING
Underwriting
RBC Capital Markets, LLC is acting as
sole book-running manager of the offering and as representative of the underwriters named below. Subject to the terms and conditions
stated in the underwriting agreement dated the date of this prospectus, each underwriter named below has severally and not jointly
agreed to purchase, and we have agreed to sell to that underwriter, the number of shares set forth opposite the underwriter’s
name.
Underwriter
|
|
Number of
Shares
|
|
RBC Capital Markets, LLC
|
|
|
|
|
Total
|
|
|
|
|
The underwriting agreement provides
that the obligations of the underwriters to purchase the shares included in this offering are subject to approval of legal matters
by counsel and to other conditions. The underwriters are obligated to purchase all the shares (other than those covered by the
option described below) if they purchase any of the shares.
Shares sold by the underwriters to the
public will initially be offered at the public offering price set forth on the cover of this prospectus. Any shares sold by the
underwriters to securities dealers may be sold at a discount from the public offering price not to exceed $ per
share. If all the shares are not sold at the offering price, the underwriters may change the offering price and the other selling
terms.
Underwriting discount
The following table shows the underwriting
discount that we are to pay to the underwriters in connection with this offering. These amounts are shown assuming both no exercise
and full exercise of the underwriters’ option to purchase additional shares of common stock.
|
|
Paid
by the Company
|
|
|
|
No
Exercise
|
|
|
Full
Exercise
|
|
Per share
|
|
$
|
|
|
|
$
|
|
|
Total
|
|
$
|
|
|
|
$
|
|
|
Indemnification
We have agreed to indemnify the underwriters
against certain liabilities, including liabilities under the Securities Act, or to contribute to payments the underwriters may
be required to make because of any of those liabilities.
Option to Purchase Additional Shares
If the underwriters sell more shares
than the total number set forth in the table above, we have granted to the underwriters an option, exercisable for 30 days from
the date of this prospectus, to purchase up to
additional shares at the public offering price less the underwriting discount. To the extent the option is exercised, each underwriter
must purchase a number of additional shares approximately proportionate to that underwriter’s initial purchase commitment.
Any shares issued or sold under the option will be issued and sold on the same terms and conditions as the other shares that are
the subject of this offering.
Lock-Ups
We and our officers and directors have
agreed that, for a period of 180 days from the date of this prospectus, we and they will not, without the prior written consent
of RBC Capital Markets, LLC, dispose of or hedge any shares or any securities convertible into or exchangeable for our common
stock, subject to certain exceptions. RBC Capital Markets, LLC in its sole discretion may release any of the securities subject
to these lock-up agreements at any time, which, in the case of officers and directors, shall be with notice.
Determination of Offering Price
Prior to this offering, there has been
a limited public market for our shares. Consequently, the public offering price for the shares was determined by negotiations
among us and the representatives. Among the factors considered in determining the public offering price were our results of operations,
our current financial condition, our future prospects, our markets, the economic conditions in and future prospects for the industry
in which we compete, our management, and currently prevailing general conditions in the equity securities markets, including current
market valuations of publicly traded companies considered comparable to our company. We cannot assure you, however, that the price
at which the shares will sell in the public market after this offering will not be lower than the public offering price or that
an active trading market in our shares will develop and continue after this offering.
Listing
We have applied to list our common stock on the Nasdaq
Capital Market under the symbol “CRBO.”
Expenses and Reimbursements
We estimate that our total expenses
of this offering will be $ . We have agreed to reimburse the underwriters
up to $15,000 for expenses related to any filing with, and any clearance of this offering by, the Financial Industry Regulatory
Authority (FINRA).
Price Stabilization, Short Positions and Penalty Bids
In connection with the offering, the underwriters
may purchase and sell shares in the open market. Purchases and sales in the open market may include short sales, purchases to
cover short positions, which may include purchases pursuant to the over-allotment option, and stabilizing purchases.
|
●
|
Short sales involve
secondary market sales by the underwriters of a greater number of shares than they are required to purchase in the offering.
|
|
○
|
“Covered”
short sales are sales of shares in an amount up to the number of shares represented by the underwriters’ over-allotment
option.
|
|
○
|
“Naked”
short sales are sales of shares in an amount in excess of the number of shares represented by the underwriters’ over-allotment
option.
|
|
●
|
Covering transactions
involve purchases of shares either pursuant to the underwriters’ over-allotment option or in the open market in order
to cover short positions.
|
|
○
|
To close a naked
short position, the underwriters must purchase shares in the open market. A naked short position is more likely to be created
if the underwriters are concerned that there may be downward pressure on the price of the shares in the open market after
pricing that could adversely affect investors who purchase in the offering.
|
|
○
|
To close a covered
short position, the underwriters must purchase shares in the open market or must exercise the over-allotment option. In determining
the source of shares to close the covered short position, the underwriters will consider, among other things, the price of
shares available for purchase in the open market as compared to the price at which they may purchase shares through the over-allotment
option.
|
|
●
|
Stabilizing transactions
involve bids to purchase shares so long as the stabilizing bids do not exceed a specified maximum.
|
Purchases to cover short positions
and stabilizing purchases, as well as other purchases by the underwriters for their own accounts, may have the effect of preventing
or retarding a decline in the market price of the shares. They may also cause the price of the shares to be higher than the price
that would otherwise exist in the open market in the absence of these transactions. The underwriters may conduct these transactions
on the Nasdaq Capital Market, in the over-the-counter market or otherwise. If the underwriters commence any of these transactions,
they may discontinue them at any time.
Electronic Distribution
In connection with the offering, certain
of the underwriters or securities dealers may distribute prospectuses by electronic means, such as e-mail.
LEGAL
MATTERS
The validity of our common stock offered
by this prospectus will be passed upon for us by Baker Botts L.L.P., Houston, Texas. Certain legal matters in connection
with this offering will be passed upon for the underwriters by Vinson & Elkins L.L.P., New York, New York.
EXPERTS
The consolidated financial statements
of Carbon Energy Corporation as of December 31, 2017 and 2016 and for each year in the two-year period then ended included in
this prospectus have been audited by EKS&H LLLP, an independent registered public accounting firm, as stated in their report
appearing herein. Such consolidated financial statements are included in reliance on the report of such independent registered
public accounting firm given on the authority of such firm as experts in accounting and auditing.
The consolidated financial statements
of Carbon Appalachian Company, LLC as of December 31, 2017 and for the period from April 3, 2017 through December 31, 2017 included
in this prospectus have been audited by EKS&H LLLP, an independent registered public accounting firm, as stated in their report
appearing herein. Such consolidated financial statements are included in reliance on the report of such independent registered
public accounting firm given on the authority of such firm as experts in accounting and auditing.
The financial statements of Carbon California
Company, LLC as of December 31, 2017 and for the period from February 15, 2017 through December 31, 2017 included in this prospectus
have been audited by EKS&H LLLP, an independent registered public accounting firm, as stated in their report appearing herein.
Such financial statements are included in reliance on the report of such independent registered public accounting firm given on
the authority of such firm as experts in accounting and auditing.
The statements of revenues and direct
operating expenses of certain properties that Carbon California Company, LLC had plans to purchase from Seneca Resources Corporation
for the years ended December 31, 2017 and 2016 included in this prospectus have been audited by EKS&H LLLP, an independent
auditor, as stated in their report appearing herein. Such statements of revenues and direct operating expenses are included in
reliance on the report of such independent auditor given on the authority of such firm as experts in accounting and auditing.
The statements of revenues and direct
operating expenses of certain properties that Carbon Appalachian Company, LLC acquired from Cabot Oil & Gas Corporation for
the period from January 1, 2017 through September 29, 2017 and for the year ended December 31, 2016 included in this prospectus
have been audited by EKS&H LLLP, an independent auditor, as stated in their report appearing herein. Such statements of revenues
and direct operating expenses are included in reliance on the report of such independent auditor given on the authority of such
firm as experts in accounting and auditing.
The information included in this prospectus
concerning estimates of the oil and gas reserves of Carbon Appalachian Company, LLC, Carbon California Company, LLC and Nytis
Exploration (USA) Inc. were prepared by Cawley, Gillespie & Associates, Inc., an independent engineering firm, and have been
included herein upon the authority of such firm as an expert.
WHERE
YOU CAN FIND MORE INFORMATION
We file annual, quarterly and other reports
with and furnish information to the SEC. You may read and copy any document we file with or furnish to the SEC at the SEC’s
Public Reference Room at 100 F Street, N.E., Washington, D.C. 20549. Please call the SEC at 1-800-732-0330 for further information
on the operation of the Public Reference Room. Our SEC filings are also available at the SEC’s website at
http://www.sec.gov
.
Upon a written or oral request, we will
provide to each person, including any beneficial owner, to whom a prospectus is delivered, a copy of any or all of the reports
or documents that have been incorporated by reference in the prospectus contained in the registration statement but not delivered
with the prospectus. These reports or documents will be provided at no cost to you by writing or calling us at the following address:
Carbon Energy Corporation, 1700 Broadway, Suite 1170, Denver, Colorado, 80290.
You also may request a copy of any
document incorporated by reference in this prospectus (including exhibits to those documents specifically incorporated by reference
in this document), at no cost, by visiting our internet website at
http://www.carbonenergycorp.com
. Information on our
website or any other website is not incorporated by reference into, and does not constitute a part of, this prospectus or the
registration statement of which this prospectus forms a part.
We have filed with the SEC a registration statement on Form S-1 (including
the exhibits, schedules and amendments thereto) under the Securities Act, with respect to the shares of our common stock offered
hereby. This prospectus does not contain all of the information set forth in the registration statement and the exhibits and schedules
thereto. For further information with respect to us and the common stock offered hereby, we refer you to the registration statement
and the exhibits and schedules filed therewith. Statements contained in this prospectus as to the contents of any contract, agreement
or any other document are summaries of the material terms of this contract, agreement or other document. With respect to each
of these contracts, agreements or other documents filed as an exhibit to the registration statement, reference is made to the
exhibits for a more complete description of the matter involved.
INDEX
TO FINANCIAL STATEMENTS
|
|
Page
|
UNAUDITED
PRO FORMA CONSOLIDATED FINANCIAL STATEMENTS
|
|
|
Carbon
Energy Corporation
|
|
|
Introduction
|
|
F-2
|
Unaudited
Pro Forma Consolidated Statement of Operations for the Six Months Ended June 30, 2018
|
|
F-3
|
Unaudited
Pro Forma Consolidated Statement of Operations for the Year Ended December 31, 2017
|
|
F-4
|
Unaudited
Pro Forma Consolidated Balance Sheet as of June 30, 2018
|
|
F-5
|
Notes
to Unaudited Pro Forma Consolidated Financial Information
|
|
F-6
|
|
|
|
HISTORICAL
FINANCIAL STATEMENTS
|
|
|
Carbon
Natural Gas Company
|
|
|
Interim
Period Financial Statements (Unaudited)
|
|
|
Consolidated
Balance Sheets as of June 30, 2018 and December 31, 2017
|
|
F-19
|
Consolidated
Statements of Operations for the Three and Six Months Ended June 30, 2018 and 2017
|
|
F-20
|
Consolidated
Statements of Stockholders’ Equity
|
|
F-21
|
Consolidated
Statements of Cash Flows for the Six Months Ended June 30, 2018 and 2017
|
|
F-22
|
Notes
to Consolidated Financial Statements
|
|
F-23
|
Annual
Financial Statements (Audited)
|
|
|
Report
of Independent Registered Public Accounting Firm
|
|
F-50
|
Consolidated
Balance Sheets as of December 31, 2017 and 2016
|
|
F-51
|
Consolidated
Statements of Operations for the Twelve Months Ended December 31, 2017 and 2016
|
|
F-52
|
Consolidated
Statements of Stockholders’ Equity
|
|
F-53
|
Consolidated
Statements of Cash Flows for the Twelve Months Ended December 31, 2017 and 2016
|
|
F-54
|
Notes
to Consolidated Financial Statements
|
|
F-55
|
|
|
|
Carbon
Appalachian Company, LLC
|
|
|
Interim
Period Financial Statements (Unaudited)
|
|
|
Consolidated
Balance Sheet as of June 30, 2018 and December 31, 2017
|
|
F-88
|
Consolidated
Statement of Operations for the three and six months ended June 30, 2018
|
|
F-89
|
Consolidated
Statement of Members’ Equity
|
|
F-90
|
Consolidated
Statement of Cash Flows for the six months ended June 30, 2018
|
|
F-91
|
Notes
to Consolidated Financial Statements
|
|
F-92
|
Annual
Financial Statements (Audited)
|
|
|
Report
of Independent Registered Public Accounting Firm
|
|
F-104
|
Consolidated
Balance Sheet as of December 31, 2017
|
|
F-105
|
Consolidated
Statement of Operations for the period April 3, 2017 (inception) through December 31, 2017
|
|
F-106
|
Consolidated
Statement of Members’ Equity
|
|
F-107
|
Consolidated
Statement of Cash Flows for the period April 3, 2017 (inception) through December 31, 2017
|
|
F-108
|
Notes
to Consolidated Financial Statements
|
|
F-109
|
|
|
|
Carbon
California Company, LLC
|
|
|
Annual
Financial Statements (Audited)
|
|
|
Report
of Independent Registered Public Accounting Firm
|
|
F-126
|
Balance
Sheet as of December 31, 2017
|
|
F-127
|
Statement
of Operations for the Period from February 15, 2017 (inception) through December 31, 2017
|
|
F-128
|
Statement
of Members’ Equity
|
|
F-129
|
Statement
of Cash Flows for the Period from February 15, 2017 (inception) through December 31, 2017
|
|
F-130
|
Notes
to Financial Statements
|
|
F-131
|
|
|
|
Cabot
Acquisition Properties
|
|
|
Independent
Auditors’ Report
|
|
F-147
|
Statements
of Revenues and Direct Operating Expenses for the Period From January 1, 2017 through September 29, 2017 and the Year Ended
December 31, 2016
|
|
F-148
|
Notes
to Statements of Revenues and Direct Operating Expenses
|
|
F-149
|
|
|
|
Seneca
Acquisition Properties
|
|
|
Independent
Auditors’ Report
|
|
F-153
|
Statements
of Revenues and Direct Operating Expenses for the Three and Six Months Ended June 30, 2018 and 2017 (
Unaudited
)
|
|
F-154
|
Notes
to Statements of Revenues and Direct Operating Expenses (
Unaudited
)
|
|
F-155
|
Statements
of Revenues and Direct Operating Expenses for the Years Ended December 31, 2017 and 2016
|
|
F-157
|
Notes
to Statements of Revenues and Direct Operating Expenses
|
|
F-158
|
UNAUDITED PRO FORMA
CONSOLIDATED FINANCIAL INFORMATION
The following unaudited pro forma consolidated
financial information and the related notes present our unaudited pro forma consolidated statements of operations for the six
months ended June 30, 2018 and for the year ended December 31, 2017, and the unaudited pro forma consolidated balance sheet as
of June 30, 2018. The unaudited pro forma consolidated financial information has been derived by aggregating our audited and unaudited
historical consolidated financial statements, the audited and unaudited historical financial statements of Carbon California Company
(“Carbon California”), the audited and unaudited historical financial statements of Carbon Appalachia Company (“Carbon
Appalachia”), the audited and unaudited historical statements of revenues and direct operating expenses for the properties
acquired in the Seneca Acquisition and the audited historical statements of revenues and direct operating expenses for the properties
acquired in the Cabot Acquisition each included elsewhere in this prospectus, and making certain pro forma adjustments to such
aggregated financial information to give effect to the transactions defined below, collectively the Transactions:
|
●
|
the increase in
Carbon’s ownership of Carbon California from 17.81% to 56.41% of voting and profits interest on February 1, 2018 in
connection with the exercise of certain warrants by Yorktown and the resulting consolidation of Carbon California (“Carbon
California Acquisition”) (note 2);
|
|
●
|
the Seneca Acquisition by Carbon California
(note 3);
|
|
●
|
additional borrowings under the Existing Credit
Facility (note 4);
|
|
●
|
the exercise of the Carbon Appalachian Warrant
(“Appalachia Warrant”) (note 5);
|
|
●
|
the proposed probable
acquisition by Carbon of Old Ironsides’ 73.5% of voting interest in Carbon Appalachia for approximately $58 million,
resulting in Carbon Appalachia becoming a wholly owned subsidiary of Carbon (“Old Ironsides Buyout”) (note 6);
|
|
●
|
the Cabot Acquisition made by Carbon Appalachia
(note 7);
|
|
●
|
the Enervest Acquisition made by Carbon Appalachia
(note 8);
|
|
●
|
conversion of Series B Preferred Stock in connection
with this Offering (note 9); and
|
|
●
|
the use of the remaining proceeds from this
Offering (note 10).
|
The Transactions, along with the assumptions
and estimates underlying the adjustments to the unaudited pro forma consolidated financial information, are described in more
detail in the accompanying notes, which should be read together with the unaudited pro forma consolidated financial information.
The unaudited pro forma consolidated
balance sheet as of June 30, 2018 and unaudited pro forma consolidated statements of operations for the six months ended June
30, 2018 and the year ended December 31, 2017 have been prepared in accordance with Article 11 of Regulation S-X, using the assumptions
set forth in the notes to the unaudited pro forma consolidated financial information.
The unaudited pro forma consolidated financial
information has been presented for illustrative purposes only and is based upon available information and reflects estimates and
certain assumptions made by our management that we believe are reasonable. Actual adjustments may differ materially from the information
presented herein. The unaudited pro forma consolidated financial information does not purport to represent what our consolidated
results of operations and financial position would have been had the Transactions occurred on the dates indicated. They are also
not intended to project our consolidated results of operations or financial position for any future period or date.
The unaudited pro forma consolidated financial
information does not reflect the realization of any expected cost savings, operating efficiencies or other synergies that may
result from the Transactions as a result of restructuring activities or other planned cost savings initiatives following the completion
of the Transactions.
The pro forma financial statements
should be read in conjunction with “Capitalization,” “Selected Historical Financial and Operating Data,”
“Management’s Discussion and Analysis of Financial Condition and Results of Operations,” “Certain Relationships
and Related Party Transactions,” “Description of Certain Indebtedness,” and our audited consolidated financial
statements and unaudited consolidated financial statements and the related notes and the other financial information included
elsewhere in this prospectus.
Carbon Energy Corporation
Unaudited Pro Forma Consolidated Statement of
Operations
For the six months ended June 30, 2018
(In Thousands, Except Per Share Data)
|
|
Carbon
Historical
|
|
|
CAC
Historical
(6c)
|
|
|
Seneca
Historical
(3d)
|
|
|
Adjustments
for Carbon California Acquisition
(2)
|
|
|
|
Adjustments
for
Old Ironsides
Buyout (6)
|
|
|
|
Other
Adjustments
(3)
|
|
|
|
Adjustments
for this
offering
(9,10)
|
|
|
|
Total
|
|
Revenue:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural
gas and liquid sales
|
|
$
|
8,175
|
|
|
$
|
25,556
|
|
|
$
|
127
|
|
|
$
|
10
|
|
2c
|
|
$
|
-
|
|
|
|
$
|
-
|
|
|
|
$
|
-
|
|
|
|
$
|
33,868
|
|
Oil
sales
|
|
|
11,074
|
|
|
|
813
|
|
|
|
4,036
|
|
|
|
760
|
|
2c
|
|
|
-
|
|
|
|
|
-
|
|
|
|
|
-
|
|
|
|
|
16,683
|
|
Transportation
and handling
|
|
|
-
|
|
|
|
1,476
|
|
|
|
-
|
|
|
|
-
|
|
|
|
|
-
|
|
|
|
|
-
|
|
|
|
|
-
|
|
|
|
|
1,476
|
|
Marketing
gas sales
|
|
|
-
|
|
|
|
17,046
|
|
|
|
-
|
|
|
|
-
|
|
|
|
|
-
|
|
|
|
|
-
|
|
|
|
|
-
|
|
|
|
|
17,046
|
|
Commodity
derivative (loss) gain
|
|
|
(6,647
|
)
|
|
|
(469
|
)
|
|
|
-
|
|
|
|
(973
|
)
|
2c
|
|
|
-
|
|
|
|
|
-
|
|
|
|
|
-
|
|
|
|
|
(8,089
|
)
|
Other
income
|
|
|
19
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
|
-
|
|
|
|
|
-
|
|
|
|
|
-
|
|
|
|
|
19
|
|
Total
revenue
|
|
|
12,621
|
|
|
|
44,422
|
|
|
|
4,163
|
|
|
|
(203
|
)
|
|
|
|
-
|
|
|
|
|
-
|
|
|
|
|
-
|
|
|
|
|
61,003
|
|
Expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease
operating expenses
|
|
|
6,058
|
|
|
|
10,961
|
|
|
|
1,219
|
|
|
|
250
|
|
2c
|
|
|
-
|
|
|
|
|
-
|
|
|
|
|
-
|
|
|
|
|
18,488
|
|
Transportation
and gathering costs
|
|
|
2,353
|
|
|
|
5,921
|
|
|
|
-
|
|
|
|
87
|
|
2c
|
|
|
-
|
|
|
|
|
-
|
|
|
|
|
-
|
|
|
|
|
8,361
|
|
Production
and property taxes
|
|
|
1,048
|
|
|
|
2,278
|
|
|
|
140
|
|
|
|
42
|
|
2c
|
|
|
-
|
|
|
|
|
-
|
|
|
|
|
-
|
|
|
|
|
3,508
|
|
Marketing
gas purchases
|
|
|
-
|
|
|
|
13,912
|
|
|
|
-
|
|
|
|
-
|
|
|
|
|
-
|
|
|
|
|
-
|
|
|
|
|
-
|
|
|
|
|
13,912
|
|
General
and administrative
|
|
|
5,491
|
|
|
|
1,383
|
|
|
|
-
|
|
|
|
312
|
|
2c
|
|
|
-
|
|
|
|
|
-
|
|
|
|
|
-
|
|
|
|
|
7,186
|
|
General
and administrative-related party reimbursement
|
|
|
(2,213
|
)
|
|
|
-
|
|
|
|
-
|
|
|
|
64
|
|
2b
|
|
|
2,149
|
|
6d
|
|
|
-
|
|
|
|
|
-
|
|
|
|
|
-
|
|
Depreciation,
depletion and amortization
|
|
|
3,471
|
|
|
|
2,934
|
|
|
|
-
|
|
|
|
77
|
|
2c
|
|
|
526
|
|
6f
|
|
|
277
|
|
3c
|
|
|
-
|
|
|
|
|
7,285
|
|
Management
and operating fee, related party
|
|
|
-
|
|
|
|
2,102
|
|
|
|
-
|
|
|
|
-
|
|
|
|
|
(2,149
|
)
|
6d
|
|
|
-
|
|
|
|
|
-
|
|
|
|
|
(47
|
)
|
Accretion
of asset retirement obligations
|
|
|
303
|
|
|
|
265
|
|
|
|
-
|
|
|
|
17
|
|
2c
|
|
|
-
|
|
|
|
|
-
|
|
|
|
|
-
|
|
|
|
|
585
|
|
Total
expenses
|
|
|
16,511
|
|
|
|
39,756
|
|
|
|
1,359
|
|
|
|
849
|
|
|
|
|
526
|
|
|
|
|
277
|
|
|
|
|
-
|
|
|
|
|
59,278
|
|
Operating
(loss) income
|
|
|
(3,890
|
)
|
|
|
4,666
|
|
|
|
2,804
|
|
|
|
(1,052
|
)
|
|
|
|
(526
|
)
|
|
|
|
(277
|
)
|
|
|
|
-
|
|
|
|
|
1,725
|
|
Other
income and (expense):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest
expense
|
|
|
(2,203
|
)
|
|
|
(1,187
|
)
|
|
|
-
|
|
|
|
(196
|
)
|
2c
|
|
|
-
|
|
|
|
|
(794
|
)
|
3d
|
|
|
-
|
|
|
|
|
(4,380
|
)
|
Warrant
derivative gain
|
|
|
225
|
|
|
|
-
|
|
|
|
-
|
|
|
|
(225
|
)
|
2b
|
|
|
-
|
|
|
|
|
-
|
|
|
|
|
-
|
|
|
|
|
-
|
|
Equity
investment gain
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
|
-
|
|
|
|
|
-
|
|
|
|
|
-
|
|
|
|
|
-
|
|
Investment
in affiliate
|
|
|
962
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
|
(948
|
)
|
6d
|
|
|
-
|
|
|
|
|
-
|
|
|
|
|
14
|
|
Gain
on derecognized equity investment in affiliate
|
|
|
5,390
|
|
|
|
|
|
|
|
|
|
|
|
(5,390
|
)
|
2b
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
-
|
|
Total
other income and (expense)
|
|
|
4,374
|
|
|
|
(1,187
|
)
|
|
|
-
|
|
|
|
(5,811
|
)
|
|
|
|
(948
|
)
|
|
|
|
(794
|
)
|
|
|
|
-
|
|
|
|
|
(4,366
|
)
|
Income
(loss) before income taxes
|
|
|
484
|
|
|
|
3,479
|
|
|
|
2,804
|
|
|
|
(6,863
|
)
|
|
|
|
(1,474
|
)
|
|
|
|
(1,071
|
)
|
|
|
|
-
|
|
|
|
|
(2,641
|
)
|
Provision
for income taxes
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
|
-
|
|
|
|
|
-
|
|
|
|
|
-
|
|
|
|
|
-
|
|
Net
income (loss) before non-controlling interest
|
|
|
484
|
|
|
|
3,479
|
|
|
|
2,804
|
|
|
|
(6,863
|
)
|
|
|
|
(1,474
|
)
|
|
|
|
(1,071
|
)
|
|
|
|
-
|
|
|
|
|
(2,641
|
)
|
Net
income (loss) attributable to non-controlling interests
|
|
|
(2,505
|
)
|
|
|
-
|
|
|
|
-
|
|
|
|
(2,992
|
)
|
2b
|
|
|
|
|
|
|
|
628
|
|
3e
|
|
|
-
|
|
|
|
|
(4,869
|
)
|
Net
income (loss) attributable to controlling interest
|
|
$
|
2,989
|
|
|
$
|
3,479
|
|
|
$
|
2,804
|
|
|
$
|
(3,871
|
)
|
|
|
$
|
(1,474
|
)
|
|
|
$
|
(1,699
|
)
|
|
|
$
|
-
|
|
|
|
$
|
2,228
|
|
Pro
forma net income (loss) per common share:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
$
|
0.41
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
0.28
|
|
Diluted
|
|
$
|
0.20
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
0.13
|
|
Pro
forma weighted average common shares outstanding (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
|
7,346
|
|
|
|
|
|
|
|
|
|
|
|
1,528
|
|
2d
|
|
|
|
|
|
|
|
|
|
|
|
|
625
|
|
9b
|
|
|
7,955
|
|
Diluted
|
|
|
7,662
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
8,185
|
|
See notes to unaudited pro forma consolidated
financial information.
Carbon Energy Corporation
Unaudited Pro Forma Consolidated Statement of Operations
For the year Ended December 31, 2017
(In Thousands, Except Per Share Data)
|
|
Carbon
Historical
|
|
|
CCC
Historical
(2b)
|
|
|
Seneca
Historical
(3c)
|
|
|
CAC
Historical
(6b)
|
|
|
Cabot
Historical
(7b)
|
|
|
Adjustments
for Carbon
California
Acquisition
(2)
|
|
|
|
Adjustments
for Old
Ironsides
Buyout
(6)
|
|
|
Other
Adjustments
(3,4,5,7,8)
|
|
|
|
Adjustments
for this
offering
(9,10)
|
|
|
Total
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenue:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural
gas and liquid sales
|
|
$
|
15,298
|
|
|
$
|
1,592
|
|
|
$
|
130
|
|
|
$
|
16,128
|
|
|
$
|
27,042
|
|
|
$
|
-
|
|
|
|
$
|
-
|
|
|
$
|
2,914
|
|
8a
|
|
$
|
-
|
|
|
$
|
63,104
|
|
Oil
sales
|
|
|
4,213
|
|
|
|
7,024
|
|
|
|
13,143
|
|
|
|
685
|
|
|
|
454
|
|
|
|
-
|
|
|
|
|
-
|
|
|
|
-
|
|
|
|
|
-
|
|
|
|
25,519
|
|
Transportation
and handling
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
911
|
|
|
|
-
|
|
|
|
-
|
|
|
|
|
-
|
|
|
|
-
|
|
|
|
|
-
|
|
|
|
911
|
|
Marketing
gas sales
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
11,315
|
|
|
|
12,070
|
|
|
|
-
|
|
|
|
|
-
|
|
|
|
-
|
|
|
|
|
-
|
|
|
|
23,385
|
|
Commodity
derivative (loss) gain
|
|
|
2,928
|
|
|
|
(1,381
|
)
|
|
|
-
|
|
|
|
2,545
|
|
|
|
-
|
|
|
|
-
|
|
|
|
|
-
|
|
|
|
-
|
|
|
|
|
-
|
|
|
|
4,092
|
|
Other
income
|
|
|
34
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
363
|
|
|
|
-
|
|
|
|
|
-
|
|
|
|
29
|
|
8a
|
|
|
-
|
|
|
|
426
|
|
Total revenue
|
|
|
22,473
|
|
|
|
7,235
|
|
|
|
13,273
|
|
|
|
31,584
|
|
|
|
39,929
|
|
|
|
-
|
|
|
|
|
-
|
|
|
|
2,943
|
|
|
|
|
-
|
|
|
|
117,437
|
|
Expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease
operating expenses
|
|
|
6,141
|
|
|
|
3,726
|
|
|
|
5,690
|
|
|
|
5,587
|
|
|
|
8,982
|
|
|
|
-
|
|
|
|
|
-
|
|
|
|
1,367
|
|
8a
|
|
|
-
|
|
|
|
31,493
|
|
Transportation
and gathering costs
|
|
|
2,172
|
|
|
|
1,442
|
|
|
|
-
|
|
|
|
4,160
|
|
|
|
9,179
|
|
|
|
-
|
|
|
|
|
-
|
|
|
|
709
|
|
8a
|
|
|
-
|
|
|
|
17,662
|
|
Production
and property taxes
|
|
|
1,276
|
|
|
|
527
|
|
|
|
516
|
|
|
|
1,464
|
|
|
|
4,183
|
|
|
|
-
|
|
|
|
|
-
|
|
|
|
96
|
|
8a
|
|
|
-
|
|
|
|
8,062
|
|
Marketing
gas purchases
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
9,290
|
|
|
|
10,389
|
|
|
|
-
|
|
|
|
|
-
|
|
|
|
-
|
|
|
|
|
-
|
|
|
|
19,679
|
|
General
and administrative
|
|
|
9,528
|
|
|
|
2,177
|
|
|
|
-
|
|
|
|
2,044
|
|
|
|
-
|
|
|
|
-
|
|
|
|
|
-
|
|
|
|
(660
|
)
|
7a
|
|
|
-
|
|
|
|
13,089
|
|
General
and administrative -related party reimbursement
|
|
|
(2,703
|
)
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
1,000
|
|
2b
|
|
|
1,703
|
|
6d
|
|
-
|
|
|
|
|
-
|
|
|
|
-
|
|
Depreciation,
depletion and amortization
|
|
|
2,544
|
|
|
|
1,304
|
|
|
|
-
|
|
|
|
2,439
|
|
|
|
-
|
|
|
|
321
|
|
2e
|
|
|
3,895
|
|
6f
|
|
830
|
|
3c
|
|
|
-
|
|
|
|
11,334
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,904
|
|
7d
|
|
|
|
|
|
|
1,904
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
667
|
|
8c
|
|
|
|
|
|
|
667
|
|
Accretion
of asset retirement obligations
|
|
|
307
|
|
|
|
192
|
|
|
|
-
|
|
|
|
198
|
|
|
|
-
|
|
|
|
-
|
|
|
|
|
-
|
|
|
|
-
|
|
|
|
|
-
|
|
|
|
697
|
|
Management
and operating fee, related party
|
|
|
-
|
|
|
|
525
|
|
|
|
-
|
|
|
|
1,582
|
|
|
|
-
|
|
|
|
(525
|
)
|
2b
|
|
|
(1,582
|
)
|
6d
|
|
|
|
|
|
|
-
|
|
|
|
-
|
|
Impairment
of oil and gas properties
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
|
-
|
|
|
|
-
|
|
|
|
|
-
|
|
|
|
-
|
|
Total expenses
|
|
|
19,265
|
|
|
|
9,893
|
|
|
|
6,206
|
|
|
|
26,764
|
|
|
|
32,733
|
|
|
|
796
|
|
|
|
|
4,016
|
|
|
|
4,913
|
|
|
|
|
-
|
|
|
|
104,587
|
|
Operating
(loss) income
|
|
|
3,208
|
|
|
|
(2,658
|
)
|
|
|
7,067
|
|
|
|
4,820
|
|
|
|
7,196
|
|
|
|
(796
|
)
|
|
|
|
(4,016
|
)
|
|
|
(1,970
|
)
|
|
|
|
-
|
|
|
|
12,850
|
|
Other
income and (expense):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest
expense
|
|
|
(1,202
|
)
|
|
|
(2,040
|
)
|
|
|
-
|
|
|
|
(891
|
)
|
|
|
-
|
|
|
|
-
|
|
|
|
|
-
|
|
|
|
(221
|
)
|
4
|
|
|
-
|
|
|
|
(4,354
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(817
|
)
|
7c
|
|
|
|
|
|
|
(817
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(255)
|
|
8b
|
|
|
|
|
|
|
(255
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(2,383)
|
|
3d
|
|
|
|
|
|
|
(2,383
|
)
|
Warrant
derivative gain
|
|
|
3,133
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
(3,752
|
)
|
2b
|
|
|
-
|
|
|
|
619
|
|
5
|
|
|
-
|
|
|
|
-
|
|
Equity
investment gain
|
|
|
1,158
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
|
(1,090
|
)
|
6d
|
|
-
|
|
|
|
|
-
|
|
|
|
68
|
|
Class
B Unit Issuance
|
|
|
-
|
|
|
|
(1,854
|
)
|
|
|
-
|
|
|
|
(924
|
)
|
|
|
-
|
|
|
|
1,854
|
|
2b
|
|
|
924
|
|
6d
|
|
-
|
|
|
|
|
-
|
|
|
|
-
|
|
Other
|
|
|
28
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
|
-
|
|
|
|
-
|
|
|
|
|
-
|
|
|
|
28
|
|
Total
other income and (expense)
|
|
|
3,117
|
|
|
|
(3,894
|
)
|
|
|
-
|
|
|
|
(1,815
|
)
|
|
|
-
|
|
|
|
(1,898
|
)
|
|
|
|
(166
|
)
|
|
|
(3,057
|
)
|
|
|
|
-
|
|
|
|
(7,713
|
)
|
Income
(loss) before income taxes
|
|
|
6,325
|
|
|
|
(6,552
|
)
|
|
|
7,067
|
|
|
|
3,005
|
|
|
|
7,196
|
|
|
|
(2,694
|
)
|
|
|
|
(4,182
|
)
|
|
|
(5,027
|
)
|
|
|
|
-
|
|
|
|
5,137
|
|
Provision
for income taxes
|
|
|
(74
|
)
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
|
-
|
|
|
|
-
|
|
|
|
|
-
|
|
|
|
(74
|
)
|
Net
income (loss) before non-controlling interest
|
|
|
6,399
|
|
|
|
(6,552
|
)
|
|
|
7,067
|
|
|
|
3,005
|
|
|
|
7,196
|
|
|
|
(2,694
|
)
|
|
|
|
(4,182
|
)
|
|
|
(5,027
|
)
|
|
|
|
-
|
|
|
|
5,211
|
|
Net
income (loss) attributable to non-controlling interests
|
|
|
81
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
(2,856
|
)
|
2b
|
|
|
|
|
|
|
1,613
|
|
3g
|
|
|
-
|
|
|
|
(1,162
|
)
|
Net
income (loss) attributable to controlling interest
|
|
$
|
6,318
|
|
|
$
|
(6,552
|
)
|
|
$
|
7,067
|
|
|
$
|
3,005
|
|
|
$
|
7,196
|
|
|
$
|
162
|
|
|
|
$
|
(4,182
|
)
|
|
$
|
(6,640
|
)
|
|
|
$
|
-
|
|
|
$
|
6,374
|
|
Pro
forma net income (loss) per common share:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
$
|
1.12
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
0.78
|
|
Diluted
|
|
$
|
0.49
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
0.58
|
|
Pro
forma weighted average common shares outstanding (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
|
5,662
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,528
|
|
2d
|
|
|
|
|
|
|
432
|
|
5
|
|
|
625
|
|
9b
|
|
8,176
|
|
Diluted
|
|
|
6,465
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
8,966
|
|
See notes to unaudited pro forma consolidated
financial information.
Carbon Energy Corporation
Unaudited Pro Forma Consolidated Balance Sheet
- As of June 30, 2018
(In Thousands)
|
|
Carbon
Historical
|
|
|
Adjustment
for Old
Ironsides
Buyout
(6)
|
|
|
|
Adjustment
for conversion
of Preferred
Stock
(9)
|
|
|
|
Adjustments
for the
offering
(10)
|
|
|
Total
|
|
Current assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$
|
4,030
|
|
|
$
|
(58,000
|
)
|
6e
|
|
$
|
-
|
|
|
|
$
|
58,000
|
|
|
$
|
16,687
|
|
|
|
|
|
|
|
$
|
12,657
|
|
6a
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts receivable:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenue
|
|
|
4,713
|
|
|
|
3,133
|
|
6a
|
|
|
-
|
|
|
|
|
-
|
|
|
|
7,846
|
|
Joint interest
billings and other
|
|
|
1,417
|
|
|
|
3,880
|
|
6a
|
|
|
-
|
|
|
|
|
-
|
|
|
|
5,297
|
|
Receivable –
related party
|
|
|
-
|
|
|
|
-
|
|
|
|
|
-
|
|
|
|
|
-
|
|
|
|
-
|
|
Due from related
parties
|
|
|
1,158
|
|
|
|
(1,158
|
)
|
6e
|
|
|
-
|
|
|
|
|
-
|
|
|
|
-
|
|
Insurance receivable
|
|
|
665
|
|
|
|
-
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
665
|
|
Other
|
|
|
133
|
|
|
|
-
|
|
|
|
|
-
|
|
|
|
|
-
|
|
|
|
133
|
|
Commodity derivative asset
|
|
|
-
|
|
|
|
60
|
|
6a
|
|
|
-
|
|
|
|
|
-
|
|
|
|
60
|
|
Inventories
|
|
|
-
|
|
|
|
1,230
|
|
6a
|
|
|
|
|
|
|
|
|
|
|
|
1,230
|
|
Prepaid
expense, deposits, and other current assets
|
|
|
1,937
|
|
|
|
515
|
|
6a
|
|
|
-
|
|
|
|
|
-
|
|
|
|
2,452
|
|
Total current assets
|
|
|
14,053
|
|
|
|
(37,683
|
)
|
|
|
|
-
|
|
|
|
|
58,000
|
|
|
|
34,370
|
|
Property and equipment
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil
and gas properties, full cost method of accounting:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved, net
|
|
|
126,510
|
|
|
|
108,006
|
|
6a
|
|
|
-
|
|
|
|
|
-
|
|
|
|
234,516
|
|
Unproved
|
|
|
3,577
|
|
|
|
1,8191
|
|
6a
|
|
|
-
|
|
|
|
|
-
|
|
|
|
5,396
|
|
Other property, equipment, net
|
|
|
2,134
|
|
|
|
10,842
|
|
6a
|
|
|
-
|
|
|
|
|
-
|
|
|
|
12,976
|
|
Total property and equipment, net
|
|
|
132,221
|
|
|
|
120,667
|
|
|
|
|
-
|
|
|
|
|
-
|
|
|
|
252,888
|
|
Investments in affiliates
|
|
|
13,375
|
|
|
|
(12,692
|
)
|
6e
|
|
|
-
|
|
|
|
|
-
|
|
|
|
683
|
|
Other long-term assets
|
|
|
2,737
|
|
|
|
1,109
|
|
6a
|
|
|
-
|
|
|
|
|
-
|
|
|
|
3,846
|
|
Total assets
|
|
$
|
162,386
|
|
|
$
|
71,401
|
|
|
|
$
|
-
|
|
|
|
$
|
58,000
|
|
|
$
|
291,787
|
|
LIABILITIES
AND STOCKHOLDERS’ EQUITY
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts payable and accrued liabilities
|
|
$
|
15,148
|
|
|
$
|
10,970
|
|
6a
|
|
$
|
-
|
|
|
|
$
|
-
|
|
|
$
|
24,960
|
|
|
|
|
|
|
|
$
|
(1,158
|
)
|
6e
|
|
|
-
|
|
|
|
|
|
|
|
|
|
|
Due to related parties
|
|
|
-
|
|
|
|
-
|
|
|
|
|
-
|
|
|
|
|
-
|
|
|
|
-
|
|
Asset retirement obligations
|
|
|
-
|
|
|
|
-
|
|
|
|
|
-
|
|
|
|
|
-
|
|
|
|
-
|
|
Firm transportation contract obligations
|
|
|
75
|
|
|
|
3,561-
|
|
6a
|
|
|
-
|
|
|
|
|
-
|
|
|
|
3,636
|
|
Commodity derivative liability
|
|
|
4,570
|
|
|
|
-
|
|
|
|
|
-
|
|
|
|
|
-
|
|
|
|
4,570
|
|
Total current
liabilities
|
|
|
19,793
|
|
|
|
13,373
|
|
|
|
|
-
|
|
|
|
|
-
|
|
|
|
33,166
|
|
Non-current liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Firm transportation contract obligations
|
|
|
123
|
|
|
|
13,227
|
|
6a
|
|
|
-
|
|
|
|
|
-
|
|
|
|
13,350
|
|
Commodity derivative liability
|
|
|
3,447
|
|
|
|
-
|
|
|
|
|
-
|
|
|
|
|
-
|
|
|
|
3,447
|
|
Production and property taxes payable
|
|
|
550
|
|
|
|
2,008-
|
|
6a
|
|
|
-
|
|
|
|
|
-
|
|
|
|
2,558
|
|
Warrant derivative liability
|
|
|
-
|
|
|
|
-
|
|
|
|
|
-
|
|
|
|
|
-
|
|
|
|
-
|
|
Asset retirement obligations
|
|
|
10,831
|
|
|
|
4,818
|
|
6a
|
|
|
-
|
|
|
|
|
-
|
|
|
|
15,649
|
|
Notes, related party, net
|
|
|
-
|
|
|
|
-
|
|
|
|
|
-
|
|
|
|
|
-
|
|
|
|
-
|
|
Credit facility, related party
|
|
|
49,900
|
|
|
|
-
|
|
|
|
|
-
|
|
|
|
|
-
|
|
|
|
49,900
|
|
Credit facility
|
|
|
23,140
|
|
|
|
37,975
|
|
6a
|
|
|
|
|
|
|
|
|
|
|
|
61,115
|
|
Long-term debt
|
|
|
78
|
|
|
|
-
|
|
|
|
|
-
|
|
|
|
|
-
|
|
|
|
78
|
|
Total non-current
liabilities
|
|
|
88,069
|
|
|
|
58,028
|
|
|
|
|
-
|
|
|
|
|
-
|
|
|
|
146,097
|
|
Stockholders’ equity:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Preferred stock
|
|
|
1
|
|
|
|
-
|
|
|
|
|
(1
|
)
|
9a
|
|
|
-
|
|
|
|
-
|
|
Common stock
|
|
|
76
|
|
|
|
-
|
|
|
|
|
6
|
|
9a
|
|
|
-
|
|
|
|
82
|
|
Additional paid-in capital
|
|
|
75,594
|
|
|
|
-
|
|
|
|
|
(5
|
)
|
9a
|
|
|
58,000
|
|
|
|
133,589
|
|
Accumulated deficit
|
|
|
(42,424
|
)
|
|
|
-
|
|
|
|
|
-
|
|
|
|
|
-
|
|
|
|
(42,424
|
)
|
Total Carbon
stockholders’ equity
|
|
|
33,247
|
|
|
|
-
|
|
|
|
|
-
|
|
|
|
|
58,000
|
|
|
|
91,247
|
|
Non-controlling interests
|
|
|
21,277
|
|
|
|
-
|
|
|
|
|
-
|
|
|
|
|
-
|
|
|
|
21,277
|
|
Total stockholders’
equity
|
|
|
54,524
|
|
|
|
-
|
|
|
|
|
-
|
|
|
|
|
58,000
|
|
|
|
112,524
|
|
Total liabilities
and stockholders’ equity
|
|
$
|
162,386
|
|
|
$
|
71,401
|
|
|
|
$
|
-
|
|
|
|
$
|
58,000
|
|
|
$
|
291,787
|
|
See notes to unaudited pro forma consolidated
financial information.
Carbon Energy Corporation
(formerly known as Carbon Natural Gas
Company)
Notes to Unaudited Pro Forma Consolidated Financial Information
All amounts are in thousands, unless
specifically stated otherwise or for share data
The unaudited pro forma
consolidated financial information is based upon the historical financial statements of Carbon, the audited and unaudited historical
financial statements of Carbon California, the audited and unaudited historical financial statements of Carbon Appalachia, the
audited and unaudited historical statements of revenues and direct operating expenses for the properties acquired in the Seneca
Acquisition and the audited historical statements of revenues and direct operating expenses for the properties acquired in the
Cabot Acquisition, as adjusted for the impact of the Transactions, as if the Transactions occurred on June 30, 2018, in the case
of the unaudited pro forma consolidated balance sheet as of June 30, 2018, or as of January 1, 2017, in the case of the unaudited
pro forma combined statements of operations for the year ended December 31, 2017, and the six months ended June 30, 2018. The
historical financial statements have been adjusted to give pro forma effect to events that are (i) directly attributable to the
Transactions, (ii) factually supportable and (iii) with respect to the unaudited pro forma consolidated statements of operations,
expected to have a continuing impact on the consolidated results following the Transactions.
The business combination was
accounted for under the acquisition method of accounting in accordance with Financial Accounting Standards Board Accounting Standards
Codification (“ASC”), Topic 805, Business Combinations.
The unaudited pro forma consolidated
financial statements do not necessarily reflect what the company’s financial condition or results of operations would have
been had the Transactions occurred on the dates indicated. They also may not be useful in predicting our future financial condition
and results of operations. Our actual financial position and results of operations may differ significantly from the pro forma
amounts reflected herein due to a variety of factors.
The historical audited statements
of Carbon California and Carbon Appalachia are prepared from the date of their formation, February 15, 2017 and April 3, 2017,
respectively, through December 31, 2017. The CRC Acquisition and the Mirada Acquisition closed on the date of formation of Carbon
California, as such, the operations of the assets acquired in the CRC Acquisition and Mirada Acquisition are included in the entire
historical period presented in the audited historical statements of Carbon California. The CNX Acquisition closed on the date
of formation of Carbon Appalachia, as such, the CNX Acquisition is included in the entire historical period presented within the
audited historical financial statements of Carbon Appalachia. No pro forma adjustments have been made to include the CRC, Mirada
and CNX Acquisitions as if they occurred on January 1, 2017 because it is impracticable to do so prior to the formation of Carbon
California and Carbon Appalachia. We believe that excluding these acquisitions for these periods – for Carbon California
excluding 45 days of the operations of the assets assumed in the CRC and Mirada Acquisitions and for Carbon Appalachia excluding
123 days of the operations of the assets assumed in the CNX Acquisition – does not have a material effect on our unaudited
consolidated pro forma statement of operations.
|
2.
|
Adjustments
for the increase in Carbon’s ownership of Carbon California from 17.81% to 56.41%
of voting and profit interest on February 1, 2018 in connection with the exercise of
certain warrants by Yorktown and the resulting consolidation of Carbon California
|
Carbon California was formed
on February 15, 2017 by Carbon and other institutional investors to acquire, divest and operate oil and gas properties in the
Ventura Basin of California.
In connection with the entry
into the Carbon California LLC Agreement, we received Class B Units and issued to Yorktown a warrant to purchase approximately
1.5 million shares of our common stock at an exercise price of $7.20 per share (the “California Warrant”). The exercise
price for the California Warrant is payable exclusively with Class A Units of Carbon California held by Yorktown and the number
of shares of our common stock for which the California Warrant is exercisable is determined, as of the time of exercise, by dividing
(a) the aggregate unreturned capital of Yorktown’s Class A Units of Carbon California by (b) the exercise price. The California
Warrant had a term of seven years and included certain standard registration rights with respect to the shares of our common stock
issuable upon exercise of the California Warrant. Yorktown exercised the California Warrant on February 1, 2018.
The issuance of the Class B
Units and the warrant were in contemplation of each other, and under non-monetary related party guidance, we accounted for the
California Warrant, at issuance, based on the fair value of the California Warrant as of the date of grant (February 15, 2017)
and recorded a long-term warrant liability with an associated offset to APIC. Future changes to the fair value of the California
Warrant are recognized in earnings. We accounted for the fair value of the Class B Units at their estimated fair value at the
date of grant, which became our investment in Carbon California with an offsetting entry to APIC.
On February 1, 2018, Yorktown
exercised the California Warrant resulting in the issuance of 1,527,778 shares of our common stock in exchange for Yorktown’s
Class A Units of Carbon California representing approximately 46.96% of the outstanding Class A Units of Carbon California and
a profits interest of approximately 38.59%. After giving effect to the exercise on February 1, 2018, we own 56.41% of the voting
and profits interests of Carbon California.
The exercise of the warrant
and the acquisition of the additional ownership interest, which is a majority financial interest, qualifies as a change of control
and should be accounted for as a business combination in accordance with ASC 805,
Business Combinations
(“ASC 805”).
The Company will consolidate the results of Carbon California into its consolidated financial statements from the date of the
acquisition forward.
(a)
|
Audited Historical
Statement of Operations.
Reflects the inclusion of Carbon California’s audited historical statement of operations
for the period ended December 31, 2017, included elsewhere in this prospectus.
|
(b)
|
Effect of acquisition
of Carbon California on unaudited pro forma consolidated statements of operations.
Reflects the following adjustments
to the pro forma consolidated statement of operations to reflect the exercise of the Warrant as if it occurred on the date
of formation of Carbon California:
|
Description
|
|
Adjustment
for six months ended June 30,
2018
|
|
|
Adjustment
for year ended December 31,
2017
|
|
|
Explanation
|
Reduction
of unrealized gain on warrant liability
|
|
$
|
225
|
|
|
$
|
3,752
|
|
|
Due to the conversion of the warrant,
there will no longer be an ongoing effect to the statement of operations, as such this adjustment reflects removal of the
unrealized gain
|
Decrease of
General and administrative-related party reimbursement
|
|
$
|
64
|
|
|
$
|
1,000
|
|
|
This reimbursement is paid by Carbon California
to Carbon. As Carbon California will be a consolidated entity going forward the reimbursement amount has been eliminated
|
Decrease of
Management and operating fee, related party
|
|
$
|
-
|
|
|
$
|
525
|
|
|
This fee was paid to Carbon, as Carbon California
will now be a consolidated entity this expense would be eliminated
|
Decrease to loss on Class B issuance
|
|
$
|
-
|
|
|
$
|
1,854
|
|
|
Elimination of loss on class B share issuance
because the holder of the shares is Carbon
|
Decrease of
Gain on derecognized equity investment in affiliate
|
|
$
|
5,391
|
|
|
$
|
-
|
|
|
Eliminate the gain on step acquisition following
fair value method of Carbon California upon gaining control
|
Adjustments to increase (decrease) to
Net loss attributable to non-controlling interest for the portion of earnings attributable to the non-controlling interest for
Carbon California:
|
|
Amount
|
|
|
NCI %
|
|
|
Adjustment
|
|
For the year ended December 31, 2017
|
|
$
|
6,552
|
|
|
|
43.59
|
%
|
|
$
|
2,856
|
|
For the six
months ended June 30, 2018 – Cumulative adjustment for 2c $(1,183) and 2b ($5,680)
|
|
$
|
(6,863
|
)
|
|
|
43.59
|
%
|
|
$
|
(2,992
|
)
|
(c)
|
Adjustment for
results of operations for Carbon California from January 1, 2018 to January 31, 2018.
Carbon California became a consolidated
entity as of February 1, 2018, this adjustment reflects the results of operations for Carbon California as if the conversion
of the California Warrant occurred on January 1, 2018.
|
|
|
For
the period
from January 1,
2018 to
January 31,
2018
|
|
Revenue:
|
|
|
|
Natural
gas and liquid sales
|
|
$
|
10
|
|
Oil sales
|
|
|
760
|
|
Commodity derivative
(loss) gain
|
|
|
(973
|
)
|
Other income
|
|
|
-
|
|
Total revenue
|
|
|
(203
|
)
|
Expenses:
|
|
|
|
|
Lease operating expenses
|
|
|
250
|
|
Transportation and
gathering costs
|
|
|
87
|
|
Production and property
taxes
|
|
|
42
|
|
General and administrative
|
|
|
312
|
|
Depreciation, depletion
and amortization
|
|
|
77
|
|
Accretion of asset
retirement obligations
|
|
|
17
|
|
Total expenses
|
|
|
785
|
|
Operating (loss) income
|
|
|
(988
|
)
|
Other income and (expense):
|
|
|
|
|
Interest expense
|
|
|
(196
|
)
|
Total other income and (expense)
|
|
|
(196
|
)
|
Income (loss) before income taxes
|
|
|
(1,184
|
)
|
Provision for income taxes
|
|
|
-
|
|
Net income (loss) before non-controlling interest
|
|
|
(1,184
|
)
|
Net income (loss) attributable to non-controlling
interests
|
|
|
-
|
|
Net income (loss) attributable to controlling
interest
|
|
$
|
(1,184
|
)
|
(d)
|
Earnings per
share.
1,527,778 shares of Carbon common stock were issued to the warrant holder, we have adjusted weighted average shares
outstanding to reflect these additional shares as if the exercise occurred on January 1, 2017.
|
(e)
|
Depletion
expense
. Reflects the calculation of the estimated depletion expense based on the estimated fair value of oil and gas
assets acquired based on the historical depletion rate of the assets to be acquired in Carbon California Acquisition. This
estimation is based on the preliminary fair value of the proved oil and gas assets multiplied by the historical Carbon California
annual depletion rate of 1.72%.
|
|
|
Depletable
base
|
|
|
Depletion
Rate
|
|
|
For
the year
ended
December 31,
2017
|
|
Estimated Depletion
|
|
$
|
90,319
|
|
|
|
1.72
|
%
|
|
$
|
1,556
|
|
Remove: actual depletion
|
|
|
|
|
|
|
|
|
|
|
(1,235
|
)
|
Pro forma adjustment
|
|
|
|
|
|
|
|
|
|
$
|
321
|
|
The adjustment for depletion
for the period when Carbon California was not consolidated, from January 1, 2018 through January 31, 2018, is considered immaterial,
thus, no adjustment has been made.
|
(f)
|
Income
taxes.
Carbon California has elected to be treated as a partnership for income tax
purposes. Accordingly, taxable income and losses are reported on the income tax returns
of Carbon California’s members, which includes the Company. Due to the limited
history of losses for Carbon California, we are unable to estimate the tax effect of
the Carbon California Acquisition on the Company’s statement of operations. As
such no pro forma adjustment has been made related to income taxes.
|
|
3.
|
Adjustments
for the Seneca Acquisition by Carbon California
|
In October 2017, Carbon California
signed a Purchase and Sale Agreement to acquire certain operated and non-operated oil and gas leases, and fee interests in and
to certain lands, situated in the Ventura Basin, together with associated wells, pipelines, facilities, equipment and other property
rights for a purchase price of $43.0 million, subject to customary and standard purchase price adjustments. After effective date
adjustments, we expect the purchase price to be approximately $37.4 million. We contributed approximately $5.0 million to Carbon
California to fund our portion of the purchase price, with the remainder funded by other equity members and debt.
The Seneca Acquisition closed
on May 1, 2018, with an effective date as of October 1, 2017. We raised our $5.0 million through the issuance of 50,000 shares
of Series B Convertible Preferred Stock, par value $0.01 per share (the “Preferred Stock”), to Yorktown. Upon the
completion of this offering, the Preferred Stock will automatically convert into shares of common stock. The conversion ratio
at which the Preferred Stock will convert into common stock is equal to an amount per share of $100 plus all accrued but unpaid
dividends payable in respect thereof (together, the “Liquidation Preference”) divided by the greater of (i) $8.00
per share or (ii) the price that is 15% less than the price per share of shares sold to the public in this offering.
The Seneca Acquisition meets
the definition of a business under Rule 11-01 (d) of Regulation S-X. As Carbon California is a consolidated entity based on our
acquisition of a majority financial interest in Carbon California (see note 2) and due to the significance of the Seneca Acquisition,
we have made an adjustment to reflect the Seneca Acquisition within the unaudited consolidated pro forma financial statements.
As the acquirer for accounting
purposes, Carbon California is required to estimate the fair value of the assets to be acquired and liabilities to be assumed.
The assets acquired and liabilities assumed for Seneca are on a preliminary basis and reflect the information currently available
to us. We are unable to estimate what, if anything, will change materially from our preliminary purchase price allocation.
The Seneca acquisition was
financed through an equity contribution of $10,000 ($5,000 by the Company and $5,000 by other investors), a draw on the Revolver
of $24,400 and issuance of $3,000 of new senior subordinated notes.
In connection with the issuance
of the $3.0 million in new subordinated notes, an investor of Carbon California received an additional equity interest, which
reduced Carbon’s ownership interest to approximately 53.92%, or a reduction of 2.49% from the ownership interest acquired
in the Carbon California acquisition (see Note 2).
|
(a)
|
Audited
historical statement of revenues and direct operating expenses.
Reflects the inclusion
of the revenues and direct operating expenses from the audited statements of revenues
and direct operating expenses for the properties acquired in the Seneca Acquisition,
included within this prospectus, as if the Seneca Acquisition occurred on January 1,
2017.
|
|
(b)
|
Unaudited
historical statement of revenues and direct operating expenses.
Reflects the inclusion
of the revenues and direct operating expenses from the unaudited statements of revenues
and direct operating expenses for the properties acquired in the Seneca Acquisition,
included within this prospectus, as if the Seneca Acquisition occurred on January 1,
2018.
|
The unaudited statement of revenues and direct
operating expenses is for the three months ended March 31, 2018. The Seneca Acquisition closed on May 1, 2018; therefore, there
was one additional month of activity between the date of the unaudited historical data provided and the closing date. The additional
month of activity has not been included because it does not have a material effect on our unaudited consolidated pro forma statement
of operations.
|
(c)
|
Depletion
expense
. Reflects the calculation of the estimated depletion expense based on the
estimated fair value of oil and gas assets acquired based on the historical depletion
rate for the assets acquired in the Seneca Acquisition.
|
Proved Reserves (Mcfe)
|
|
|
104,027,133
|
|
Production (Mcfe)
|
|
|
2,359,827
|
|
|
|
|
|
|
Estimated Depletion Rate (Production/Proved
Reserves)
|
|
|
2.22
|
%
|
|
|
Depletable
base
|
|
|
Depletion
Rate
|
|
|
For the six months ended
June 30,
2018
|
|
|
For the year ended December 31,
2017
|
|
Estimated Depletion
|
|
$
|
37,400
|
|
|
|
2.22
|
%
|
|
$
|
277
|
|
|
$
|
830
|
|
|
(d)
|
Interest
expense
.
Reflects the pro forma increase to interest expense from an anticipated additional draw
of $24,400 on the Carbon California revolver (increase in capacity to $41,000) and the
remaining $3,000 from issuance of additional senior subordinated notes to fund the Seneca
Acquisition, as if the draw had occurred on January 1, 2017. A hypothetical 1/8 percent
change in the rates applicable to our Revolver would not have a material impact on our
unaudited pro forma consolidated statements of operations for the six months ended June
30, 2018 nor for the year ended December 31, 2017.
|
|
|
Estimated Principal
|
|
|
Weighted Average Rate
|
|
|
For the six months ended
June 30, 2018
|
|
|
For the year ended December 31,
2017
|
|
Interest expense on Revolver
|
|
$
|
24,400
|
|
|
|
8.29
|
%
|
|
$
|
674
|
|
|
$
|
2,022
|
|
Additional
subordinated notes
|
|
$
|
3,000
|
|
|
|
12.00
|
%
|
|
|
120
|
|
|
|
360
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total pro forma
adjustment
|
|
|
|
|
|
|
|
|
|
$
|
794
|
|
|
$
|
2,383
|
|
|
(e)
|
Non-controlling
interest.
Reflect 46.08% of the results of operations related to the assets acquired
in the Seneca Acquisition as Net Income attributable to non-controlling interests and
the reduction to the non-controlling interest for the change of the 2.49% ownership interest
for Carbon California as follows:
|
|
|
Earnings (loss)
|
|
|
NCI %
|
|
|
For the six months ended
June 30, 2018
|
|
Seneca Historical
|
|
$
|
2,804
|
|
|
|
46.08
|
%
|
|
$
|
1,292
|
|
Cumulative effect of 3c and 3d
|
|
$
|
(913
|
)
|
|
|
46.08
|
%
|
|
|
(421
|
)
|
Effect of
ownership percentage change on cumulative Carbon California adjustments (See Net loss before non-controlling interest on pro
forma income statement column 4)
|
|
$
|
(6,863
|
)
|
|
|
2.49
|
%
|
|
|
(171
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total pro forma
adjustment
|
|
|
|
|
|
|
|
|
|
$
|
700
|
|
|
|
Earnings
(loss)
|
|
|
NCI
%
|
|
|
For
the year ended December 31, 2017
|
|
Seneca Historical
|
|
$
|
7,067
|
|
|
|
46.08
|
%
|
|
$
|
3,256
|
|
Cumulative effect of 3c and 3d
|
|
$
|
(2,739
|
)
|
|
|
46.08
|
%
|
|
|
(1,262
|
)
|
Update for Carbon California
results for change in ownership
|
|
$
|
(6,552
|
)
|
|
|
2.49
|
%
|
|
|
(163
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total pro forma adjustment
|
|
|
|
|
|
|
|
|
|
$
|
1,831
|
|
|
4.
|
Adjustments
for the additional borrowings under the Existing Credit Facility
|
In the third quarter of 2017,
the Company contributed approximately $6,625 to Carbon Appalachia. This funding was provided with borrowings under the Existing
Credit Facility.
This adjustment reflects the
increased interest expenses related to the additional borrowing under the Existing Credit Facility as if the borrowing occurred
on January 1, 2017. A hypothetical 1/8 percent change in the rates applicable to our Revolver would not have a material impact
on our unaudited pro forma consolidated statements of operations for the year ended December 31, 2017.
|
|
Principal
|
|
|
Weighted
Average
Rate
|
|
|
Interest
expense for the year ended December 31, 2017
|
|
Interest
expense
|
|
$
|
6,625
|
|
|
|
5.82
|
%
|
|
$
|
386
|
|
Remove
actual interest incurred
|
|
|
|
|
|
|
|
|
|
|
(165
|
)
|
Pro forma
adjustment
|
|
|
|
|
|
|
|
|
|
$
|
221
|
|
|
5.
|
Adjustments
for the exercise of the Appalachia Warrant
|
On April 3, 2017, we issued
to Yorktown a warrant to purchase approximately 408,000 shares of our common stock at an exercise price of $7.20 per share. The
exercise price for the Appalachia Warrant is payable exclusively with Class A Units of Carbon Appalachia held by Yorktown, and
the number of shares of our common stock for which the Appalachia Warrant is exercisable is determined, as of the time of exercise,
by dividing (a) the aggregate unreturned capital of Yorktown’s Class A Units of Carbon Appalachia plus a 10% internal rate
of return by (b) the exercise price. The Appalachia Warrant had a term of seven years and included certain standard registration
rights with respect to the shares of our common stock issuable upon exercise of the Appalachia Warrant.
On November 1, 2017, Yorktown
exercised the Appalachia Warrant resulting in the issuance of 432,051 shares of our common stock in exchange for Class A Units
representing approximately 7.95% of then outstanding Class A Units of Carbon Appalachia. We accounted for the exercise through
extinguishment of the warrant liability associated with the Appalachia Warrant of approximately $1,900 and the receipt of Yorktown’s
Class A Units as an increase to investment in affiliates in the amount of approximately $2,900. After giving effect to the exercise
on November 1, 2017, we owned 26.5% of Carbon Appalachia’s outstanding Class A Units, 100% of its Class B Units and 100%
of its Class C Units.
The related warrant derivative
liability was being fair valued in accordance with ASC 820,
Fair Value Measurements
, at each reporting period and as this
warrant has been exercised we have removed the related unrealized gains of $619 recognized during the year ended December 31,
2017 from the pro forma statement of operations.
Additionally, 432,051 shares
of Carbon common stock were issued to the warrant holder, we have adjusted weighted average share outstanding to reflect these
additional shares as if the exercise occurred on January 1, 2017.
|
6.
|
Adjustments
for the use of offering proceeds for the proposed probable acquisition by Carbon of Old
Ironsides’ 73.5% of voting interest in Carbon Appalachia for approximately $58
million, resulting in Carbon Appalachia becoming a wholly owned subsidiary of Carbon
|
Carbon Appalachia formed in
2016 by us, Yorktown and Old Ironsides to acquire producing assets in the Appalachian Basin in Kentucky, Tennessee, Virginia and
West Virginia. On April 3, 2017, we, Yorktown and Old Ironsides Energy, LLC, entered in to a limited liability company agreement
(the “Carbon Appalachia LLC Agreement”), with an initial equity commitment of $100.0 million, of which $37.0 million
has been contributed as of December 31, 2017.
As of December 31, 2017, we
owned 26.5% of the ownership interests in Carbon Appalachia and accounted for our ownership in Carbon Appalachia as an equity
method investment. In contemplation of this offering, our management has signed an agreement with Old Ironsides to use a portion
of our proceeds from this offering to purchase the additional ownership interest in Carbon Appalachia to bring our ownership to
100% (the “
Old Ironsides Buyout
”). Based on our related party relationships with Old Ironsides, we consider
this proposed acquisition to be probable, as such, we have included the acquisition of Carbon Appalachia in the unaudited pro
forma financial statements. This acquisition is expected to close in the second quarter of 2018, subject to negotiation and preparation
of definitive transaction documents and other customary closing conditions.
This transaction is considered
probable and based on the tests required by Rule 8-04 of Regulation S-X, the Old Ironsides Buyout meets the threshold for inclusion
despite not yet being closed. The Old Ironsides Buyout also meets the definition of a business under Rule 11-01 (d) of Regulation
S-X.
The proposed probable acquisition
of the additional ownership interest qualifies as a change of control and would be accounted for as a business combination in
accordance with ASC 805, Business Combinations (“ASC 805”). The Company will consolidate the results of Carbon Appalachia
into its consolidated financial statements from the date of the acquisition forward.
|
(a)
|
Estimated
consideration and preliminary purchase price allocation.
As noted above, the proposed
probable Old Ironsides Buyout qualifies as a business combination under ASC 805. As such,
the Company recognizes the identifiable assets to be acquired and liabilities to be assumed
at their respective fair value as of the date of the acquisition. The Company expects
to pay $58 million for the remaining 73.5% ownership interest in Carbon Appalachia. As
this acquisition is considerable probable and has not yet occurred, the purchase price
allocation is considered preliminary.
|
The table below represents
the preliminary purchase price allocation for the Old Ironsides Buyout:
|
|
Amount
|
|
Fair value of consideration
transferred
|
|
$
|
58,000
|
|
Fair value of previously held interest
|
|
|
12,692
|
|
Fair value of business acquired
|
|
$
|
70,692
|
|
Assets
to be acquired and liabilities to be assumed
|
|
Amount
|
|
Cash acquired
|
|
$
|
12,657
|
|
Accounts receivable:
|
|
|
|
|
Revenue
|
|
|
3,133
|
|
Joint interest billings and other
|
|
|
3,880
|
|
Commodity derivative asset acquired - ST
|
|
|
60
|
|
Inventories
|
|
|
1,230
|
|
Prepaid expense, deposits, and other current assets
|
|
|
515
|
|
Oil and gas properties acquired:
|
|
|
|
|
Proved
|
|
|
108,006
|
|
Unproved
|
|
|
1,819
|
|
Other property and equipment, net
|
|
|
10,842
|
|
Other long term assets
|
|
|
1,109
|
|
Accounts payable and accrued liabilities
|
|
|
(10,970
|
)
|
Firm transportation contract obligation - ST
|
|
|
(3,561
|
)
|
Property and production taxes payable - LT
|
|
|
(2,008
|
)
|
Asset retirement obligations assumed - LT
|
|
|
(4,818
|
)
|
Firm transportation contract obligation - LT
|
|
|
(13,227
|
)
|
Revolver
|
|
|
(37,975
|
)
|
Total net assets acquired
|
|
$
|
70,692
|
|
The assets to be acquired and
liabilities to be assumed are on a preliminary basis and reflect our expectations based on the information currently available
to us. There may be material changes to the preliminary purchase price allocation, but we are unable to estimate the effect of
these changes may be at this time. We expect the purchase price allocation to be finalized during fiscal year 2018.
|
(b)
|
Audited
Historical Statement of Operations.
Reflects the inclusion of Carbon Appalachia’s
audited historical statement of operations for the period ended December 31, 2017, included
elsewhere in this prospectus.
|
|
(c)
|
Unaudited
Historical Statement of Operations.
Reflects
the inclusion of Carbon Appalachia’s unaudited historical statement of operations
for the six months ended June 30, 2018, included within this prospectus, as if the Old
Ironsides Buyout occurred on January 1, 2017.
|
|
(d)
|
Effect
of Old Ironsides Buyout on statement of operations.
Reflects the following adjustments
to the pro forma consolidated statement of operations the proposed probable Old Ironsides
Buyout as if it occurred on January 1 of each respective period:
|
Description
|
|
Adjustment
for
six
months ended
June 30,
2018
|
|
|
Adjustment
for
year
ended
December 31,
2017
|
|
|
Explanation
|
Decrease of General and administrative-related party reimbursement
|
|
$
|
2,149
|
|
|
$
|
1,703
|
|
|
This reimbursement is paid by Carbon Appalachia to Carbon. As Carbon Appalachia
will be a consolidated entity going forward the reimbursement amount has been eliminated.
|
Decrease of Management and operating fee, related party
|
|
$
|
2,149
|
|
|
$
|
1,582
|
|
|
This fee was paid to Carbon, as Carbon Appalachia will now be a consolidated entity this
expense would be eliminated
|
Decrease to loss on Class B issuance
|
|
$
|
-
|
|
|
$
|
924
|
|
|
Elimination of loss on class B share issuance because the holder of the shares will be Carbon
upon completion of the acquisition
|
Decrease of equity investment gain
|
|
$
|
948
|
|
|
$
|
1,090
|
|
|
Removal of equity investment gain on Carbon Appalachia. Carbon Appalachia will be a consolidated
entity, as such, there will be no such gains after the acquisition
|
|
(e)
|
Effect
of Old Ironsides Buyout on balance sheet.
Reflects the following adjustments to the
pro forma consolidated statement of operations to reflect the proposed probable Old Ironsides
Buyout as if it occurred on June 30, 2018:
|
Description
|
|
Amount
|
|
|
Explanation
|
Reduction
of cash
|
|
$
|
58,000
|
|
|
Reduction
of cash based on purchase price. This cash is to come from the offering proceeds.
|
Reduction of
receivable due from related party
|
|
$
|
1,158
|
|
|
Elimination
of related party receivable due from Carbon Appalachia, upon acquisition this would be eliminated in the consolidated balance
sheet
|
Elimination of
investment in affiliate
|
|
$
|
12,692
|
|
|
After
the proposed acquisition, Carbon Appalachia would be a consolidated entity not an equity method investee. This adjustment
eliminates the equity method investment for Carbon Appalachia as of March 31, 2018
|
Reduction of
accounts payable
|
|
$
|
1,158
|
|
|
Reduce
accounts payable by the amount due to Carbon from Carbon Appalachia, which would be eliminated upon acquisition
|
|
(f)
|
Depletion
expense
. Reflects the calculation of the estimated depletion expense based on the
estimated fair value of oil and gas assets be acquired based on the historical depletion
rate of the assets to be acquired in the Old Ironsides Buyout. This estimation is based
on the preliminary fair value of the proved oil and gas assets multiplied by the historical
Carbon Appalachia depletion rate of 5.12%.
|
|
|
Depletable base
|
|
|
Depletion Rate
|
|
|
For the six months ended
June 30, 2018
|
|
|
For the year ended December 31,
2017
|
|
Estimated Depletion
|
|
$
|
108,006
|
|
|
|
5.12
|
%
|
|
$
|
2,764
|
|
|
$
|
5,529
|
|
Remove: actual depletion
|
|
|
|
|
|
|
|
|
|
|
(1,307
|
)
|
|
|
(1,633
|
)
|
Pro forma adjustment
|
|
|
|
|
|
|
|
|
|
$
|
526
|
|
|
$
|
3,895
|
|
|
(g)
|
Income
taxes.
Carbon Appalachia has elected to be treated as a partnership for income tax
purposes. Accordingly, taxable income and losses are reported on the income tax returns
of the Carbon Appalachia’s members, which after the proposed probable acquisition
would be the Company. Due to the limited history of earnings for Carbon Appalachia, we
are unable to estimate the tax effect of the Old Ironsides Buyout on the Company’s
statement of operations. As such no pro forma adjustment has been made related to income
taxes.
|
|
7.
|
Adjustment
for the Cabot Acquisition made by Carbon Appalachia
|
On September 29, 2017, Carbon
Appalachia acquired natural gas producing properties and related facilities as well as transmission pipeline facilities and equipment
located predominantly in the state of West Virginia for a purchase price of $41.3 million, subject to normal purchase adjustments,
with an effective date of April 1, 2017 for oil and gas assets and September 29, 2017, for the corporate entity acquired. Consideration
to fund the Cabot Acquisition was provided by contributions from the Company’s members of $11.0 million and $20.4 million
in funds drawn from its Revolver.
The Cabot Acquisition qualified
as a business combination as defined by ASC 805,
Business Combinations
and, as such, Carbon Appalachia estimated the fair
value of the assets acquired and liabilities assumed as of the closing date of September 29, 2017. As Carbon Appalachia is expected
to become a consolidated entity based on the Old Ironsides Buyout (see note 6) and due to the significance of the Cabot Acquisition,
we have made an adjustment to reflect the Cabot Acquisition within the unaudited consolidated pro forma financial statements.
|
(a)
|
Carbon
Appalachia expensed approximately $660 of transaction and due diligence costs related
to the Cabot Acquisition that were included in general and administrative expenses in
the accompanying consolidated statement of operations for the period ended December 31,
2017. This adjustment reflects the elimination of these costs.
|
|
(b)
|
As
the Cabot Acquisition closed on September 29, 2017, the Carbon Appalachia audited historical
financial statements included the results of operations from the properties acquired
in the Cabot Acquisition from September 30, 2017 to December 31, 2017. Based on the proposed
probable Old Ironsides Buyout (see note 6), Carbon Appalachia would become a consolidated
entity, as such an adjustment should be made as if the Cabot Acquisition occurred on
January 1, 2017.
|
This adjustment reflects the
results of operations related to the Cabot Acquisition Properties for the period from January 1, 2017 to September 29, 2017. These
amounts are derived from audited historical statements of revenues and direct operating expense included within this prospectus.
|
|
Period from January 1, 2017
through September 29,
|
|
(In thousands)
|
|
2017
|
|
|
|
|
|
Revenues:
|
|
|
|
Natural
gas sales
|
|
$
|
27,042
|
|
Oil sales
|
|
|
454
|
|
Marketing
gas sales
|
|
|
12,070
|
|
Storage
and other
|
|
|
363
|
|
Total revenues
|
|
|
39,929
|
|
Direct operating
expenses:
|
|
|
|
|
Lease operating
|
|
|
8,982
|
|
Transportation,
gathering, and compression
|
|
|
9,179
|
|
Marketing
gas purchases
|
|
|
10,389
|
|
Production
and property taxes
|
|
|
4,183
|
|
Total
direct operating expenses
|
|
|
32,733
|
|
Revenues in excess of direct operating
expenses
|
|
$
|
7,196
|
|
|
(c)
|
Interest
expense.
Reflects the additional interest expense that would have been incurred on
the Carbon Appalachia Revolver draw made to finance the Cabot Acquisition as if it occurred
on January 1, 2017. A hypothetical change of 1/8 percent would not have a material effect
on the Company’s financial statements:
|
|
|
Principal
|
|
|
Weighted
Average Rate
|
|
|
Interest
expense for period from January 1 to September 29, 2017
|
|
Interest
expense on Revolver
|
|
$
|
20,400
|
|
|
|
5.34
|
%
|
|
$
|
817
|
|
|
(d)
|
Depletion
expense
. Reflects the calculation of the estimated depletion expense for the assets
to be acquired. This estimation is based on the preliminary fair value of the proved
oil and gas assets multiplied by the historical Carbon Appalachia depletion rate of 5.12%.
This provides a reasonable estimation of the depletion for the assets acquired in the
Cabot Acquisition.
|
|
|
Depletable
base
|
|
|
Depletion
Rate
|
|
|
For
the period from January 1, 2017 to September 29, 2017
|
|
Estimated
Depletion
|
|
$
|
49,920
|
|
|
|
5.12
|
%
|
|
$
|
1,904
|
|
|
(e)
|
Income
taxes.
The Cabot Acquisition was made by Carbon Appalachia and Carbon Appalachia
has elected to be treated as a partnership for income tax purposes. Accordingly, taxable
income and losses are reported on the income tax returns of the Carbon Appalachia’s
members, which after the proposed probable acquisition would be the Company. Due to the
limited history of earnings for Carbon Appalachia, we are unable to estimate the tax
effect of the Cabot Acquisition on the Company’s unaudited pro forma consolidated
statement of operations. As such no pro forma adjustment has been made to income taxes
for the Old Ironsides Buyout.
|
|
8.
|
Adjustment
for Enervest Acquisition made by Carbon Appalachia
|
On August 15, 2017, Carbon
Appalachia acquired natural gas producing properties and related facilities located predominantly in the state of West Virginia
for a purchase price of $21.5 million, subject to normal purchase adjustments, with an effective date of May 1, 2017. Consideration
to fund the Enervest Acquisition was provided by contributions from Carbon Appalachia’s members of $14.0 million and $8.0
million in funds drawn from Carbon Appalachia’s Revolver.
The assets acquired consist
of oil and gas leases and the associated mineral interests, oil and gas wells, a field office building and associated land, vehicles
and other miscellaneous equipment.
This acquisition did not qualify
as a business combination under ASC 805, but qualifies as a business under Rule 11-01 (d) of Regulation S-X. As Carbon Appalachia
is expected to become a consolidated entity based on the Old Ironsides Buyout (see note 6) and due to the significance of the
Enervest Acquisition, we have elected to reflect an adjustment for the Enervest Acquisition within the unaudited consolidated
pro forma financial statements.
|
(a)
|
As
the Enervest Acquisition closed on August 15, 2017, Carbon Appalachia audited historical
statement of operations included the results of operations from the properties acquired
in the Enervest Acquisition from August 16, 2017 to December 31, 2017. Based on the proposed
probable Old Ironsides Buyout (see note 6), Carbon Appalachia would become a consolidated
entity, as such an adjustment should be made as if the Enervest Acquisition occurred
on January 1, 2017.
|
This adjustment reflects the
results of operations related to the properties acquired in the Enervest Acquisition for the period from January 1, 2017 to August
15, 2017. These amounts are derived from unaudited historical records related to the properties acquired in the Enervest Acquisition.
|
|
Period from January 1, 2017
through August 15,
|
|
(In thousands)
|
|
2017
|
|
|
|
|
|
Revenues:
|
|
|
|
Natural
gas sales
|
|
$
|
2,914
|
|
Storage
and other
|
|
|
29
|
|
Total revenues
|
|
|
2,943
|
|
Direct operating
expenses:
|
|
|
|
|
Lease operating
|
|
|
1,367
|
|
Transportation,
gathering, and compression
|
|
|
709
|
|
Production
and property taxes
|
|
|
96
|
|
Total
direct operating expenses
|
|
|
2,172
|
|
|
|
|
|
|
Revenues in excess of direct operating
expenses
|
|
$
|
771
|
|
|
(b)
|
Interest
expense.
Reflects the additional interest expense that would have been incurred on
the Revolver draw made to purchase the Enervest properties as if it occurred on January
1, 2017. A hypothetical change of 1/8 percent would not have a material effect on the
Company’s financial statements:
|
|
|
Principal
|
|
|
Weighted
Average Rate
|
|
|
Interest
expense for period from January 1 to August 15, 2017
|
|
Interest
expense on Revolver
|
|
$
|
8,000
|
|
|
|
5.34
|
%
|
|
$
|
255
|
|
|
(c)
|
Depletion
expense
. Reflects the calculation of the estimated depletion expense for the assets
to be acquired. This estimation is based on the preliminary fair value of the proved
oil and gas assets multiplied by the historical CAC depletion rate of 5.12%. This provides
a reasonable estimation of the depletion expense for the assets acquired in the Enervest
Acquisition.
|
|
|
Depletable
base
|
|
|
Depletion
Rate
|
|
|
For
the period from January 1, 2017 to August 15, 2017
|
|
Estimated
Depletion
|
|
$
|
20,948
|
|
|
|
5.12
|
%
|
|
$
|
667
|
|
|
(d)
|
Income
taxes.
The Envervest Acquisition was made by CAC and CAC has elected to be treated
as a partnership for income tax purposes. Accordingly, taxable income and losses are
reported on the income tax returns of the CAC’s members, which after the proposed
probable acquisition would be the Company. Due to the limited history of earnings for
CAC, we are unable to estimate the tax effect of the Enervest Acquisition on the Company’s
statement of operations. As such no pro forma adjustment has been made related to income
taxes.
|
|
9.
|
Adjustments
for the conversion of Series B Preferred Stock in connection with this Offering
|
As part of the Seneca Acquisition
we issued 50,000 shares of Preferred Stock to Yorktown for $5,000. The Preferred Stock is automatically convertible into shares
of common stock in the Company upon completion of this offering. The Preferred Stock is convertible into shares of common stock
of the Company at a ratio of equal to an amount per share of $100 plus all accrued but unpaid dividends payable in respect thereof
divided by the greater of (i) $8.00 per share or (ii) the price that is 15% less than the price per share of shares sold to the
public in this offering.
|
(a)
|
This
adjustment reflects the reduction of the Preferred Stock and the increase in common stock
at par and additional paid in capital upon conversion of the Preferred Stock into common
stock of the Company using $8.00 per share and the following calculation:
|
|
|
Per
Share Value
|
|
|
Value
of Preferred Stock
|
|
|
|
|
|
Conversion
Rate
|
|
Converted
Shares
|
|
50,000
shares of Preferred Stock
|
|
$
|
100
|
|
|
$
|
5,000
|
|
|
$
|
100
|
|
|
$8.00
per share
|
|
|
625,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pro
forma adjustments
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common stock at par
|
|
$
|
6
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Additional paid-in-capital
|
|
$
|
4,994
|
|
|
(b)
|
Earnings
per share.
These unaudited pro forma financial statements assume 625,000 shares of
Carbon common stock will be issued to Yorktown upon conversion of the Preferred Stock
at completion of this offering, and we have adjusted weighted average shares outstanding
to reflect these additional shares as if the exercise occurred on January 1, 2017.
|
|
10.
|
Adjustments
for the use of proceeds from this Offering
|
Upon completion of this offering,
we will issue and sell shares of common stock and receive net proceeds, after
deducting estimated offering expenses payable by us and underwriting discount of approximately $
million. The Company plans to use approximately $58 million of the proceeds to complete the CAC Acquisition (see note 6), $
million of the proceeds would be used to pay down the Company’s and the
remainder would be used to fund operating expenses.
|
(a)
|
Adjustment
for pay down of $ million on the .
|
|
|
Principal
|
|
|
Weighted
Average Rate
|
|
|
Interest
expense for the year ended December 31, 2017
|
|
Reduction in interest
expense on
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pro
forma adjustment
|
|
|
|
|
|
|
|
|
|
|
|
|
CARBON ENERGY
CORPORATION
Consolidated Balance Sheets
|
|
June 30,
|
|
|
December 31,
|
|
(in thousands)
|
|
2018
|
|
|
2017
|
|
|
|
(Unaudited)
|
|
|
|
|
|
ASSETS
|
|
|
|
|
|
|
|
|
Current assets:
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$
|
4,030
|
|
|
$
|
1,650
|
|
Accounts receivable:
|
|
|
|
|
|
|
|
|
Revenue
|
|
|
4,713
|
|
|
|
2,206
|
|
Trade receivable
|
|
|
1,417
|
|
|
|
-
|
|
Joint interest billings and other
|
|
|
133
|
|
|
|
349
|
|
Insurance receivable (Note 2)
|
|
|
665
|
|
|
|
802
|
|
Due from related parties
|
|
|
1,158
|
|
|
|
2,075
|
|
Commodity derivative asset
|
|
|
-
|
|
|
|
215
|
|
Prepaid expense, deposits and other current assets
|
|
|
1,937
|
|
|
|
783
|
|
Total current assets
|
|
|
14,053
|
|
|
|
8,080
|
|
|
|
|
|
|
|
|
|
|
Property and equipment (Note 4)
|
|
|
|
|
|
|
|
|
Oil and gas properties, full cost method of accounting:
|
|
|
|
|
|
|
|
|
Proved, net
|
|
|
126,510
|
|
|
|
34,178
|
|
Unproved
|
|
|
3,577
|
|
|
|
1,947
|
|
Other property and equipment, net
|
|
|
2,134
|
|
|
|
737
|
|
Total property and equipment, net
|
|
|
132,221
|
|
|
|
36,862
|
|
|
|
|
|
|
|
|
|
|
Investments in affiliates (Note 6)
|
|
|
13,375
|
|
|
|
14,267
|
|
Other long-term assets
|
|
|
2,737
|
|
|
|
800
|
|
Total assets
|
|
$
|
162,386
|
|
|
$
|
60,009
|
|
|
|
|
|
|
|
|
|
|
LIABILITIES AND STOCKHOLDERS’ EQUITY
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current liabilities:
|
|
|
|
|
|
|
|
|
Accounts payable and accrued liabilities (Note 11)
|
|
$
|
15,148
|
|
|
$
|
11,218
|
|
Firm transportation contract obligations (Note 14)
|
|
|
75
|
|
|
|
127
|
|
Commodity derivative liability (Note 13)
|
|
|
4,570
|
|
|
|
-
|
|
Total current liabilities
|
|
|
19,793
|
|
|
|
11,345
|
|
|
|
|
|
|
|
|
|
|
Non-current liabilities:
|
|
|
|
|
|
|
|
|
Firm transportation contract obligations (Note 14)
|
|
|
123
|
|
|
|
134
|
|
Production and property taxes payable
|
|
|
550
|
|
|
|
520
|
|
Warrant liability (Note 12)
|
|
|
-
|
|
|
|
2,017
|
|
Asset retirement obligations (Note 5)
|
|
|
10,831
|
|
|
|
7,357
|
|
Credit facility (Note 7)
|
|
|
23,140
|
|
|
|
22,140
|
|
Long-term debt
|
|
|
78
|
|
|
|
-
|
|
Credit facility-related party (Note 7)
|
|
|
49,900
|
|
|
|
-
|
|
Commodity derivative liability (Note 13)
|
|
|
3,447
|
|
|
|
-
|
|
Total non-current liabilities
|
|
|
88,069
|
|
|
|
32,168
|
|
|
|
|
|
|
|
|
|
|
Commitments (Note 14)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Stockholders’ equity:
|
|
|
|
|
|
|
|
|
Preferred stock, $0.01 par value; authorized 1,000,000
shares, 50,000 shares issued and outstanding at June 30, 2018 and no shares issued and outstanding at December 31, 2017
|
|
|
1
|
|
|
|
-
|
|
Common stock, $0.01 par value; authorized 35,000,000
shares, 7,700,619 and 6,005,633 shares issued and outstanding at June 30, 2018 and December 31, 2017, respectively
|
|
|
77
|
|
|
|
60
|
|
Additional paid-in capital
|
|
|
75,594
|
|
|
|
58,813
|
|
Accumulated deficit
|
|
|
(42,424
|
)
|
|
|
(44,218
|
)
|
Total Carbon stockholders’ equity
|
|
|
33,247
|
|
|
|
14,655
|
|
Non-controlling interests
|
|
|
21,277
|
|
|
|
1,841
|
|
Total stockholders’ equity
|
|
|
54,524
|
|
|
|
16,496
|
|
Total liabilities and stockholders’ equity
|
|
$
|
162,386
|
|
|
$
|
60,009
|
|
See accompanying notes to Consolidated
Financial Statements.
CARBON ENERGY
CORPORATION
Consolidated Statements of Operations
(Unaudited)
|
|
Six Months Ended
June 30,
|
|
(in thousands, except per share amounts)
|
|
2018
|
|
|
2017
|
|
|
|
|
|
|
|
|
Revenue:
|
|
|
|
|
|
|
Natural gas sales
|
|
$
|
7,462
|
|
|
$
|
8,017
|
|
Natural gas liquid sales
|
|
|
713
|
|
|
|
-
|
|
Oil sales
|
|
|
11,074
|
|
|
|
2,192
|
|
Commodity derivative gain (loss)
|
|
|
(6,647
|
)
|
|
|
3,141
|
|
Other income
|
|
|
19
|
|
|
|
20
|
|
Total revenue
|
|
|
12,621
|
|
|
|
13,370
|
|
|
|
|
|
|
|
|
|
|
Expenses:
|
|
|
|
|
|
|
|
|
Lease operating expenses
|
|
|
6,058
|
|
|
|
2,706
|
|
Transportation and gathering costs
|
|
|
2,353
|
|
|
|
1,015
|
|
Production and property taxes
|
|
|
1,048
|
|
|
|
855
|
|
General and administrative
|
|
|
5,491
|
|
|
|
3,494
|
|
General and administrative - related party reimbursement
|
|
|
(2,213
|
)
|
|
|
(300
|
)
|
Depreciation, depletion and amortization
|
|
|
3,471
|
|
|
|
1,234
|
|
Accretion of asset retirement obligations
|
|
|
303
|
|
|
|
155
|
|
Total expenses
|
|
|
16,511
|
|
|
|
9,159
|
|
|
|
|
|
|
|
|
|
|
Operating (loss) income
|
|
|
(3,890
|
)
|
|
|
4,211
|
|
|
|
|
|
|
|
|
|
|
Other income (expense):
|
|
|
|
|
|
|
|
|
Interest expense
|
|
|
(2,203
|
)
|
|
|
(522
|
)
|
Warrant derivative gain
|
|
|
225
|
|
|
|
1,683
|
|
Gain on derecognized equity investment in affiliate – Carbon California
|
|
|
5,390
|
|
|
|
-
|
|
Investment in affiliates
|
|
|
962
|
|
|
|
-
|
|
Total other (expense) income
|
|
|
4,374
|
|
|
|
1,161
|
|
|
|
|
|
|
|
|
|
|
(Loss) income before income taxes
|
|
|
484
|
|
|
|
5,372
|
|
|
|
|
|
|
|
|
|
|
Provision for income taxes
|
|
|
-
|
|
|
|
-
|
|
|
|
|
|
|
|
|
|
|
Net (loss) income before non-controlling interests
|
|
|
484
|
|
|
|
5,372
|
|
|
|
|
|
|
|
|
|
|
Net (loss) income attributable to non-controlling interests
|
|
|
(2,505
|
)
|
|
|
76
|
|
|
|
|
|
|
|
|
|
|
Net (loss) income attributable to controlling interest
|
|
$
|
2,989
|
|
|
$
|
5,296
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) per common share:
|
|
|
|
|
|
|
|
|
Basic
|
|
$
|
0.41
|
|
|
$
|
0.95
|
|
Diluted
|
|
$
|
0.20
|
|
|
$
|
0.56
|
|
Weighted average common shares outstanding:
|
|
|
|
|
|
|
|
|
Basic
|
|
|
7,346
|
|
|
|
5,554
|
|
Diluted
|
|
|
7,662
|
|
|
|
6,458
|
|
See accompanying notes to Consolidated
Financial Statements.
CARBON ENERGY
CORPORATION
Consolidated Statements of Stockholders’
Equity
(Unaudited)
(in thousands)
|
|
Common Stock
|
|
|
Preferred Stock
|
|
|
|
|
|
Non- controlling
|
|
|
Accumulated
|
|
|
Total Stockholders'
|
|
|
|
Shares
|
|
|
Amount
|
|
|
Shares
|
|
|
Amount
|
|
|
APIC
|
|
|
interest
|
|
|
Deficit
|
|
|
Equity
|
|
Balances, December 31, 2017
|
|
|
6,006
|
|
|
|
60
|
|
|
|
-
|
|
|
|
-
|
|
|
|
58,813
|
|
|
|
1,841
|
|
|
|
(44,218
|
)
|
|
|
16,496
|
|
Stock based compensation
|
|
|
39
|
|
|
|
1
|
|
|
|
-
|
|
|
|
-
|
|
|
|
482
|
|
|
|
-
|
|
|
|
-
|
|
|
|
483
|
|
Restricted shares :
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
Vested restricted stock
|
|
|
20
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
Vested performance units
|
|
|
108
|
|
|
|
1
|
|
|
|
-
|
|
|
|
-
|
|
|
|
(1
|
)
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
Preferred share issuance
|
|
|
-
|
|
|
|
-
|
|
|
|
50
|
|
|
|
1
|
|
|
|
4,999
|
|
|
|
-
|
|
|
|
-
|
|
|
|
5,000
|
|
Beneficial conversion feature
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
1,125
|
|
|
|
-
|
|
|
|
(1,125
|
)
|
|
|
-
|
|
Deemed dividend
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
71
|
|
|
|
-
|
|
|
|
(71
|
)
|
|
|
-
|
|
CCC warrant exercise - share issuance
|
|
|
1,528
|
|
|
|
15
|
|
|
|
-
|
|
|
|
-
|
|
|
|
8,311
|
|
|
|
16,466
|
|
|
|
-
|
|
|
|
24,792
|
|
CCC warrant exercise - liability extinguishment
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
1,792
|
|
|
|
-
|
|
|
|
-
|
|
|
|
1,792
|
|
Non-controlling interest contributions, net
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
5,475
|
|
|
|
-
|
|
|
|
5,475
|
|
Step up in basis
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
Net income (loss)
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
(2,505
|
)
|
|
|
2,989
|
|
|
|
484
|
|
Balances, June 30, 2018
|
|
|
7,701
|
|
|
$
|
77
|
|
|
|
50
|
|
|
$
|
1
|
|
|
$
|
75,594
|
|
|
$
|
21,277
|
|
|
$
|
42,424
|
|
|
$
|
54,524
|
|
See accompanying notes to Consolidated
Financial Statements.
CARBON ENERGY
CORPORATION
Consolidated Statements of Cash Flows
(Unaudited)
|
|
Six Months Ended
|
|
|
|
June 30,
|
|
(in thousands)
|
|
2018
|
|
|
2017
|
|
|
|
|
|
|
|
|
Cash flows from operating activities:
|
|
|
|
|
|
|
Net income
|
|
$484
|
|
|
$5,372
|
|
Items not involving cash:
|
|
|
|
|
|
|
|
|
Depreciation, depletion and amortization
|
|
|
3,471
|
|
|
|
1,234
|
|
Accretion of asset retirement obligations
|
|
|
303
|
|
|
|
155
|
|
Unrealized commodity derivative (gain) loss
|
|
|
5,587
|
|
|
|
(3,023
|
)
|
Warrant derivative gain
|
|
|
(225
|
)
|
|
|
(1,683
|
)
|
Stock-based compensation expense
|
|
|
483
|
|
|
|
539
|
|
Equity investment (income)loss
|
|
|
(962
|
)
|
|
|
-
|
|
Gain on derecognized equity investment in affiliate – Carbon
California
|
|
|
(5,390
|
)
|
|
|
-
|
|
Amortization of debt issuance costs
|
|
|
247
|
|
|
|
-
|
|
Other
|
|
|
-
|
|
|
|
(72
|
)
|
Net change in:
|
|
|
|
|
|
|
|
|
Accounts receivable
|
|
|
(353
|
)
|
|
|
1,331
|
|
Prepaid expenses, deposits and other current assets
|
|
|
570
|
|
|
|
(375
|
)
|
Accounts payable, accrued liabilities,
firm transportation contract obligations, and other long-term obligations
|
|
|
(2,600
|
)
|
|
|
(1,142
|
)
|
Net cash provided by operating activities
|
|
|
1,615
|
|
|
|
2,336
|
|
|
|
|
|
|
|
|
|
|
Cash flows from investing activities:
|
|
|
|
|
|
|
|
|
Development and acquisition of properties and equipment
|
|
|
(40,472
|
)
|
|
|
(1,182
|
)
|
Cash received- Carbon California Acquisition
|
|
|
275
|
|
|
|
-
|
|
Other long-term assets
|
|
|
-
|
|
|
|
(15
|
)
|
Investment in affiliates
|
|
|
-
|
|
|
|
(240
|
)
|
Net cash used in investing activities
|
|
|
(40,197
|
)
|
|
|
(1,437
|
)
|
|
|
|
|
|
|
|
|
|
Cash flows from financing activities:
|
|
|
|
|
|
|
|
|
Proceeds from credit facility
|
|
|
31,502
|
|
|
|
600
|
|
Proceeds from preferred shares
|
|
|
5,000
|
|
|
|
-
|
|
Payments on credit facility
|
|
|
(14
|
)
|
|
|
(1,300
|
)
|
Payments of debt issuance costs
|
|
|
(511
|
)
|
|
|
-
|
|
Contributions from non-controlling interests
|
|
|
5,000
|
|
|
|
-
|
|
Distributions to non-controlling interests
|
|
|
(15
|
)
|
|
|
(43
|
)
|
Net cash provided by (used in) financing activities
|
|
|
40,962
|
|
|
|
(743
|
)
|
|
|
|
|
|
|
|
|
|
Net increase in cash and cash equivalents
|
|
|
2,380
|
|
|
|
156
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents, beginning of period
|
|
|
1,650
|
|
|
|
858
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents, end of period
|
|
$
|
4,030
|
|
|
$
|
1,014
|
|
See accompanying notes to Consolidated
Financial Statements.
CARBON ENERGY
CORPORATION
Notes to Consolidated Financial Statements
(Unaudited)
Note 1 – Organization
Carbon Energy Corporation, formerly
known as Carbon Natural Gas Company, and its subsidiaries (referred to herein as “
we
”, “
us
”,
the “
Company
” or “
Carbon”
) is an independent oil and gas company engaged in the
exploration, development and production of oil and natural gas in the United States. The Company’s business is comprised
of the assets and properties of Nytis Exploration (USA) Inc. (“Nytis USA”) and its subsidiary Nytis Exploration Company
LLC (“Nytis LLC”) which conduct the Company’s operations in the Appalachian and Illinois Basins, Carbon California
Operating Company, LLC (“CCOC”) and Carbon California Company, LLC (“Carbon California”) which conduct
the Company’s operations in California, and the Company’s equity investment in Carbon Appalachian Company, LLC (“Carbon
Appalachia”).
Appalachian and Illinois Basin Operations
In the Appalachian and Illinois Basins,
Nytis LLC conducts our operations. The following illustrates this relationship as of June 30, 2018.
Ventura Basin Operations
In California, CCOC conducts our operations.
On February 1, 2018, an entity managed by Yorktown Partners, LLC (“Yorktown”) exercised a warrant it held to purchase
shares of our common stock at an exercise price of $7.20 per share (the “
California Warrant
”), resulting in
the issuance of 1,527,778 shares of our common stock. In exchange, we received Yorktown’s Class A Units of Carbon California
representing approximately 46.96% of the then outstanding Class A Units of Carbon California (a profits interest of approximately
38.59%). After giving effect to the exercise on February 1, 2018, we owned 56.4% of the voting and profits interests of Carbon
California and Prudential Capital Energy Partners, L.P. (“Prudential”) owned 43.6%. On May 1, 2018, Carbon California
closed the Seneca Acquisition. Following the exercise of the California Warrant by Yorktown and the Seneca Acquisition, we own
53.9% of the voting and profits interests, and Prudential owns the remainder of the interest, in Carbon California. As of February
1, 2018, we consolidate Carbon California for financial reporting purposes.
Note 2 – Summary of Significant Accounting Policies
Basis of Presentation
The accompanying unaudited condensed
consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United
States (“GAAP”) for interim financial information. Accordingly, they do not include all the information and footnotes
required by GAAP for complete financial statements. In the opinion of management, the accompanying unaudited condensed consolidated
financial statements include all adjustments (consisting of normal and recurring accruals) considered necessary to present fairly
our financial position as of June 30, 2018, and our results of operations and cash flows for the six months ended June 30, 2018
and 2017. Operating results for the six months ended June 30, 2018, are not necessarily indicative of the results that may be
expected for the full year because of the impact of fluctuations in prices received for oil and natural gas, natural production
declines, the uncertainty of exploration and development drilling results and other factors.
Principles of Consolidation
The unaudited condensed consolidated
financial statements include the accounts of Carbon, CCOC, Carbon California and Nytis USA and its consolidated subsidiary, Nytis
LLC. Carbon owns 100% of Nytis USA and CCOC. Nytis USA owns approximately 99% of Nytis LLC. Carbon owns 53.9% of Carbon California.
Nytis LLC also holds an interest in 64 oil
and gas partnerships. For partnerships where we have a controlling interest, the partnerships are consolidated. We are currently
consolidating, on a pro-rata basis, 47 partnerships. In these instances, we reflect the non-controlling ownership interest in
partnerships and subsidiaries as non-controlling interests on our unaudited consolidated statements of operations and reflect
the non-controlling ownership interests in the net assets of the partnerships as non-controlling interests within stockholders’
equity on our unaudited consolidated balance sheet. All significant intercompany accounts and transactions have been eliminated.
In accordance with established practice in
the oil and gas industry our unaudited condensed consolidated financial statements also include our pro-rata share of assets,
liabilities, income, lease operating costs and general and administrative expenses of the oil and gas partnerships in which we
have a non-controlling interest.
Non-majority owned investments that do not
meet the criteria for pro-rata consolidation are accounted for using the equity method when we have the ability to significantly
influence the operating decisions of the investee. When we do not have the ability to significantly influence the operating decisions
of an investee, the cost method is used. All transactions, if any, with investees have been eliminated in the accompanying unaudited
condensed consolidated financial statements.
Effective February 1, 2018, Yorktown
exercised the California Warrant, which resulted in us acquiring Yorktown’s ownership interest in Carbon California in exchange
for shares of our common stock. On May 1, 2018, Carbon California closed the Seneca Acquisition. Following the exercise of the
California Warrant by Yorktown and the Seneca Acquisition, we own 53.9%, of the voting and profits interests, and Prudential owns
the remainder of the interest, in Carbon California.
Insurance Receivable
Insurance receivable is comprised of
an insurance receivable for the loss of property as a result of wildfires that impacted Carbon California in December 2017. The
Company filed claims with its insurance provider and is in receipt of partial funds associated with the claims as of June 30,
2018. Therefore, the Company has determined the receivable is collectible and is included in insurance receivable on the unaudited
consolidated balance sheets.
Long-term Assets
Long-term assets are comprised of debt
issuance costs, bonds, and fees associated with the registration statement of which this prospectus is a part. We have recorded
debt issuance costs and amortize the balance over the life of the loan. As of June 30, 2018, we have approximately $1.0 million
of deferred financing costs associated with our credit facility and Carbon California’s Senior Revolving Notes within long-term
assets. See note 7. As of June 30, 2018, we have incurred approximately $1.5 million for the outside professional services in
conjunction with the completion of the registration statement for a possible equity raise. We will continue to accumulate deferred
financing costs until the completion of the offering. If the offering is unsuccessful, the amount will be immediately expensed.
Investments in Affiliates
Investments in non-consolidated affiliates
are accounted for under either the cost or equity method of accounting, as appropriate. The cost method of accounting is generally
used for investments in affiliates in which we have has less than 20% of the voting interests of a corporate affiliate or less
than a 3% to 5% interest of a partnership or limited liability company and do not have significant influence. Investments in non-consolidated
affiliates, accounted for using the cost method of accounting, are recorded at cost and impairment assessments for each investment
are made annually to determine if a decline in the fair value of the investment, other than temporary, has occurred. A permanent
impairment is recognized if a decline in the fair value occurs.
If we hold between 20% and 50% of the voting
interest in non-consolidated corporate affiliates or generally greater than a 3% to 5% interest of a partnership or limited liability
company and can exert significant influence or control (e.g., through our influence with a seat on the board of directors or management
of operations), the equity method of accounting is generally used to account for the investment. Equity method investments will
increase or decrease by our share of the affiliate’s profits or losses and such profits or losses are recognized in our
unaudited consolidated statements of operations. For our equity method investment in Carbon Appalachia, we use the hypothetical
liquidation at book value method to recognize our share of the affiliate’s profits or losses. We review equity method investments
for impairment whenever events or changes in circumstances indicate that an other than temporary decline in value has occurred.
Related Party Transactions
Management Reimbursements
In our role as manager of Carbon California
and Carbon Appalachia, we receive management reimbursements. We received approximately $1.5 million for the six months ended June
30, 2018, from Carbon Appalachia, and $50,000 for the one month ended January 31, 2018, from Carbon California. These reimbursements
are included in general and administrative – related party reimbursement on our unaudited consolidated statements of operations.
Effective February 1, 2018, the management reimbursements received from Carbon California are eliminated at consolidation. This
elimination includes $350,000 for the period February 1, 2018, through June 30, 2018.
In addition to the management reimbursements,
approximately $595,000 in general and administrative expenses were reimbursed for the six months ended June 30, 2018, from Carbon
Appalachia, and $14,000 for the one month ended January 31, 2018, by Carbon California. General and administrative expenses reimbursed
by Carbon California and eliminated in consolidation were approximately $42,000 for the period February 1, 2018, through June
30, 2018.
Operating Reimbursements
In our role as operator of Carbon California
and Carbon Appalachia, we receive reimbursements of operating expenses. These expenses are recorded directly to receivable –
due from related party on our unaudited consolidated balance sheets and are therefore not included in our operating expenses on
our unaudited consolidated statements of operations.
Carbon California Credit
Facilities
The credit facilities of Carbon California,
including the Senior Revolving Notes, Carbon California Notes and Carbon California 2018 Subordinated Notes (all defined below),
are held by Prudential or its affiliates. See note 7.
Preferred Stock
In April 2018, we issued 50,000 shares
of Preferred Stock to Yorktown. See note 9.
Old Ironsides Membership Interest
Purchase Agreement
On May 4, 2018, we entered into a Membership
Interest Purchase Agreement with Old Ironsides. See note 6.
Use of Estimates
The preparation of financial statements
in conformity with GAAP requires management to makes estimates and assumptions that affect the amounts reported in the consolidated
financial statements and accompanying notes. There have been no changes in our critical accounting estimates from those that were
disclosed in the 2017 Annual Report on Form 10-K. Actual results could differ from these estimates.
Earnings (Loss) Per Common Share
Basic earnings per common share is
computed by dividing the net income (loss) attributable to common stockholders for the period by the weighted average number of
common shares outstanding during the period. The shares of restricted common stock granted to our officers, directors and employees
are included in the computation of basic net income per share only after the shares become fully vested. Diluted earnings per
common share includes both the vested and unvested shares of restricted stock and the potential dilution that could occur upon
exercise of warrants to acquire common stock computed using the treasury stock method, which assumes that the increase in the
number of shares is reduced by the number of shares which could have been repurchased by us with the proceeds from the exercise
of warrants (which were assumed to have been made at the average market price of the common shares during the reporting period).
We issued 50,000 shares of Series B Convertible Preferred Stock, par value $0.01 per share (the “Preferred Stock”),
and the difference between the carrying amount of the Preferred Stock in equity and the fair value of the Preferred Stock is treated
as a dividend for purposes of calculating earnings per common share. The Preferred Stock deemed dividend could potentially dilute
basic earnings per common share in the future.
The following table sets forth the calculation
of basic and diluted income per share:
|
|
Six months ended
June 30,
|
|
(in thousands except per share amounts)
|
|
2018
|
|
|
2017
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
2,989
|
|
|
$
|
5,296
|
|
Less: warrant derivative gain
|
|
|
(225
|
)
|
|
|
(1,683
|
)
|
Less: beneficial conversion feature
|
|
|
(1,125
|
)
|
|
|
-
|
|
Less: deemed dividend for convertible preferred shares
|
|
|
(71
|
)
|
|
|
-
|
|
Diluted net (loss) income
|
|
|
1,568
|
|
|
|
3,613
|
|
|
|
|
|
|
|
|
|
|
Basic weighted-average common shares outstanding during the period
|
|
|
7,346
|
|
|
|
5,554
|
|
|
|
|
|
|
|
|
|
|
Add dilutive effects of warrants and non-vested shares of restricted
stock
|
|
|
316
|
|
|
|
904
|
|
|
|
|
|
|
|
|
|
|
Diluted weighted-average common shares outstanding during the period
|
|
|
7,662
|
|
|
|
6,458
|
|
|
|
|
|
|
|
|
|
|
Basic net (loss) income per common share
|
|
$
|
0.41
|
|
|
$
|
0.95
|
|
Diluted net (loss) income per common share
|
|
$
|
0.20
|
|
|
$
|
0.56
|
|
Recently Adopted Accounting Pronouncement
In May 2014, the Financial Accounting
Standards Board ("FASB") issued Accounting Standard Update ("ASU") 2014-09,
Revenue from Contracts with
Customers
(Topic 606) (“ASU 2014-09”), which establishes a comprehensive new revenue recognition standard designed
to depict the transfer of goods or services to a customer in an amount that reflects the consideration the entity expects to receive
in exchange for those goods or services. In March 2016, the FASB released certain implementation guidance through ASU 2016-08
(collectively with ASU 2014-09, the "Revenue ASUs") to clarify principal versus agent considerations. The Revenue ASUs
allow for the use of either the full or modified retrospective transition method, and the standard is effective for annual reporting
periods beginning after December 15, 2017 including interim periods within that period, with early adoption permitted for annual
reporting periods beginning after December 15, 2016. We adopted the guidance using the modified retrospective method with the
effective date of January 1, 2018. We did not record a cumulative-effect adjustment to the opening balance of retained earnings
as no adjustment was necessary. The adoption of the Revenue ASUs did not impact net income or cash flows. See note 10 for the
new disclosures required by the Revenue ASUs.
Recently Issued Accounting Pronouncements
In February 2016, the FASB issued ASU
2016-02, “
Leases
(Topic 842)” (“ASU 2016-02”), which establishes a comprehensive new lease standard
designed to increase transparency and comparability among organizations by recognizing lease assets and lease liabilities on the
balance sheet and disclosing key information about leasing arrangements. In transition, lessees and lessors are required to recognize
and measure leases at the beginning of the earliest period presented using a modified retrospective approach. The modified retrospective
approach includes a number of optional practical expedients that entities may elect to apply. An entity that elects to apply the
practical expedients will, in effect, continue to account for leases that commence before the effective date in accordance with
previous GAAP standards. ASU 2016-02 is effective for public companies for fiscal years, and interim periods within those fiscal
years, beginning after December 15, 2018. We are currently evaluating the impact of the adoption of this standard on our financial
statements.
There were various updates recently
issued by the FASB, most of which represented technical corrections to the accounting literature or application to specific industries
and are not expected to a have a material impact on our reported financial position, results of operations, or cash flows.
Note 3 – Acquisitions and Divestitures
Acquisition of Majority Control of Carbon California
Carbon California was formed in 2016 by
us and entities managed by Yorktown and Prudential to acquire producing assets in the Ventura Basin of California.
In connection with the entry into the
limited liability company agreement of Carbon California, we received Class B Units and issued to Yorktown the California Warrant
exercisable for shares of our common stock. The exercise price for the California Warrant was payable exclusively with Class A
Units of Carbon California held by Yorktown and the number of shares of our common stock for which the California Warrant was
exercisable was determined, as of the time of exercise, by dividing (a) the aggregate unreturned capital of Yorktown’s Class
A Units of Carbon California by (b) the exercise price. The California Warrant had a term of seven years and included certain
standard registration rights with respect to the shares of our common stock issuable upon exercise of the California Warrant.
The issuance of the Class B Units and the California Warrant were in contemplation of each other, and
under non-monetary related party guidance, we accounted for the California Warrant, at issuance, based on the fair value of the
California Warrant as of the date of grant (February 15, 2017) and recorded a long-term warrant liability with an associated offset
to Additional Paid in Capital (“APIC”). Future changes to the fair value of the California Warrant are recognized in
earnings. We accounted for the fair value of the Class B Units at their estimated fair value at the date of grant, which became
our investment in Carbon California with an offsetting entry to APIC. Additionally, we accounted for our 17.81% profits interest
in Carbon California as an equity method investment until January 31, 2018.
On February 1, 2018, Yorktown exercised
the California Warrant resulting in the issuance of 1,527,778 shares of our common stock in exchange for Yorktown’s Class
A Units of Carbon California representing approximately 46.96% of the outstanding Class A Units of Carbon California (a profits
interest of approximately 38.59%). After giving effect to the exercise on February 1, 2018, we owned 56.4% of the voting and profits
interests of Carbon California. On May 1, 2018, Carbon California closed the Seneca Acquisition. Following the exercise of the
California Warrant by Yorktown and the Seneca Acquisition, we own 53.9% of the voting and profits interests, and Prudential owns
the remainder of the interest, in Carbon California.
The exercise of the California Warrant and
the acquisition of the additional ownership interest is accounted for as a step acquisition in which we obtained control in accordance
with ASC 805,
Business Combinations
(“ASC 805”) (referred to herein as the “Carbon California Acquisition”).
We recognized 100% of the identifiable assets acquired, liabilities assumed and the non-controlling interest at their respective
fair value as of the date of the acquisition. We exchanged 1,527,778 common shares at a fair value of approximately $8.3 million
($5.45 per share), for 11,000 Class A Units of Carbon California, representing a 38.59% ownership interest in Carbon California.
We followed the fair value method to allocate the consideration transferred to the identifiable net assets acquired and non-controlling
interest (“NCI”) on a preliminary basis as follows:
|
|
Amount
(in thousands)
|
|
Fair value of Carbon common shares transferred as consideration
|
|
$
|
8,326
|
|
Fair value of NCI
|
|
|
16,466
|
|
Fair value of previously held interest
|
|
|
7,244
|
|
Fair value of business acquired
|
|
$
|
32,036
|
|
Assets acquired and liabilities assumed
|
|
Amount
(in thousands)
|
|
Cash
|
|
$
|
275
|
|
Accounts receivable:
|
|
|
|
|
Joint interest billings and other
|
|
|
690
|
|
Receivable - related party
|
|
|
1,610
|
|
Prepaid expense, deposits, and other current assets
|
|
|
1,723
|
|
Oil and gas properties:
|
|
|
|
|
Proved
|
|
|
56,477
|
|
Unproved
|
|
|
1,495
|
|
Other property and equipment, net
|
|
|
877
|
|
Other long-term assets
|
|
|
475
|
|
Accounts payable and accrued liabilities
|
|
|
(6,054
|
)
|
Commodity derivative liability – short-term
|
|
|
(916
|
)
|
Commodity derivative liability – long-term
|
|
|
(1,729
|
)
|
Asset retirement obligations – short-term
|
|
|
(384
|
)
|
Asset retirement obligations – long-term
|
|
|
(2,537
|
)
|
Subordinated Notes, related party, net
|
|
|
(8,874
|
)
|
Senior Revolving Notes, related party
|
|
|
(11,000
|
)
|
Notes payable
|
|
|
(92
|
)
|
Total net assets acquired
|
|
$
|
32,036
|
|
The preliminary fair value of the assets acquired
and liabilities assumed were determined using various valuation techniques, including an income approach. The fair value measurements
were primarily based on significant inputs that are not directly observable in the market and are considered Level 3 under the
fair value measurements and disclosure framework.
On the date of the acquisition, we derecognized
our equity investment in Carbon California and recognized a gain of approximately $5.4 million based on the fair value of our
previously held interest compared to its carrying value.
For assets and liabilities accounted for as
business combinations, including the Carbon California Acquisition, to determine the fair value of the assets acquired, the Company
primarily used the income approach and made market assumptions as to projections of estimated quantities of oil and natural gas
reserves, future production rates, future commodity prices including price differentials as of the date of closing, future operating
and development costs, a market participant weighted average cost of capital, and the condition of vehicles and equipment. The
determination of the fair value of the accounts payable and accrued liabilities assumed required significant judgement, including
estimates relating to production assets.
Seneca Acquisition
In October 2017, Carbon California
signed a Purchase and Sale Agreement to acquire 309 operated and one non-operated oil wells covering approximately 6,800 gross
acres (6,500 net), and fee interests in and to certain lands, situated in the Ventura Basin, together with associated wells, pipelines,
facilities, equipment and other property rights for a purchase price of $43.0 million, subject to customary and standard purchase
price adjustments, from Seneca Resources Corporation (the “
Seneca Acquisition
”). We contributed approximately
$5.0 million to Carbon California to fund our portion of the purchase price, through the $5.0 Preferred Stock issuance, with Prudential
contributing $5.0 million. Carbon California funded the remaining purchase price from cash, increased borrowings under the Senior
Revolving Notes and $3.0 million in proceeds from the issuance of Senior Subordinated Notes. The Seneca Acquisition closed on
May 1, 2018 with an effective date as of October 1, 2017.
Utilizing the assistance of third-party
valuation specialists, we considered various factors in our estimate of fair value of the acquired assets including (i) reserves,
(ii) production rates, (iii) future operating and development costs, (iv) future commodity prices, including price differentials,
(v) future cash flows, and (vi) working conditions and expected lives of vehicles and equipment.
We determined that substantially all
of the fair value of the assets acquired related to proved oil and gas properties and, as such the Seneca Acquisition does not
meet the definition of a business. Therefore, we have accounted for the transaction as an asset acquisition and allocated the
purchase price based on the relative fair value of the assets acquired.
The fair value of the production assets
were determined using the income approach using Level 3 inputs according the ASC 820,
Fair Value
, hierarchy. The fair
value of the other assets was determined using the market approach using Level 3 inputs. The determination of the fair value of
the oil and gas and other property and equipment acquired and accounts payable and accrued liability assumed, required significant
judgement, including estimates relating to the production assets and the other transaction costs. We recorded $639,000 in ARO,
and $330,000 in assumed liabilities in connection with the Seneca Acquisition. We incurred transaction costs related to the Seneca
Acquisition in the amount of $318,000. As this acquisition was determined to be an asset acquisition, transaction costs were capitalized
to oil and gas properties- proved, net on the balance sheet. Below is the summary of the assets acquired (in thousands):
Identifiable assets acquired:
|
|
|
|
Assets:
|
|
|
|
Proved oil and gas properties
|
|
$
|
37,386
|
|
Unproved oil and gas properties
|
|
|
100
|
|
Other property and equipment
|
|
|
545
|
|
Intangible assets
|
|
|
300
|
|
Total identified assets
|
|
$
|
38,331
|
|
Consolidation of Carbon California
and Seneca Acquisition Unaudited Pro Forma Results of Operations
Below are unaudited consolidated results
of operations for the six months ended June 30, 2018 and 2017, as though the Carbon California Acquisition and the Seneca Acquisition
had been completed as of January 1, 2017. The Carbon California Acquisition closed February 1, 2018, and the Seneca Acquisition
closed May 1, 2018, and accordingly, our unaudited consolidated statements of operations for the six months ended June 30, 2018,
includes Carbon California’s results of operations for the quarter, and the Seneca Acquisition results of operations for
the period May 1, 2018 through June 30, 2018.
|
|
Unaudited Pro Forma Consolidated Results
|
|
|
|
For Six Months Ended
June 30,
|
|
(in thousands, except per share amounts)
|
|
2018
|
|
|
2017
|
|
Revenue
|
|
$
|
20,283
|
|
|
$
|
27,054
|
|
Net (loss) income before non-controlling interests
|
|
|
4,256
|
|
|
|
8,704
|
|
Net (loss) income attributable to non-controlling interests
|
|
|
(2,504
|
)
|
|
|
76
|
|
Net (loss) income attributable to controlling interests
|
|
$
|
7,739
|
|
|
$
|
8,628
|
|
Net income per share (basic)
|
|
$
|
1.01
|
|
|
$
|
1.54
|
|
Net income per share (diluted)
|
|
$
|
0.84
|
|
|
$
|
1.18
|
|
Note 4 – Property and Equipment
Net property and equipment as of June 30, 2018 and December
31, 2017, consists of the following:
(in thousands)
|
|
June 30,
2018
|
|
|
December 31,
2017
|
|
|
|
|
|
|
|
|
Oil and gas properties:
|
|
|
|
|
|
|
Proved oil and gas properties
|
|
$
|
211,602
|
|
|
$
|
114,893
|
|
Unproved properties not subject to depletion
|
|
|
3,577
|
|
|
|
1,947
|
|
Accumulated depreciation, depletion, amortization and impairment
|
|
|
(85,092
|
)
|
|
|
(80,715
|
)
|
Net oil and gas properties
|
|
|
130,087
|
|
|
|
36,125
|
|
|
|
|
|
|
|
|
|
|
Furniture and fixtures, computer hardware and software, and other equipment
|
|
|
3,631
|
|
|
|
1,758
|
|
Accumulated depreciation and amortization
|
|
|
(1,497
|
)
|
|
|
(1,021
|
)
|
Net other property and equipment
|
|
|
2,134
|
|
|
|
737
|
|
|
|
|
|
|
|
|
|
|
Total net property and equipment
|
|
$
|
132,221
|
|
|
$
|
36,862
|
|
We had approximately $3.5 million and
$1.9 million, at June 30, 2018 and December 31, 2017, respectively, of unproved oil and gas properties not subject to depletion.
At June 30, 2018 and December 31, 2017, our unproved properties consist principally of leasehold acquisition costs in the following
areas:
(in thousands)
|
|
June 30,
2018
|
|
|
December 31,
2017
|
|
|
|
|
|
|
|
|
Ventura Basin
|
|
$
|
1,595
|
|
|
$
|
-
|
|
Illinois Basin:
|
|
|
|
|
|
|
|
|
Indiana
|
|
|
432
|
|
|
|
432
|
|
Illinois
|
|
|
136
|
|
|
|
136
|
|
Appalachian Basin:
|
|
|
|
|
|
|
|
|
Kentucky
|
|
|
919
|
|
|
|
915
|
|
Ohio
|
|
|
66
|
|
|
|
66
|
|
West Virginia
|
|
|
429
|
|
|
|
398
|
|
|
|
|
|
|
|
|
|
|
Total unproved properties not subject to depletion
|
|
$
|
3,577
|
|
|
$
|
1,947
|
|
During the six months ended June 30,
2018 and 2017, there were no expiring leasehold costs that were reclassified into proved property. The excluded properties are
assessed for impairment at least annually. Subject to industry conditions, evaluations of most of these properties and the inclusion
of their costs in amortized capital costs is expected to be completed within five years.
We capitalized overhead applicable
to acquisition, development and exploration activities of approximately $190,000 and $131,000 for the six months ended June 30,
2018 and 2017, respectively.
Depletion expense related to oil and
gas properties for the six months ended June 30, 2018 and 2017, was approximately $3.1 million and $1.1 million, or $0.80 and
$0.41 per Mcfe, respectively.
Note 5 – Asset Retirement Obligation
Our asset retirement obligations (“ARO”)
relate to future costs associated with the plugging and abandonment of oil and gas wells, removal of equipment and facilities
from leased acreage and returning such land to its original condition. The fair value of a liability for an ARO is recorded in
the period in which it is incurred or acquired, and the cost of such liability is recorded as an increase in the carrying amount
of the related long-lived asset by the same amount. The liability is accreted each period and the capitalized cost is depleted
on a units-of-production basis as part of the full cost pool. Revisions to estimated AROs result in adjustments to the related
capitalized asset and corresponding liability.
The estimated ARO liability is based on estimated
economic lives, estimates as to the cost to abandon the wells in the future, and federal and state regulatory requirements. The
liability is discounted using a credit-adjusted risk-free rate estimated at the time the liability is incurred or acquired or
increased as a result of a reassessment of expected cash flows and assumptions inherent in the estimation of the liability. Upward
revisions to the liability could occur due to changes in estimated abandonment costs or well economic lives, or if federal or
state regulators enact new requirements regarding the abandonment of wells. AROs are valued utilizing Level 3 fair value measurement
inputs (see note 12).
The following table is a reconciliation of
the ARO:
|
|
Six Months Ended
June 30,
|
|
(in thousands)
|
|
2018
|
|
|
2017
|
|
Balance at beginning of period
|
|
$
|
7,737
|
|
|
$
|
5,120
|
|
Accretion expense
|
|
|
303
|
|
|
|
155
|
|
Additions from Carbon California Company, LLC
|
|
|
2,921
|
|
|
|
-
|
|
Additions from Seneca Acquisition
|
|
|
639
|
|
|
|
-
|
|
Additions during period
|
|
|
-
|
|
|
|
5
|
|
|
|
|
11,600
|
|
|
|
5,280
|
|
Less: ARO recognized as a current liability
|
|
|
(769
|
)
|
|
|
(183
|
)
|
|
|
|
|
|
|
|
|
|
Balance at end of period
|
|
$
|
10,831
|
|
|
$
|
5,097
|
|
Note 6 – Investments in Affiliates
Carbon California
Carbon California was formed in 2016 by us
and entities managed by Yorktown and Prudential to acquire producing assets in the Ventura Basin in California. On February 15,
2017, we, Yorktown and Prudential entered into a limited liability company agreement (the “Carbon California LLC Agreement”)
of Carbon California, a Delaware limited liability company.
Prior to February 1, 2018, we held
17.81% of the voting and profits interests, Yorktown held 38.59% of the voting and profits interests and Prudential held 43.59%
of the voting and profits interests in Carbon California. On February 1, 2018, Yorktown exercised the California Warrant, pursuant
to which Yorktown obtained additional shares of common stock in us in exchange for the transfer and assignment by Yorktown of
all its rights in Carbon California. Following the exercise of the California Warrant by Yorktown, we owned 56.4% of the voting
and profits interests, and Prudential held the remainder of the interests, in Carbon California. On May 1, 2018, Carbon California
closed the Seneca Acquisition. Following the exercise of the California Warrant by Yorktown and the Seneca Acquisition, we own
53.9% of the voting and profits interests, and Prudential owns the remainder of the interests, in Carbon California. We consolidate
Carbon California for financial reporting purposes.
On February 15, 2017, Carbon California
(i) issued and sold Class A Units to Yorktown and Prudential for an aggregate cash consideration of $22.0 million, (ii) entered
into a Note Purchase Agreement (the “Note Purchase Agreement”) with Prudential Legacy Insurance Company of New Jersey
and Prudential Insurance Company of America for the issuance and sale of up to $25.0 million of Senior Secured Revolving Notes
(the “Senior Revolving Notes”) due February 15, 2022 and (iii) entered into a Securities Purchase Agreement (the “Securities
Purchase Agreement”) with Prudential for the issuance and sale of $10.0 million of Senior Subordinated Notes (the “Subordinated
Notes”) due February 15, 2024. We are not a guarantor of the Senior Revolving Notes or the Subordinate Notes.
The closing of the Note Purchase Agreement
and the Securities Purchase Agreement on February 15, 2017, resulted in the sale and issuance by Carbon California of (i) Senior
Revolving Notes in the principal amount of $10.0 million and (ii) Subordinated Notes in the original principal amount of $10.0
million. The maximum principal amount available under the Senior Revolving Notes is based upon the borrowing base attributable
to Carbon California’s proved oil and gas reserves which is to be determined at least semi-annually. As of June 30, 2018,
the borrowing base was $41.0 million. There was $38.5 million of indebtedness outstanding thereunder as of June 30, 2018.
Net proceeds from the offering transaction
were used by Carbon California to complete the acquisitions of oil and gas assets in the Ventura Basin of California, which acquisitions
also closed on February 15, 2017. The remainder of the net proceeds were used to fund field development projects, to fund a future
complementary acquisition and for general working capital purposes of Carbon California.
For the period February 15, 2017 (inception)
through January 31, 2018, based on our 17.8% interest in Carbon California, our ability to appoint a member to the board of directors
and our role of manager of Carbon California, we accounted for our investment in Carbon California under the equity method of
accounting as we believed we exerted significant influence. We used the Hypothetical Liquidation at Book Value Method (“HLBV”)
to determine our share of profits or losses in Carbon California and adjusted the carrying value of our investment accordingly.
The HLBV is a balance-sheet approach that calculates the amount each member of Carbon California would have received if Carbon
California were liquidated at book value at the end of each measurement period. The change in the allocated amount to each member
during the period represents the income or loss allocated to that member. In the event of liquidation of Carbon California, to
the extent that Carbon California has net income, available proceeds are first distributed to members holding Class B units and
any remaining proceeds are then distributed to members holding Class A Units. For the period February 15, 2017 (inception) through
January 31, 2018, Carbon California incurred a net loss of which our share (as a holder of Class B Units for that period) was
zero.
In connection with our entry into the Carbon
California LLC Agreement, we received the aforementioned Class B Units and issued to Yorktown the California Warrant. The exercise
price for the California Warrant was payable exclusively with Class A Units of Carbon California held by Yorktown and the number
of shares of our common stock for which the California Warrant was exercisable was determined, as of the time of exercise, by
dividing (a) the aggregate unreturned capital of Yorktown’s Class A Units of Carbon California by (b) the exercise price.
The California Warrant had a term of seven years and included certain standard registration rights with respect to the shares
of our common stock issuable upon exercise of the California Warrant. On February 1, 2018, Yorktown exercised the California Warrant.
As a result of the warrant exercise, Carbon holds 11,000 Class A Units of Carbon California and all of the Class B units, resulting
in an aggregate Sharing Percentage of 56.4%. Effective February 1, 2018, the Company consolidates Carbon California in its unaudited
condensed consolidated financial statements.
On May 1, 2018, Carbon California entered
into an agreement with Prudential Capital Energy Partners, L.P. for the issuance and sale of $3.0 million of unsecured notes due
February 15, 2024, bearing interest of 12% per annum (the “Carbon California 2018 Subordinated Notes”). Prudential
received 585 Class A Units, representing an approximately 2% additional sharing percentage, for the issuance of the Carbon California
2018 Subordinated Notes. Carbon California valued this unit issuance based on the relative fair value by valuing the units at
$1,000 per unit and aggregating the amount with the outstanding Carbon California 2018 Subordinated Notes of $3.0 million. The
Company then allocated the non-cash value of the units of approximately $490,000, which was recorded as a discount to the Carbon
California 2018 Subordinated Notes. As of June 30, 2018, Carbon California had an outstanding discount of $482,000 associated
with these notes, which is presented net of the Carbon California 2018 Subordinated Notes within Credit facility-related party
on the unaudited consolidated balance sheets. As of June 30, 2018, the Company has $58,000 of deferred costs offsetting the Carbon
California 2018 Subordinated Notes.
Carbon Appalachia
Carbon Appalachia was formed in 2016 by us,
Yorktown and entities managed by Old Ironsides Energy LLC (“Old Ironsides”) to acquire producing assets in the Appalachian
Basin in Kentucky, Tennessee, Virginia and West Virginia.
Outlined below is a summary of (i)
our contributions, (ii) our resulting percentage of Class A unit ownership and iii) our overall resulting Sharing Percentage of
Carbon Appalachia after giving effect to the Class C Unit ownership. Holders of units within each class of units participate in
profit or losses and distributions according to their proportionate share of each class of units (“Sharing Percentage”).
Each contribution and its use are described in summary following the table.
Timing
|
|
Capital
Contribution
|
|
Resulting Class A
Units (%)
|
|
|
Resulting
Sharing %
|
|
April 2017
|
|
$0.24 million
|
|
|
2.00
|
%
|
|
|
2.98
|
%
|
August 2017
|
|
$3.71 million
|
|
|
15.20
|
%
|
|
|
16.04
|
%
|
September 2017
|
|
$2.92 million
|
|
|
18.55
|
%
|
|
|
19.37
|
%
|
November 2017
|
|
Warrant exercise
|
|
|
26.50
|
%
|
|
|
27.24
|
%
|
On April 3, 2017, we, Yorktown and
Old Ironsides, entered in to a limited liability company agreement (the “Carbon Appalachia LLC Agreement”), with an
initial equity commitment of $100.0 million, of which $37.0 million has been contributed as of June 30, 2018.
Pursuant to the Carbon Appalachia LLC
Agreement, we acquired a 2.0% interest in Carbon Appalachia for $240,000 of Class A Units associated with our initial equity commitment
of $2.0 million. We also have the ability to earn up to an additional 14.7% of Carbon Appalachia distributions (represented by
Class B Units) after certain return thresholds to the holders of Class A Units are met. The Class B Units were acquired for no
cash consideration.
In addition, we acquired a 1.0% interest
represented by Class C Units which were obtained in connection with the contribution to Carbon Appalachia of a portion of our
working interest in undeveloped properties in Tennessee. If Carbon Appalachia agrees to drill horizontal Chattanooga Shale wells
on these properties, it will pay 100% of the cost of drilling and completion of the first 20 wells to earn a 75% working interest
in such properties. We, through our subsidiary, Nytis LLC, will retain a 25% working interest in the properties. There was no
activity associated with these properties in 2017 nor during the first six months of 2018.
In 2017, Carbon Appalachia Enterprises,
LLC, formerly known as Carbon Tennessee Company, LLC (“CAE”), a subsidiary of Carbon Appalachia, entered into a 4-year
$100.0 million (with $1.5 million sublimit for letters of credit) senior secured asset-based revolving credit facility with LegacyTexas
Bank with an initial borrowing base of $10.0 million (the “CAE Credit Facility”).
The CAE Credit Facility borrowing base
was adjusted for acquisitions completed in 2017. Most recently, on April 30, 2018, the CAE Credit Facility was amended, which
increased the borrowing base to $70.0 million with redeterminations as of April 1 and October 1 each year. As of June 30, 2018,
there was approximately $38.0 million outstanding under the CAE Credit Facility.
The CAE Credit Facility is guaranteed
by each of CAE’s existing and future direct or indirect subsidiaries (subject to certain exceptions). CAE’s obligations
and those of CAE’s subsidiary guarantors under the CAE Credit Facility are secured by essentially all of CAE’s tangible
and intangible personal and real property (subject to certain exclusions).
Interest is payable quarterly and accrues
on borrowings under the CAE Credit Facility at a rate per annum equal to either (i) the base rate plus an applicable margin between
0.00% and 1.00% or (ii) the Adjusted LIBOR rate plus an applicable margin between 3.00% and 4.00% at our option. The actual margin
percentage is dependent on the CAE Credit Facility utilization percentage. CAE is obligated to pay certain fees and expenses in
connection with the CAE Credit Facility, including a commitment fee for any unused amounts of 0.50%.
The CAE Credit Facility contains affirmative
and negative covenants that, among other things, limit CAE’s ability to (i) incur additional debt; (ii) incur additional
liens; (iii) sell, transfer or dispose of assets; (iv) merge or consolidate, wind-up, dissolve or liquidate; (v) make dividends
and distributions on, or repurchases of, equity; (vi) make certain investments; (vii) enter into certain transactions with our
affiliates; (viii) enter into sales-leaseback transactions; (ix) make optional or voluntary payments of debt; (x) change the nature
of our business; (xi) change our fiscal year to make changes to the accounting treatment or reporting practices; (xii) amend constituent
documents; and (xiii) enter into certain hedging transactions.
The affirmative and negative covenants
are subject to various exceptions, including basket amounts and acceptable transaction levels. In addition, the CAE Credit Facility
requires CAE’s compliance, on a consolidated basis, with (i) a maximum Debt/EBITDA ratio of 3.5 to 1.0 and (ii) a minimum
current ratio of 1.0 to 1.0.
CAE may at any time repay the loans under
the CAE Credit Facility, in whole or in part, without penalty. CAE must pay down borrowings under the CAE Credit Facility or provide
mortgages of additional oil and natural gas properties to the extent that outstanding loans and letters of credit exceed the borrowing
base.
In connection with our entry into the Carbon
Appalachia LLC Agreement, and Carbon Appalachia engaging in certain transactions during 2017, we received the aforementioned Class
B Units and issued to Yorktown a warrant to purchase approximately 408,000 shares of our common stock at an exercise price of
$7.20 per share (the “Appalachia Warrant”). The Appalachia Warrant was payable exclusively with Class A Units of Carbon
Appalachia held by Yorktown and the number of shares of our common stock for which the Appalachia Warrant was exercisable was
determined, as of the time of exercise, by dividing (a) the aggregate unreturned capital of Yorktown’s Class A Units of
Carbon Appalachia plus a required 10% internal rate of return by (b) the exercise price.
On November 1, 2017, Yorktown exercised the
Appalachia Warrant, resulting in the issuance of approximately 432,000 shares of our common stock in exchange for Class A Units
representing approximately 7.95% of then outstanding Class A Units of Carbon Appalachia. We accounted for the exercise through
extinguishment of the warrant liability associated with the Appalachia Warrant of approximately $1.9 million and the receipt of
Yorktown’s Class A Units as an increase to investment in affiliates in the amount of approximately $2.9 million. After giving
effect to the exercise, we own 26.5% of Carbon Appalachia’s outstanding Class A Units along with 100% of its Class C Units.
The issuance of the Class B Units and the
Appalachia Warrant were in contemplation of each other, and under non-monetary related party guidance, we accounted for the Appalachia
Warrant, at issuance, based on the fair value of the Appalachia Warrant as of the date of grant (April 3, 2017) and recorded a
warrant liability with an associated offset to APIC. Future changes to the fair value of the Appalachia Warrant are recognized
in earnings. We accounted for the fair value of the Class B Units at their estimated fair value at the date of grant, which became
our investment in Carbon Appalachia with an offsetting entry to APIC.
As of the grant date of the Appalachia Warrant,
we estimated that the fair market value of the Appalachia Warrant was approximately $1.3 million, and the fair value of the Class
B Units was approximately $924,000. The difference in the fair value of the Appalachia Warrant from the grant date though its
exercise on November 1, 2017, was approximately $619,000 and was recognized in warrant derivative gain in our consolidated statements
of operations for the year ended December 31, 2017.
Based on our 27.24% combined Class
A and Class C interest (and our ability as of June 30, 2018 to earn up to an additional 14.7%) in Carbon Appalachia, our ability
to appoint a member to the board of directors and our role of manager of Carbon Appalachia, we are accounting for our investment
in Carbon Appalachia under the equity method of accounting as we believe we exert significant influence. We use the HLBV to determine
our share of profits or losses in Carbon Appalachia and adjust the carrying value of our investment accordingly. Our investment
in Carbon Appalachia is represented by our Class A and C interests, which we acquired by contributing approximately $6.9 million
in cash and unevaluated property. In the event of liquidation of Carbon Appalachia, available proceeds are first distributed to
members holding Class C Units then to holders of Class A Units until their contributed capital is recovered with an internal rate
of return of 10%. Any additional distributions would then be shared between holders of Class A, Class B and Class C Units. For
the six months ended June 30, 2018, Carbon Appalachia earned net income, of which our share is approximately $917,000. The ability
of Carbon Appalachia to make distributions to its owners, including us, is dependent upon the terms of its credit facility, which
currently prohibit distributions unless agreed to by the lender.
As of June 30, 2018, Carbon Appalachia
is in compliance with all CAE Credit Facility covenants.
The following table sets forth selected
historical unaudited consolidated statements of operations and production data for Carbon Appalachia.
(in thousands)
|
|
As of
June 30,
2018
|
|
Current assets
|
|
$
|
21,475
|
|
Total oil and gas properties, net
|
|
$
|
83,541
|
|
Total other property and equipment, net
|
|
$
|
10,842
|
|
Other long-term assets
|
|
$
|
1,109
|
|
Current liabilities
|
|
$
|
14,531
|
|
Non-current liabilities
|
|
$
|
58,028
|
|
Total members’ equity
|
|
$
|
44,408
|
|
|
|
Six months
ended
|
|
|
April 3,
2017 to
|
|
(in thousands)
|
|
June 30,
2018
|
|
|
June 30,
2017
|
|
Revenues
|
|
$
|
44,422
|
|
|
$
|
1,557
|
|
Operating expenses
|
|
|
39,756
|
|
|
|
1,757
|
|
Income from operations
|
|
|
4,666
|
|
|
|
(200
|
)
|
Net income
|
|
$
|
3,479
|
|
|
$
|
(329
|
)
|
Old Ironsides Membership Interest Purchase Agreement
On May 4, 2018, we entered into a Membership
Interest Purchase Agreement (the “MIPA”) with Old Ironsides. Old Ironsides owns 73.5%, and we own the remaining 26.5%,
of the issued and outstanding Class A Units of Carbon Appalachia. We also own all of the Class B and Class C units of Carbon Appalachia.
Pursuant to the MIPA, we may acquire all of Old Ironsides’ membership interests of Carbon Appalachia. Following the
closing of the transaction, we would own 100% of the issued and outstanding ownership interests in Carbon Appalachia, and Carbon
Appalachia will become a wholly-owned subsidiary of ours.
Subject to the terms and conditions
of the MIPA, we will pay Old Ironsides approximately $58.0 million at closing, subject to adjustment, in accordance with the MIPA.
We intend to fund the acquisition through the issuance of additional equity, for which we have filed the registration statement
of which this prospectus is a part.
The MIPA contains termination rights
for us and Old Ironsides, including, among others, if the closing of the transaction has not occurred on or before October 15,
2018. The MIPA may also be terminated by mutual written consent of us and Old Ironsides.
Investments in Affiliates
During the six months ended June 30,
2018 and 2017, we recorded total equity method income of approximately $952,000 and $7,000, respectively. Additionally, on February
1, 2018, as a result of the Carbon California Acquisition, we derecognized our equity investment in Carbon California and recognized
a gain of approximately $5.4 million based on the fair value of our previously held interest compared to its carrying value.
Note 7 – Credit Facilities
Our Credit Facility
In 2016, we entered into a 4-year $100.0
million senior secured asset-based revolving credit facility with LegacyTexas Bank. LegacyTexas Bank is the initial lender and
acts as administrative agent.
The credit facility has a maximum availability
of $100.0 million (with a $500,000 sublimit for letters of credit), which availability is subject to the amount of the borrowing
base. The initial borrowing base established under the credit facility was $17.0 million. The borrowing base is subject to semi-annual
redeterminations in March and September. On March 30, 2018, the borrowing base was increased from $23.0 to $25.0 million, of which
approximately $23.1 million was outstanding as of June 30, 2018. Our effective interest rate as of June 30, 2018 was 5.54%. In
July 2018, the borrowing base was increased from $25.0 million to $28.0 million.
The credit facility is guaranteed by each
of our existing and future subsidiaries (subject to certain exceptions). Our obligations and those of our subsidiary guarantors
under the credit facility are secured by essentially all of our tangible and intangible personal and real property (subject to
certain exclusions).
Interest is payable quarterly and accrues
on borrowings under the credit facility at a rate per annum equal to either (i) the base rate plus an applicable margin between
0.50% and 1.50% or (ii) the Adjusted LIBOR rate plus an applicable margin between 3.50% and 4.50% at our option. The actual margin
percentage is dependent on the credit facility utilization percentage. We are obligated to pay certain fees and expenses in connection
with the credit facility, including a commitment fee for any unused amounts of 0.50%.
The credit facility contains affirmative
and negative covenants that, among other things, limit our ability to (i) incur additional debt; (ii) incur additional liens;
(iii) sell, transfer or dispose of assets; (iv) merge or consolidate, wind-up, dissolve or liquidate; (v) make dividends and distributions
on, or repurchases of, equity; (vi) make certain investments; (vii) enter into certain transactions with our affiliates; (viii)
enter into sales-leaseback transactions; (ix) make optional or voluntary payments of debt; (x) change the nature of our business;
(xi) change our fiscal year to make changes to the accounting treatment or reporting practices; (xii) amend constituent documents;
and (xiii) enter into certain hedging transactions.
The affirmative and negative covenants
are subject to various exceptions, including basket amounts and acceptable transaction levels. In addition, the credit facility
requires our compliance, on a consolidated basis, with (i) a maximum Debt/EBITDA ratio of 3.5 to 1.0 and (ii) a minimum current
ratio of 1.0 to 1.0.
On March 27, 2018, the credit facility
was amended to revise the calculation of the Leverage Ratio from a Debt/EBITDA ratio to a Net Debt/Adjusted EBITDA ratio, reset
the testing period used in the determination of Adjusted EBITDA, eliminated the minimum current ratio and substituted alternative
liquidity requirements, including maximum allowed current liabilities in relation to current assets, a minimum cash balance requirement
of $750,000 and maximum aged trade payable requirements. As of June 30, 2018, we were in compliance with our financial covenants.
We may at any time repay the loans under
the credit facility, in whole or in part, without penalty. We must pay down borrowings under the credit facility or provide mortgages
of additional oil and natural gas properties to the extent that outstanding loan and letters of credit exceed the borrowing base.
As required under the terms of the credit
facility, we entered into derivative contracts with fixed pricing for a certain percentage of our production. We are a party to
an ISDA Master Agreement with BP Energy Company that established standard terms for the derivative contracts and an inter-creditor
agreement with LegacyTexas Bank and BP Energy Company whereby any credit exposure related to the derivative contracts entered
into by the Company and BP Energy Company is secured by the collateral and backed by the guarantees supporting the credit facility.
Carbon California – Credit
Facilities
Effective as of February 1, 2018, our
ownership in Carbon California increased to 56.4% due to the exercise of the California Warrant. As a result of this transaction,
we consolidate Carbon California for financial reporting purposes.
On May 1, 2018, Carbon California closed
the Seneca Acquisition. Following the exercise of the California Warrant by Yorktown and the Seneca Acquisition, we own 53.92%
of the voting and profits interests, and Prudential owns the remainder of the interests, in Carbon California.
The table below summarizes the notes
payable outstanding for Carbon California as of June 30, 2018 (in thousands):
Senior Revolving Notes, related party, due February 15, 2022
|
|
$
|
38,500
|
|
Subordinated Notes, related party, due February 15, 2024
|
|
|
13,000
|
|
Long-term debt
|
|
|
78
|
|
Total gross notes payable
|
|
|
51,578
|
|
Less: Deferred notes costs
|
|
|
(232
|
)
|
Less: Notes discount
|
|
|
(1,368
|
)
|
Total net notes payable
|
|
$
|
49,978
|
|
Carbon California- Senior Revolving
Notes, Related Party
On February 15, 2017, Carbon California
entered into the Note Purchase Agreement with Prudential Legacy Insurance Company of New Jersey and Prudential Insurance Company
of America for the issuance and sale of the Senior Revolving Notes due February 15, 2022. We are not a guarantor of the Senior
Revolving Notes. The closing of the Note Purchase Agreement on February 15, 2017, resulted in the sale and issuance by Carbon
California of Senior Revolving Notes in the principal amount of $10.0 million. The maximum principal amount available under the
Senior Revolving Notes is based upon the borrowing base attributable to Carbon California’s proved oil and gas reserves
which is to be determined at least semi-annually. As of June 30, 2018, the borrowing base was $41.0 million, of which $38.5 million
was outstanding.
Carbon California may elect to incur
interest at either (i) 5.0% plus the London interbank offered rate (“LIBOR”) or (ii) 4.00% plus Prime Rate (which
is defined as the interest rate published daily by JPMorgan Chase Bank, N.A.). As of June 30, 2018, the effective borrowing rate
for the Senior Revolving Notes was 8.29%. In addition, the Senior Revolving Notes include a commitment fee for any unused amounts
at 0.50% as well as an annual administrative fee of $75,000, payable on February 15 each year.
The Senior Revolving Notes are secured
by all the assets of Carbon California. The Senior Revolving Notes require Carbon California, as of January 1 and July 1 of each
year, to hedge its anticipate proved developed products production at such time for year one, two and three at a rate of 75%,
65% and 50%, respectively. Carbon California may make principal payments in minimum installments of $500,000. Distributions to
equity members are generally restricted.
Carbon California incurred fees directly
associated with the issuance of the Senior Revolving Notes and amortizes these fees over the life of the Senior Revolving Notes.
The current portion of these fees are included in prepaid expense and deposits and the long-term portion is included in other
long-term assets for a combined value of $944,000. During the six months ended June 30, 2018 and 2017, Carbon California amortized
fees of $77,000 and $43,000, respectively.
The Note Purchase Agreement requires
Carbon California to maintain certain financial and non-financial covenants which include the following ratios: total leverage
ratio, senior leverage ratio, interest coverage ratio, current ratio, and other qualitative covenants as defined in the Note Purchase
Agreement. As of June 30, 2018, Carbon California was in compliance with its financial covenants.
Carbon California Subordinated
Notes
On February 15, 2017, Carbon California
entered into the Securities Purchase Agreement with Prudential Capital Energy Partners, L.P. for the issuance and sale of the
Subordinated Notes due February 15, 2024, bearing interest of 12% per annum. We are not a guarantor of the Subordinated Notes.
The closing of the Securities Purchase Agreement on February 15, 2017, resulted in the sale and issuance by Carbon California
of Subordinated Notes in the original principal amount of $10.0 million.
Prudential received an additional 1,425
Class A Units, representing 5% of total sharing percentage, for the issuance of the Subordinated Notes. Carbon California valued
this unit issuance based on the relative fair value by valuing the units at $1,000 per unit and aggregating the amount with the
outstanding Subordinated Notes of $10.0 million. The Company then allocated the non-cash value of the units of approximately $1.3
million, which was recorded as a discount to the Subordinated Notes. As of June 30, 2018, Carbon California had an outstanding
discount of $923,000, which is presented net of the Subordinated Notes within Credit facility-related party on the unaudited consolidated
balance sheets.
The Subordinated Notes require Carbon
California, as of January 1 and July 1 of each year, to hedge its anticipated production at such time for year one, two and three
at a rate of 67.5%, 58.5% and 45%, respectively.
Prepayment of the Subordinated Notes
is currently not available. After February 15, 2019, prepayment is allowed at 100%, subject to a 3.0% fee of outstanding principal.
Prepayment is not subject to such fee after February 17, 2020. Distributions to equity members are generally restricted.
The Securities Purchase Agreement requires
Carbon California to maintain certain financial and non-financial covenants, which include the following ratios: total leverage
ratio, senior leverage ratio, interest coverage ratio, asset coverage ratio, current ratio, and other qualitative covenants as
defined in the Securities Purchase Agreement. As of June 30, 2018, Carbon California was in compliance with its financial covenants.
Carbon California-2018 Subordinated
Notes
On May 1, 2018, Carbon California entered
into an agreement with Prudential for the issuance and sale of the Carbon California 2018 Subordinated Notes.
Prudential received 585 Class A Units,
representing approximately 2% additional sharing percentage, for the issuance of the Carbon California 2018 Subordinated Notes.
Carbon California valued this unit issuance based on the relative fair value by valuing the units at $1,000 per unit and aggregating
the amount with the outstanding Carbon California 2018 Subordinated Notes of $3.0 million. The Company then allocated the non-cash
value of the units of approximately $490,000, which was recorded as a discount to the Carbon California 2018 Subordinated Notes.
As of June 30, 2018, Carbon California had an outstanding discount of $482,000 associated with these notes, which is presented
net of the Carbon California 2018 Subordinated Notes within Credit facility-related party on the unaudited consolidated balance
sheets. As of June 30, 2018, the Company has $58,000 of deferred costs offsetting the Carbon California 2018 Subordinated Notes.
The Carbon California 2018 Subordinated
Notes require Carbon California, as of January 1 and July 1 of each year, to hedge its anticipated production at such time for
year one, two and three at a rate of 67.5%, 58.5% and 45%, respectively.
Prepayment of the Carbon California
2018 Subordinated Notes is currently not available. After May 1, 2020, prepayment is allowed in full subject to a 3.0% fee of
outstanding principal. Prepayment is not subject to such fee after May 1, 2021. Distributions to equity members are generally
restricted.
The Carbon California 2018 Subordinated
Notes agreement requires Carbon California to maintain certain financial and non-financial covenants, which include the following
ratios: total leverage ratio, senior leverage ratio, interest coverage ratio, asset coverage ratio, current ratio, and other qualitative
covenants as defined in the Carbon California 2018 Subordinated Notes. As of June 30, 2018, Carbon California was in compliance
with its financial covenants.
Note 8 – Income Taxes
We recognize deferred income tax assets
and liabilities for the estimated future tax consequences attributable to temporary differences between the financial statement
carrying amounts of existing assets and liabilities and their respective tax bases. We have net operating loss carryforwards available
in certain jurisdictions to reduce future taxable income. Future tax benefits for net operating loss carryforwards are recognized
to the extent that realization of these benefits is considered more likely than not. To the extent that available evidence raises
doubt about the realization of a deferred income tax asset, a valuation allowance is established.
At June 30, 2018, we have established
a full valuation allowance against the balance of net deferred tax assets.
Note 9 – Stockholders’
Equity
Authorized and Issued Capital Stock
Effective March 15, 2017, and pursuant
to a reverse stock split approved by the stockholders and Board of Directors, each 20 shares of issued and outstanding common stock
became one share of common stock and no fractional shares were issued. References to the number of shares and price per share give
retroactive effect to the reverse stock split for all periods presented.
As of June 30, 2018, we had 35.0 million
shares of common stock authorized with a par value of $0.01 per share, of which approximately 7.7 million were issued and outstanding,
and 1.0 million shares of preferred stock authorized with a par value of $0.01 per share. On April 6, 2018, the Company entered
into a preferred stock purchase agreement with Yorktown for a private placement of 50,000 shares of the Preferred Stock for $5.0
million. During the six months ended June 30, 2018, the increase in our issued and outstanding common stock is primarily due to
(a) Yorktown’s exercise of the California Warrant (see note 3), resulting in the issuance of approximately 1.5 million shares
of our common stock in exchange for Class A Units in Carbon California representing approximately 46.96% of the then outstanding
Class A Units, in addition to (b) restricted stock and restricted performance units that vested during the year.
Carbon Stock Incentive Plans
We have two stock plans, the Carbon 2011
Stock Incentive Plan and the Carbon 2015 Stock Incentive Plan (collectively the “Carbon Plans”). The Carbon Plans were
approved by our shareholders and in the aggregate provide for the issuance of approximately 1.1 million shares of common stock
to our officers, directors, employees or consultants eligible to receive the awards under the Carbon Plans.
The Carbon Plans provide for the granting
of incentive stock options, non-qualified stock options, restricted stock awards, performance awards and phantom stock awards,
or a combination of the foregoing, as to employees, officers, directors or consultants, provided that only employees may be granted
incentive stock options and directors may only be granted restricted stock awards and phantom stock awards.
Restricted Stock
As of June 30, 2018, approximately
649,000 shares of restricted stock have been granted under the terms of the Carbon Plans. Restricted stock awards for employees
vest ratably over a three-year service period or cliff vest at the end of a three-year service period. For non-employee directors,
the awards vest upon the earlier of a change in control of us or the date their membership on the Board of Directors is terminated
other than for cause. We recognize compensation expense for these restricted stock grants based on the grant date fair value of
the shares, amortized ratably over three years for employee awards (based on the required service period for vesting) and seven
years for non-employee director awards (based on a market survey of the average tenure of directors among U.S. public companies).
For restricted stock granted between 2014 and 2017, we recognized compensation expense based on the grant date fair value of the
shares, utilizing an enterprise value approach, using valuation metrics primarily based on multiples of cash flow from operations,
production and reserves. For restricted stock and performance units granted in 2013 and 2018, we utilized the closing price of
our stock on the date of grant to recognize compensation expense. During the six months ended June 30, 2018, 58,719 restricted
stock units vested.
Compensation costs recognized for these
restricted stock grants were approximately $348,000 and $354,000 for the six months ended June 30, 2018 and 2017, respectively.
As of June 30, 2018, there was approximately $1.8 million unrecognized compensation costs related to these restricted stock grants
which we expect to be recognized over the next 6.8 years. In 2018 we utilized the traded value of our common stock on the date
of grant instead of the enterprise value to record compensation expense related to new equity grants. Due to the price received
for our Preferred Stock, we believe the closing price of our common stock is now a better representation of the fair value of
our common stock, instead of the enterprise value used to record compensation expense related to new equity grants.
Restricted Performance Units
As of June 30, 2018, approximately
597,000 shares of performance units have been granted under the terms of the Carbon Plans. Performance units represent a contractual
right to receive one share of our common stock subject to the terms and conditions of the agreements, including the achievement
of certain performance measures relative to a defined peer group or the growth of certain performance measures over a defined
period of time as well as, in some cases, continued service requirements.
We account for the performance units
granted during 2014 through 2018 at their fair value determined at the date of grant, which were $11.80, $8.00, $5.40, $7.20 and
$9.80 per share, respectively. The final measurement of compensation cost will be based on the number of performance units that
ultimately vest. At June 30, 2018, we estimated that none of the performance units granted in 2016-2018 would vest, and, accordingly,
no compensation cost has been recorded for these performance units. During 2016, we estimated that it was probable that the performance
units granted in 2014 and 2015 would vest and therefore compensation costs of approximately $135,000 and $185,000 related to these
performance units were recognized for the six months ended June 30, 2018 and 2017, respectively. As of June 30, 2018, compensation
costs related to the performance units granted in 2014 and 2015 have been fully recognized. As of June 30, 2018, if change in
control and other performance provisions pursuant to the terms and conditions of these award agreements are met in full, the estimated
unrecognized compensation cost related to the performance units granted in 2012 and 2016 through 2018 would be approximately $3.4
million.
Preferred Stock
Series B Convertible Preferred
Stock – Related Party
In connection with the closing of the
Seneca Acquisition, we raised $5.0 million through the issuance of 50,000 shares of Preferred Stock to Yorktown. The Preferred
Stock converts into common stock at the election of the holder or will automatically convert into shares of our common stock upon
completion of a qualifying equity financing event. The number of shares of common stock issuable upon conversion is dependent
upon the price per share of common stock issued in connection with any such qualifying equity financing but has a floor conversion
price equal to $8.00 per share. The conversion ratio at which the Preferred Stock will convert into common stock is equal to an
amount per share of $100 plus all accrued but unpaid dividends payable in respect thereof divided by the greater of (i) $8.00
per share or (ii) the price that is 15% less than the lowest price per share of shares sold to the public in the next equity financing.
Using the floor of $8.00 per share would yield 12.5 shares of common stock for every unit of Preferred Stock. The conversion price
will be proportionately increased or decreased to reflect changes to the outstanding shares of common stock, such as the result
of a combination, reclassification, subdivision, stock split, stock dividend or other similar transaction involving the common
stock. Additionally, after the third anniversary of the issuance of the Preferred Stock, we have the option to redeem the shares
for cash.
The Preferred Stock accrues cash dividends
at a rate of six percent (6%) of the initial issue price of $100 per share per annum. The holders of the Preferred Stock are entitled
to the same number of votes of common stock that such share of Preferred Stock would represent on an as converted basis. The holders
of the Preferred Stock receive liquidation preference based on the initial issue price of $100 per share plus any accrued dividends
over common stock holders and the holders of any junior ranking stock. As of June 30, 2018, we accrued $71,000 of dividends.
We apply the guidance in ASC 480 “
Distinguishing
Liabilities from Equity
” when determining the classification and measurement of the Preferred Stock. The Preferred Stock
does not feature any redemption rights within the holders’ control or conditional redemption features not within our control
as of June 30, 2018. Accordingly, the Preferred Stock is presented as a component of consolidated stockholders’ equity.
We have evaluated the Preferred Stock
in accordance with ASC 815, “
Derivatives and Hedging
”, including consideration of embedded derivatives requiring
bifurcation. The issuance of the Preferred Stock could generate a beneficial conversion feature (“BCF”), which arises
when a debt or equity security is issued with an embedded conversion option that is beneficial to the investor or in the money
at inception because the conversion option has an effective strike price that is less than the market price of the underlying
stock at the commitment date. Based on the conversion terms and the price at the commitment date, we determined that a BCF was
required to be recorded related to the voluntary conversion option by the holder as of June 30, 2018. We recorded the BCF as a
reduction of retained earnings and an increase to APIC of $1.1 million, which is based on the difference between the floor price
of $8.00 and our stock price as of the commitment date multiplied by the number of shares to be issued. We are also required to
evaluate a contingent BCF for the automatic conversion feature, but in accordance with ASC 470, “
Debt
”, we
will not record the effect of the BCF until the contingency is resolved. As of June 30, 2018, we have a BCF of approximately $1.1
million
We also evaluated the Preferred Stock
conversion components and determined it should be considered an “equity host” and not a “debt host” as
defined by ASC 815. This evaluation is necessary in order to determine if any embedded features require bifurcation and, therefore,
separate accounting as a derivative liability. Our analysis followed the “whole instrument approach,” which compares
an individual feature against the entire preferred stock instrument which includes that feature.
Our analysis was based on a consideration
of the economic characteristics and risks of the Preferred Stock. We specifically evaluated all the stated and implied substantive
terms and features including (i) whether the Preferred Stock included redemption features, (ii) whether the holders of the Preferred
Stock were entitled to dividends, (iii) the voting rights of the Preferred Stock and (iv) the existence and nature of any conversion
rights. As a result, our determination was that the Preferred Stock is an “equity host,” and the embedded conversion
feature is not considered a derivative liability.
Note 10 – Revenue Recognition
Revenue from Contracts with Customers
We recognize revenue when it satisfies a performance
obligation by transferring control over a product to a customer. Revenue is measured based on the consideration we expect to receive
in exchange for those products. Revenues from contracts with customers are recorded on the unaudited consolidated statements of
operations based on the type of product being sold.
Performance Obligations and Significant
Judgments
We sell oil and natural gas products in the
United States through a single reportable segment. We primarily sell products within two regions of the United States: Appalachia
and Illinois Basins and the Ventura Basin. We enter into contracts that generally include one type of distinct product in variable
quantities and priced based on a specific index related to the type of product. Most of our contract pricing provisions are tied
to a market index, with certain adjustments based on, among other factors, whether a well delivers to a gathering or transmission
line, quality of the oil or natural gas, and prevailing supply and demand conditions.
The oil and natural gas is typically sold
in an unprocessed state to processors and other third parties for processing and sale to customers. We recognize revenue at a
point in time when control of the oil or natural gas passes to the customer. For oil sales, control is typically transferred to
the customer upon receipt at the wellhead or a contractually agreed upon delivery point. Under our natural gas contracts with
processors, control transfers upon delivery at the wellhead or the inlet of the processing entity’s system. For our other
natural gas contracts, control transfers upon delivery to the inlet or to a contractually agreed upon delivery point. In the cases
where we sell to a processor, we have determined that we are the principal in the arrangement and the processors are our customers.
We recognize the revenue in these contracts based on the net proceeds received from the processor.
Transfer of control drives the presentation
of transportation and gathering costs within the accompanying unaudited consolidated statements of operations. Transportation
and gathering costs incurred prior to control transfer are recorded within the transportation and gathering expense line item
on the accompanying unaudited consolidated statements of operations, while transportation and gathering costs incurred subsequent
to control transfer are recorded as a reduction to the related revenue.
A portion of our product sales are short-term
in nature. For those contracts, we use the practical expedient in ASC 606-10-50-14 exempting us from disclosure of the transaction
price allocated to remaining performance obligations if the performance obligation is part of a contract that has an original
expected duration of one year or less.
For our product sales that have a contract
term greater than one year, we have utilized the practical expedient in ASC 606-10-50-14(a) which states we are not required to
disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely
to an unsatisfied performance obligation. Under these sales contracts, each unit of product represents a separate performance
obligation; therefore, future volumes are unsatisfied and disclosure of the transaction price allocated to remaining performance
obligations is not required. We have no unsatisfied performance obligations at the end of each reporting period.
We do not believe that significant judgments
are required with respect to the determination of the transaction price, including any variable consideration identified. There
is a low level of uncertainty due to the precision of measurement and use of index-based pricing with predictable differentials.
Additionally, any variable consideration identified is not constrained.
Disaggregation of Revenues
In the following table, revenue for
the six months ended June 30, 2018, is disaggregated by primary region within the United States and major product line. As noted
above, we operate as one reportable segment.
(in thousands)
|
|
|
|
|
|
|
|
|
|
Type
|
|
Appalachia and
Illinois Basin
|
|
|
Ventura Basin
|
|
|
Total
|
|
Natural gas sales
|
|
$
|
6,919
|
|
|
$
|
543
|
|
|
$
|
7,462
|
|
Natural gas liquids sales
|
|
|
-
|
|
|
|
713
|
|
|
|
713
|
|
Oil sales
|
|
|
2,624
|
|
|
|
8,450
|
|
|
|
11,074
|
|
Total revenue
|
|
$
|
9,543
|
|
|
$
|
9,706
|
|
|
$
|
19,249
|
|
Contract Balances
Under our product sales contracts, we
invoice customers once our performance obligations have been satisfied, at which point payment is unconditional. Accordingly,
our product sales contracts do not typically give rise to contract assets or liabilities under ASC 606.
Prior Period Performance Obligations
We record revenue in the month production
is delivered to the purchaser, but settlement statements may not be received until 30 to 90 days after the month of production.
As such, we estimate the production delivered and the related pricing. Any differences between our initial estimates and actuals
are recorded in the month payment is received from the customer. These differences have not historically been material. For the
six months ended June 30, 2018, revenue recognized in the reporting period related to prior period performance obligations is
immaterial.
The estimated revenue is recorded within Accounts
receivable - Revenue on the unaudited consolidated balance sheets.
Note 11 – Accounts Payable
and Accrued Liabilities
Accounts payable and accrued liabilities consist
of the following:
|
|
June 30,
2018
|
|
|
December 31,
2017
|
|
|
|
|
|
|
|
|
Accounts payable
|
|
$
|
5,220
|
|
|
$
|
3,274
|
|
Oil and gas revenue suspense
|
|
|
2,419
|
|
|
|
1,776
|
|
Gathering and transportation payables
|
|
|
1,550
|
|
|
|
497
|
|
Production taxes payable
|
|
|
507
|
|
|
|
214
|
|
Drilling advances received from joint venture partner
|
|
|
274
|
|
|
|
245
|
|
Accrued lease operating expenses
|
|
|
832
|
|
|
|
684
|
|
Accrued ad valorem taxes-current
|
|
|
1,611
|
|
|
|
1,054
|
|
Accrued general and administrative expenses
|
|
|
605
|
|
|
|
2,473
|
|
Accrued asset retirement obligation-current
|
|
|
769
|
|
|
|
380
|
|
Accrued interest
|
|
|
492
|
|
|
|
247
|
|
Other liabilities
|
|
|
869
|
|
|
|
374
|
|
|
|
|
|
|
|
|
|
|
Total accounts payable and accrued liabilities
|
|
$
|
15,148
|
|
|
$
|
11,218
|
|
Note 12 – Fair Value Measurements
Authoritative guidance defines fair value
as the price that would be received to sell an asset or paid to transfer a liability (an exit price) in an orderly transaction
between market participants at the measurement date. The guidance establishes a hierarchy for inputs used in measuring fair value
that maximizes the use of observable inputs and minimizes the use of unobservable inputs by requiring that the most observable
inputs be used when available. Observable inputs are inputs that market participants would use in pricing the asset or liability
developed based on market data obtained from sources independent of us. Unobservable inputs are inputs that reflect our assumptions
of what market participants would use in pricing the asset or liability developed based on the best information available in the
circumstances. The hierarchy is broken down into three levels based on the reliability of the inputs as follows:
|
Level 1:
|
Quoted
prices are available in active markets for identical assets or liabilities;
|
|
Level 2:
|
Quoted
prices in active markets for similar assets or liabilities that are observable for the asset or liability; or
|
|
Level 3:
|
Unobservable
pricing inputs that are generally less observable from objective sources, such as discounted cash flow models or valuations.
|
Financial assets and liabilities are classified
based on the lowest level of input that is significant to the fair value measurement. Our policy is to recognize transfers in
and/or out of fair value hierarchy as of the end of the reporting period for which the event or change in circumstances caused
the transfer. We have consistently applied the valuation techniques discussed below for all periods presented.
The following table presents our financial
assets and liabilities that were accounted for at fair value on a recurring basis by level within the fair value hierarchy:
(in thousands)
|
|
Fair Value Measurements Using
|
|
|
|
Level 1
|
|
|
Level 2
|
|
|
Level 3
|
|
|
Total
|
|
June 30, 2018
|
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivatives
|
|
$
|
-
|
|
|
$
|
8,017
|
|
|
$
|
-
|
|
|
$
|
8,017
|
|
December 31, 2017
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Asset:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivatives
|
|
$
|
-
|
|
|
$
|
215
|
|
|
$
|
-
|
|
|
$
|
215
|
|
Liabilities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Warrant derivative liability
|
|
$
|
-
|
|
|
$
|
-
|
|
|
$
|
2,017
|
|
|
$
|
2,017
|
|
Commodity Derivative
As of June 30, 2018, our commodity
derivative financial instruments are comprised of natural gas and oil swaps and costless collars. The fair values of these agreements
are determined under an income valuation technique. The valuation model requires a variety of inputs, including contractual terms,
published forward prices, volatilities for options and discount rates, as appropriate. Our estimates of fair value of derivatives
include consideration of the counterparty’s credit worthiness, our credit worthiness and the time value of money. The consideration
of these factors results in an estimated exit-price for each derivative asset or liability under a market place participant’s
view. All the significant inputs are observable, either directly or indirectly; therefore, our derivative instruments are included
within the Level 2 fair value hierarchy. The counterparty for all our outstanding commodity derivative financial instruments as
of June 30, 2018, is BP Energy Company.
Warrant Derivative
A third-party valuation specialist was
utilized to determine the fair value our California Warrant. The warrant is designated as Level 3. We review the valuations, including
the related model inputs and assumptions, and analyze changes in fair value measurements between periods. We corroborate such inputs,
calculations and fair value changes using various methodologies, and review unobservable inputs for reasonableness utilizing relevant
information from other published sources.
We estimated the fair value of the
California Warrant on February 15, 2017, the grant date of the warrant, to be approximately $5.8 million, using a call option
pricing model with the following assumptions: a seven-year term, exercise price of $7.20, volatility rate of 41.8% and a risk-free
rate of 2.3%. As we will receive Class A Units in Carbon California in the event the holder exercises the California Warrant,
we also considered the fair value of the Class A Units in its valuation. We utilized the same measurement as of December 31, 2017
for January 31, 2018, using a Monte Carlo valuation model which utilized unobservable inputs including the percentage return on
our shares at various timelines, the percentage return on the privately-held Carbon California Class A Units at various timelines,
an exercise price of $7.20, volatility rate of 45%, a risk-free rate of 2.1% and an estimated remaining term of 6.4 years. As
of December 31, 2017, the fair value of the California Warrant was approximately $2.0 million. On February 1, 2018, Yorktown exercised
the California Warrant, resulting in the issuance of 1,527,778 shares of our common stock. In exchange, we received Yorktown’s
Class A Units of Carbon California representing approximately 46.96% of the outstanding Class A Units of Carbon California and
a profits interest of approximately 38.59%.
The following table summarizes the changes
in fair value of our financial instruments classified as Level 3 in the fair value hierarchy:
(in thousands)
|
|
Total
|
|
Balance, December 31, 2017
|
|
$
|
2,017
|
|
Warrant derivative gain for the period January 1- January 31, 2018
|
|
|
(225
|
)
|
CCC Warrant Exercise - liability extinguishment
|
|
|
(1,792
|
)
|
Balance, June 30, 2018
|
|
$
|
-
|
|
Assets and Liabilities Measured and
Recorded at Fair Value on a Non-Recurring Basis
The fair value of each of the following
assets and liabilities measured and recorded at fair value on a non-recurring basis are based on unobservable pricing inputs and
therefore, are included within the Level 3 fair value hierarchy.
We use the income valuation technique
to estimate the fair value of asset retirement obligations using the amounts and timing of expected future dismantlement costs,
credit-adjusted risk-free rates and time value of money. During the six months ended June 30, 2018 and 2017, we recorded approximately
$3.6 million and $5,000, in additions to asset retirement obligations, respectively. Additions during the six months ended June
30, 2018, primarily related to the Carbon California Acquisition. See note 3 for additional information.
The exercise of the California Warrant and
the acquisition of the additional ownership interest in Carbon California on February 1, 2018, is accounted for as a step acquisition
in which we obtained control in accordance with ASC 805, Business Combinations (“ASC 805”). We consolidate the results
of Carbon California into our unaudited condensed consolidated financial statements from the date of the Carbon California Acquisition
forward. The Carbon California Acquisition was accounted for as a business combination, and the identifiable assets acquired,
and liabilities assumed, were recorded at their estimated fair value at the date of acquisition. We have completed our preliminary
valuation to determine the fair value of the identifiable assets acquired and liabilities assumed. The fair value of the assets
acquired was determined using various valuation techniques, including an income approach. The fair value measurements were primarily
based on significant inputs that are not directly observable in the market and are considered Level 3 under the fair value measurements
and disclosure framework. See note 3 for additional information.
We assume, at times, certain firm transportation
contracts as part of our acquisitions of oil and natural gas properties. The fair value of the firm transportation obligations
was determined based upon the contractual obligations assumed by us and discounted based upon our effective borrowing rate. These
contractual obligations are being amortized monthly as we pay these firm transportation obligations in the future.
Asset Retirement Obligation
The fair value of our asset retirement
obligation liability is recorded in the period in which it is incurred or assumed by taking into account the cost of abandoning
oil and gas wells ranging from $20,000 to $30,000, which is based on industry expectations for similar work; the estimated timing
of reclamation ranging from one to 75 years based on estimates from reserve engineers; an inflation rate of 1.92%; and a credit
adjusted risk-free rate of 7.24%, which takes into account our credit risk and the time value of money. Given the unobservable
nature of the inputs, the initial measurement of the asset retirement obligation liability is deemed to use Level 3 inputs (see
note 3). During the six months ended June 30, 2018, we recorded additions to asset retirement obligations of approximately $3.6
million, primarily due to the Carbon California Acquisition. Carbon California estimates the fair value of asset retirement obligations
using the amounts and timing of expected future dismantlement costs, credit-adjusted risk-free rates and time value of money.
Carbon California’s asset retirement obligation is calculated upon assumption by taking into account the cost of abandoning
oil and gas wells based on industry expectations for similar work, the economic lives of its properties between 1-49 years; an
inflation rate between 2.01% and 2.03%; and a credit adjusted risk-free rate between 8.09% and 15.5%.
Class B Units
We received Class B Units from Carbon California
and Carbon Appalachia as part of the entry into the Carbon California LLC and Carbon Appalachia LLC agreements. We estimated the
fair value of the Class B units, in each case, by utilizing the assistance of third-party valuation specialists. The fair values
were based upon enterprise values derived from inputs including estimated future production rates, future commodity prices including
price differentials as of the dates of closing, future operating and development costs and comparable market participants.
Note 13 – Physical Delivery Contracts and Gas Derivatives
We historically have used commodity-based
derivative contracts to manage exposures to commodity price on certain of our oil and natural gas production. We do not hold or
issue derivative financial instruments for speculative or trading purposes. We also have entered into fixed price delivery contracts
to effectively provide commodity price hedges. Because these contracts are not expected to be net cash settled, they are considered
to be normal sales contracts and not derivatives. Therefore, these contracts are not recorded at fair value in the unaudited condensed
consolidated financial statements.
Pursuant to the terms of our credit
facility, the Note Purchase Agreements and the Securities Purchase Agreement, we have entered into swap and collar derivative
agreements to hedge certain of our oil and natural gas production through 2021. As of June 30, 2018, these derivative agreements
consisted of the following:
Our Physical Delivery Contracts
and Oil and Gas Derivatives
|
|
Natural Gas Swaps
|
|
|
Natural Gas Collars
|
|
|
Oil Swaps
|
|
|
|
|
|
|
Weighted
|
|
|
|
|
|
Weighted
|
|
|
|
|
|
Weighted
|
|
|
|
|
|
|
Average
|
|
|
|
|
|
Average Price
|
|
|
|
|
|
Average
|
|
Year
|
|
MMBtu
|
|
|
Price (a)
|
|
|
MMBtu
|
|
|
Range (a)
|
|
|
Bbl
|
|
|
Price (b)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2018
|
|
|
1,740,000
|
|
|
$
|
3.00
|
|
|
|
-
|
|
|
|
-
|
|
|
|
35,500
|
|
|
$
|
53.41
|
|
2019
|
|
|
2,596,000
|
|
|
$
|
2.86
|
|
|
|
-
|
|
|
|
-
|
|
|
|
48,000
|
|
|
$
|
53.76
|
|
|
(a)
|
NYMEX Henry Hub
Natural Gas futures contract for the respective period.
|
|
(b)
|
NYMEX Light Sweet
Crude West Texas Intermediate futures contract for the respective period.
|
Carbon California Physical Delivery
Contracts and Oil and Gas Derivatives
|
|
Natural
Gas Swaps
|
|
|
Natural
Gas Collars
|
|
|
Oil
Swaps
|
|
|
|
|
|
|
Weighted
|
|
|
|
|
|
Weighted
|
|
|
|
|
|
Weighted
|
|
|
|
|
|
Weighted
|
|
|
|
|
|
|
Average
|
|
|
|
|
|
Average
Price
|
|
|
WTI
|
|
|
Average
|
|
|
Brent
|
|
|
Average
|
|
Year
|
|
MMBtu
|
|
|
Price
(a)
|
|
|
MMBtu
|
|
|
Range (a)
|
|
|
Bbl
|
|
|
Price
(b)
|
|
|
Bbl
|
|
|
Price
(c)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2018
|
|
|
180,000
|
|
|
$
|
3.03
|
|
|
|
-
|
|
|
|
-
|
|
|
|
85,809
|
|
|
$
|
53.08
|
|
|
|
110,598
|
|
|
$
|
66.46
|
|
2019
|
|
|
-
|
|
|
$
|
-
|
|
|
|
360,000
|
|
|
|
$2.60 - $3.03
|
|
|
|
139,797
|
|
|
$
|
51.96
|
|
|
|
137,486
|
|
|
$
|
66.35
|
|
2020
|
|
|
-
|
|
|
$
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
73,147
|
|
|
$
|
50.12
|
|
|
|
123,882
|
|
|
$
|
65.06
|
|
2021
|
|
|
-
|
|
|
$
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
$
|
-
|
|
|
|
28,641
|
|
|
$
|
66.35
|
|
|
(a)
|
NYMEX Henry Hub
Natural Gas futures contract for the respective period.
|
|
(b)
|
NYMEX Light Sweet
Crude West Texas Intermediate futures contract for the respective period.
|
|
(c)
|
Brent
future contracts for the respective period.
|
For our swap instruments, we receive a
fixed price for the hedged commodity and pay a floating price to the counterparty. The fixed-price payment and the floating-price
payment are netted, resulting in a net amount due to or from the counterparty.
Costless collars are designed to establish
floor and ceiling prices on anticipated future oil and gas production. The ceiling establishes a maximum price that we will receive
for the volumes under contract, while the floor establishes a minimum price.
The following table summarizes the fair value
of the derivatives recorded in the unaudited consolidated balance sheets (see note 12). These derivative instruments are not designated
as cash flow hedging instruments for accounting purposes:
(in thousands)
|
|
|
|
|
|
June 30,
2018
|
|
|
December 31,
2017
|
|
Commodity derivative contracts:
|
|
|
|
|
|
|
|
|
Commodity derivative asset
|
|
$
|
-
|
|
|
$
|
215
|
|
Other long-term assets
|
|
$
|
-
|
|
|
$
|
10
|
|
|
|
|
|
|
|
|
|
|
Commodity derivative liabilities
|
|
$
|
4,570
|
|
|
$
|
-
|
|
Commodity derivative liabilities, non-current
|
|
$
|
3,447
|
|
|
$
|
-
|
|
The table below summarizes the commodity
settlements and unrealized gains and losses related to our derivative instruments. These commodity settlements and unrealized gains
and losses are recorded and included in commodity derivative gain or loss in the accompanying unaudited consolidated statements
of operations.
(in thousands)
|
|
For the six months ended
June 30,
|
|
|
|
2018
|
|
|
2017
|
|
Commodity derivative contracts:
|
|
|
|
|
|
|
Settlement (loss) gain
|
|
$
|
(1,060
|
)
|
|
$
|
118
|
|
Unrealized (loss) gain
|
|
|
(5,587
|
)
|
|
|
3,023
|
|
|
|
|
|
|
|
|
|
|
Total settlement and unrealized (loss) gain, net
|
|
$
|
(6,647
|
)
|
|
$
|
3,141
|
|
Commodity derivative settlement gains and
losses are included in cash flows from operating activities in our unaudited consolidated statements of cash flows.
The counterparty in all our derivative
instruments is BP Energy Company. We and Carbon California have entered into International Swaps and Derivatives Association (“ISDA”)
Master Agreements with BP Energy Company that establish standard terms for the derivative contracts and inter-creditor agreements
whereby any credit exposure related to the derivative contracts entered into by us and BP Energy Company is secured by the collateral
and backed by the guarantees supporting the credit facility.
We and Carbon California net our derivative
instrument fair value amounts executed with BP Energy Company pursuant to ISDA master agreements, which provide for the net settlement
over the term of the contracts and in the event of default or termination of the contracts. The following table summarizes the
location and fair value amounts of all derivative instruments in the unaudited consolidated balance sheets, as well as the gross
recognized derivative assets, liabilities and amounts offset in the unaudited consolidated balance sheets as of June 30, 2018.
|
|
|
|
|
|
|
|
|
|
Net
|
|
|
|
|
|
Gross
|
|
|
|
|
|
Recognized
|
|
|
|
|
|
Recognized
|
|
|
Gross
|
|
|
Fair Value
|
|
|
|
|
|
Assets/
|
|
|
Amounts
|
|
|
Assets/
|
|
|
|
Balance Sheet Classification
|
|
Liabilities
|
|
|
Offset
|
|
|
Liabilities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivative assets:
|
|
Commodity derivative
|
|
$
|
272
|
|
|
$
|
(272
|
)
|
|
$
|
-
|
|
|
|
Other long-term assets
|
|
|
181
|
|
|
|
(181
|
)
|
|
|
-
|
|
Total derivative assets
|
|
|
|
$
|
453
|
|
|
$
|
(453
|
)
|
|
$
|
-
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivative liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivative
|
|
$
|
(4,842
|
)
|
|
$
|
272
|
|
|
$
|
(4,570
|
)
|
|
|
Commodity derivative: non-current
|
|
|
(3,628
|
)
|
|
|
181
|
|
|
|
(3,447
|
)
|
Total derivative liabilities
|
|
|
|
$
|
(8,470
|
)
|
|
$
|
453
|
|
|
$
|
(8,017
|
)
|
The following table summarizes the location
and fair value amounts of all derivative instruments in the consolidated balance sheets, as well as the gross recognized derivative
assets, liabilities and amounts offset in the consolidated balance sheets as of December 31, 2017.
|
|
|
|
|
|
|
|
|
|
Net
|
|
|
|
|
|
Gross
|
|
|
|
|
|
Recognized
|
|
|
|
|
|
Recognized
|
|
|
Gross
|
|
|
Fair Value
|
|
|
|
|
|
Assets/
|
|
|
Amounts
|
|
|
Assets/
|
|
|
|
Balance Sheet Classification
|
|
Liabilities
|
|
|
Offset
|
|
|
Liabilities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivative assets:
|
|
Commodity derivative
|
|
$
|
624
|
|
|
$
|
(409
|
)
|
|
$
|
215
|
|
|
|
Other long-term assets
|
|
|
250
|
|
|
|
(240
|
)
|
|
|
10
|
|
Total derivative assets
|
|
|
|
$
|
874
|
|
|
$
|
(649
|
)
|
|
$
|
225
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivative liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivative
|
|
$
|
(409
|
)
|
|
$
|
409
|
|
|
$
|
-
|
|
|
|
Commodity derivative: non-current
|
|
|
(240
|
)
|
|
|
240
|
|
|
|
-
|
|
Total derivative liabilities
|
|
|
|
$
|
(649
|
)
|
|
$
|
649
|
|
|
$
|
-
|
|
Due to the volatility of oil and natural
gas prices, the estimated fair values of our derivatives are subject to large fluctuations from period to period.
Note 14 – Commitments
We have entered into employment agreements
with certain of our executives and officers. The term of the agreements generally ranges from one to two years and provides for
renewal provisions in one-year increments thereafter. The agreements provide for, among other items, severance and continuation
of benefit payments upon termination of employment or certain change of control events.
We have entered into long-term firm
transportation contracts to ensure the transport for certain of our gas production to purchasers. Firm transportation volumes
and the related demand charges for the remaining term of these contracts at June 30, 2018 are summarized in the table below.
Period
|
|
Dekatherms
per day
|
|
|
Demand
Charges
|
|
July 2018 - March 2020
|
|
|
3,230
|
|
|
$
|
0.20
- $0.62
|
|
April 2020 – May 2020
|
|
|
2,150
|
|
|
$
|
0.20
|
|
June 2020 – May 2036
|
|
|
1,000
|
|
|
$
|
0.20
|
|
A liability of approximately $198,000
related to firm transportation contracts assumed in the EXCO Acquisition in 2016, which represents the remaining commitment, is
reflected on our unaudited consolidated balance sheets as of June 30, 2018. The fair value of these firm transportation obligations
was determined based upon the contractual obligations assumed by us and discounted based upon our effective borrowing rate. These
contractual obligations are being amortized monthly as we pay these firm transportation obligations in the future.
Capital Commitment
In our participation as a Class A member
of Carbon Appalachia we made a capital commitment of $23.6 million, of which we have contributed $6.9 million as of June 30, 2018.
As of June 30, 2018, we had no capital commitments associated
with Carbon California.
During March 2018, management became aware
that one of our field employees had been misappropriating funds from our suspended revenue accounts, or suspense accounts, over
a period of several years. Promptly following the discovery of the misappropriation, we terminated the employee and engaged an
external forensic specialist to lead an investigation to determine the extent and impact on our financial statements. That investigation
revealed that the employee’s ability to misappropriate funds from the suspense accounts was eliminated in 2017 when we moved
our revenue accounting function to our Denver office and instituted our current set of revenue accounting practices and internal
controls. As a result, the employee no longer had access to the suspense accounts.
The discovery of the misappropriation was
made in March 2018 when the employee attempted to misappropriate funds from a different source. This attempt was identified under
our current internal controls.
The investigation is still ongoing,
but based on the results so far, we have recorded a provision at June 30, 2018, to reflect the estimated loss of suspended revenue.
Depending upon the results of the investigation, which we are seeking to conclude as soon as reasonably practicable, we may determine
that the estimate should be increased or decreased. Furthermore, we will no longer be using printed manual checks for payments.
Revenue and other checks will require approval from more than one individual and we are evaluating our segregation of duties,
specifically related to the cash disbursement process, and will adjust where possible to strengthen the system of internal
control. We have determined that this event constituted a significant deficiency, but not a material weakness.
Note 15 – Supplemental Cash Flow Disclosure
Supplemental cash flow disclosures are presented
below:
|
|
Six Months Ended
June 30,
|
|
(in thousands)
|
|
2018
|
|
|
2017
|
|
|
|
|
|
|
|
|
Cash paid during the period for:
|
|
|
|
|
|
|
|
|
Interest
|
|
$
|
909
|
|
|
$
|
433
|
|
Non-cash transactions:
|
|
|
|
|
|
|
|
|
Increase in asset retirement obligations
|
|
$
|
3,560
|
|
|
$
|
5
|
|
Decrease in accounts payable and accrued liabilities included in oil
and gas properties
|
|
$
|
(161
|
)
|
|
$
|
(79
|
)
|
Non-cash acquisition of Carbon California interests (see note 3)
|
|
$
|
(18,906
|
)
|
|
$
|
-
|
|
Carbon California Acquisition on February 1, 2018(see note 3)
|
|
$
|
17,114
|
|
|
$
|
-
|
|
Obligations assumed with Seneca asset purchase (see note 2)
|
|
$
|
330
|
|
|
$
|
-
|
|
Accrued dividend for convertible preferred stock (see note 9)
|
|
$
|
71
|
|
|
$
|
-
|
|
Beneficial conversion feature for convertible preferred stock (see
note 9)
|
|
$
|
1,125
|
|
|
$
|
-
|
|
Issuance of warrants for investment in affiliates
|
|
$
|
-
|
|
|
$
|
7,094
|
|
Exercise of warrant derivative (see note 3)
|
|
$
|
(1,792
|
)
|
|
$
|
-
|
|
Note 16 – Subsequent Events
Our Credit Facility Borrowing Base Increase
In July 2018, the borrowing base of our credit facility
was increased from $25.0 million to $28.0 million.
Liberty Acquisition
On July 11, 2018, we completed the acquisition of oil and
gas producing properties and related facilities located in eastern Kentucky from Liberty Energy, LLC for approximately $3.6 million,
subject to normal and customary post-closing adjustments (“Liberty Acquisition”). The Liberty Acquisition was funded
through borrowings under our credit facility
REPORT OF INDEPENDENT
REGISTERED PUBLIC ACCOUNTING FIRM
To the Stockholders and Board of Directors
Carbon Natural Gas Company
Denver, Colorado
OPINION ON THE FINANCIAL STATEMENTS
We have audited the accompanying consolidated
balance sheets of Carbon Natural Gas Company (the “Company”) as of December 31, 2017 and 2016, and the related consolidated
statements of operations, stockholders’ equity, and cash flows, for each year in the two-year period ended December 31,
2017, and the related notes (collectively referred to as the “financial statements”). In our opinion, the financial
statements present fairly, in all material respects, the financial position of the Company as of December 31, 2017 and 2016, and
the results of its operations and its cash flows for each year in the two-year period ended December 31, 2017, in conformity with
accounting principles generally accepted in the United States of America.
BASIS FOR OPINION
These financial statements are the responsibility
of the Company’s management. Our responsibility is to express an opinion on the Company’s financial statements based
on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (“PCAOB”)
and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable
rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance
with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about
whether the financial statements are free of material misstatement, whether due to error or fraud. The Company is not required
to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits we are
required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion
on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion.
Our audits included performing procedures
to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures
that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures
in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made
by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide
a reasonable basis for our opinion.
/s/
EKS&H LLLP
|
|
EKS&H LLLP
|
|
March
31, 20
18
Denver, Colorado
We have served as the Company’s auditor since 2005.
CARBON
NATURAL GAS COMPANY
Consolidated
Balance Sheets
(In thousands)
|
|
December 31,
|
|
|
December 31,
|
|
|
|
2017
|
|
|
2016
|
|
ASSETS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current assets:
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$
|
1,650
|
|
|
$
|
858
|
|
Accounts receivable:
|
|
|
|
|
|
|
|
|
Revenue
|
|
|
2,206
|
|
|
|
2,369
|
|
Joint interest billings and other
|
|
|
1,151
|
|
|
|
2,251
|
|
Due from related parties
|
|
|
2,075
|
|
|
|
-
|
|
Commodity derivative asset
|
|
|
215
|
|
|
|
-
|
|
Prepaid expense, deposits, and other current assets
|
|
|
783
|
|
|
|
305
|
|
Total current assets
|
|
|
8,080
|
|
|
|
5,783
|
|
|
|
|
|
|
|
|
|
|
Property and equipment (Note 5)
|
|
|
|
|
|
|
|
|
Oil and gas properties, full cost method of accounting:
|
|
|
|
|
|
|
|
|
Proved, net
|
|
|
34,178
|
|
|
|
33,212
|
|
Unproved
|
|
|
1,947
|
|
|
|
1,999
|
|
Other property and equipment, net
|
|
|
737
|
|
|
|
325
|
|
Total property and equipment, net
|
|
|
36,862
|
|
|
|
35,536
|
|
|
|
|
|
|
|
|
|
|
Investments in affiliates (Note 6)
|
|
|
14,267
|
|
|
|
668
|
|
Other long-term assets
|
|
|
800
|
|
|
|
725
|
|
Total assets
|
|
$
|
60,009
|
|
|
$
|
42,712
|
|
|
|
|
|
|
|
|
|
|
LIABILITIES AND STOCKHOLDERS’ EQUITY
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current liabilities:
|
|
|
|
|
|
|
|
|
Accounts payable and accrued liabilities (Note 10)
|
|
$
|
11,218
|
|
|
$
|
9,121
|
|
Firm transportation contract obligations (Note 1)
|
|
|
127
|
|
|
|
561
|
|
Commodity derivative liability
|
|
|
-
|
|
|
|
1,341
|
|
Total current liabilities
|
|
|
11,345
|
|
|
|
11,023
|
|
Non-current liabilities:
|
|
|
|
|
|
|
|
|
Firm transportation contract obligations (Note 1)
|
|
|
134
|
|
|
|
261
|
|
Commodity derivative liability
|
|
|
-
|
|
|
|
591
|
|
Production and property taxes payable
|
|
|
520
|
|
|
|
628
|
|
Warrant liability
|
|
|
2,017
|
|
|
|
-
|
|
Asset retirement obligations (Note 3)
|
|
|
7,357
|
|
|
|
5,006
|
|
Credit facility (Note 7)
|
|
|
22,140
|
|
|
|
16,230
|
|
Total non-current liabilities
|
|
|
32,168
|
|
|
|
22,716
|
|
|
|
|
|
|
|
|
|
|
Commitments and contingencies (Note 13)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Stockholders’ equity:
|
|
|
|
|
|
|
|
|
Preferred stock, $0.01 par value; authorized 1,000,000
shares, no shares issued and outstanding at December 31, 2017 and 2016
|
|
|
-
|
|
|
|
-
|
|
Common
stock, $0.01 par value; authorized 10,000,000 shares, 6,005,633 and 5,482,673 shares
issued and outstanding at December 31, 2017 and 2016, respectively
|
|
|
60
|
|
|
|
1,096
|
|
Additional paid-in capital
|
|
|
58,813
|
|
|
|
56,548
|
|
Accumulated deficit
|
|
|
(44,218
|
)
|
|
|
(50,536
|
)
|
Total Carbon stockholders’ equity
|
|
|
14,655
|
|
|
|
7,108
|
|
Non-controlling interests
|
|
|
1,841
|
|
|
|
1,865
|
|
Total stockholders’ equity
|
|
|
16,496
|
|
|
|
8,973
|
|
|
|
|
|
|
|
|
|
|
Total liabilities and stockholders’ equity
|
|
$
|
60,009
|
|
|
$
|
42,712
|
|
See accompanying
notes to Consolidated Financial Statements.
CARBON
NATURAL GAS COMPANY
Consolidated
Statements of Operations
(In
thousands, except per share amounts)
|
|
Twelve months ended
December 31,
|
|
|
|
2017
|
|
|
2016
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenue:
|
|
|
|
|
|
|
Natural gas sales
|
|
$
|
15,298
|
|
|
$
|
7,127
|
|
Oil sales
|
|
|
4,213
|
|
|
|
3,316
|
|
Commodity derivative gain (loss)
|
|
|
2,928
|
|
|
|
(2,259
|
)
|
Other income
|
|
|
34
|
|
|
|
11
|
|
Total revenue
|
|
|
22,473
|
|
|
|
8,195
|
|
|
|
|
|
|
|
|
|
|
Expenses:
|
|
|
|
|
|
|
|
|
Lease operating expenses
|
|
|
6,141
|
|
|
|
3,175
|
|
Transportation and gathering costs
|
|
|
2,172
|
|
|
|
1,645
|
|
Production and property taxes
|
|
|
1,276
|
|
|
|
820
|
|
General and administrative
|
|
|
9,528
|
|
|
|
8,645
|
|
General and administrative-related party reimbursement
|
|
|
(2,703
|
)
|
|
|
-
|
|
Depreciation, depletion, and amortization
|
|
|
2,544
|
|
|
|
1,953
|
|
Accretion of asset retirement obligations
|
|
|
307
|
|
|
|
176
|
|
Impairment of oil and gas properties
|
|
|
-
|
|
|
|
4,299
|
|
Total expenses
|
|
|
19,265
|
|
|
|
20,713
|
|
|
|
|
|
|
|
|
|
|
Operating income (loss)
|
|
|
3,208
|
|
|
|
(12,518
|
)
|
|
|
|
|
|
|
|
|
|
Other income and (expense):
|
|
|
|
|
|
|
|
|
Interest expense
|
|
|
(1,202
|
)
|
|
|
(367
|
)
|
Warrant derivative gain
|
|
|
3,133
|
|
|
|
-
|
|
Investment in affiliates
|
|
|
1,158
|
|
|
|
49
|
|
Other
|
|
|
28
|
|
|
|
17
|
|
Total other income and (expense)
|
|
|
3,117
|
|
|
|
(301
|
)
|
|
|
|
|
|
|
|
|
|
Income (loss) before income taxes
|
|
|
6,325
|
|
|
|
(12,819
|
)
|
|
|
|
|
|
|
|
|
|
Provision for income taxes
|
|
|
(74
|
)
|
|
|
-
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) before non-controlling interest
|
|
|
6,399
|
|
|
|
(12,819
|
)
|
|
|
|
|
|
|
|
|
|
Net income (loss) attributable to non-controlling interests
|
|
|
81
|
|
|
|
(413
|
)
|
|
|
|
|
|
|
|
|
|
Net income (loss) attributable to controlling interest
|
|
$
|
6,318
|
|
|
$
|
(12,406
|
)
|
|
|
|
|
|
|
|
|
|
Net income (loss) per common share:
|
|
|
|
|
|
|
|
|
Basic
|
|
$
|
1.12
|
|
|
$
|
(2.27
|
)
|
Diluted
|
|
$
|
0.49
|
|
|
$
|
(2.27
|
)
|
Weighted average common shares outstanding (in thousands):
|
|
|
|
|
|
|
|
|
Basic
|
|
|
5,662
|
|
|
|
5,468
|
|
Diluted
|
|
|
6,465
|
|
|
|
5,468
|
|
See accompanying
notes to Consolidated Financial Statements.
CARBON
NATURAL GAS COMPANY
Consolidated
Statements of Stockholders’ Equity
(In thousands)
|
|
|
|
|
|
|
|
Additional
|
|
|
Non-
|
|
|
|
|
|
Total
|
|
|
|
Common Stock
|
|
|
Paid-in
|
|
|
Controlling
|
|
|
Accumulated
|
|
|
Stockholders’
|
|
|
|
Shares
|
|
|
Amount
|
|
|
Capital
|
|
|
Interests
|
|
|
Deficit
|
|
|
Equity
|
|
Balances, December 31, 2015
|
|
|
5,383
|
|
|
$
|
36
|
|
|
$
|
55,434
|
|
|
$
|
2,299
|
|
|
$
|
(38,130
|
)
|
|
$
|
19,640
|
|
Stock-based compensation
|
|
|
-
|
|
|
|
-
|
|
|
|
2,440
|
|
|
|
-
|
|
|
|
-
|
|
|
|
2,440
|
|
Restricted stock vested
|
|
|
65
|
|
|
|
13
|
|
|
|
(13
|
)
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
Performance units vested
|
|
|
84
|
|
|
|
17
|
|
|
|
(17
|
)
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
Restricted stock and performance units
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
-
|
|
|
|
-
|
|
|
|
|
|
exchanged for tax withholding
|
|
|
(50
|
)
|
|
|
(11
|
)
|
|
|
(256
|
)
|
|
|
-
|
|
|
|
-
|
|
|
|
(267
|
)
|
Non-controlling interests distributions, net
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
(14
|
)
|
|
|
-
|
|
|
|
(14
|
)
|
Non-controlling interest purchase
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
(7
|
)
|
|
|
-
|
|
|
|
(7
|
)
|
Net loss
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
(413
|
)
|
|
|
(12,406
|
)
|
|
|
(12,819
|
)
|
Balances, December 31, 2016
|
|
|
5,482
|
|
|
$
|
55
|
|
|
$
|
57,588
|
|
|
$
|
1,865
|
|
|
$
|
(50,536
|
)
|
|
$
|
8,973
|
|
Stock-based compensation
|
|
|
-
|
|
|
|
-
|
|
|
|
1,106
|
|
|
|
-
|
|
|
|
-
|
|
|
|
1,106
|
|
Restricted stock vested
|
|
|
67
|
|
|
|
1
|
|
|
|
(1
|
)
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
Performance units vested
|
|
|
80
|
|
|
|
1
|
|
|
|
(1
|
)
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
Restricted stock and performance units
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
exchanged for tax withholding
|
|
|
(55
|
)
|
|
|
(1
|
)
|
|
|
(398
|
)
|
|
|
-
|
|
|
|
-
|
|
|
|
(399
|
)
|
Shares issued for exercise of warrant (Note 6)
|
|
|
432
|
|
|
|
4
|
|
|
|
2,787
|
|
|
|
-
|
|
|
|
-
|
|
|
|
2,791
|
|
Warrant derivative extinguishment
|
|
|
-
|
|
|
|
-
|
|
|
|
2,049
|
|
|
|
-
|
|
|
|
-
|
|
|
|
2,049
|
|
Class B Fair Value (Note 6)
|
|
|
-
|
|
|
|
-
|
|
|
|
(4,317
|
)
|
|
|
|
|
|
|
|
|
|
|
(4,317
|
)
|
Non-controlling interests’ distributions, net
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
(105
|
)
|
|
|
-
|
|
|
|
(105
|
)
|
Net income
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
81
|
|
|
|
6,318
|
|
|
|
6,399
|
|
Balances, December 31, 2017
|
|
|
6,006
|
|
|
$
|
60
|
|
|
$
|
58,813
|
|
|
$
|
1,841
|
|
|
$
|
(44,218
|
)
|
|
$
|
16,496
|
|
See
accompanying notes to Consolidated Financial Statements.
CARBON
NATURAL GAS COMPANY
Consolidated
Statements of Cash Flows
(In thousands)
|
|
Twelve months ended
December 31,
|
|
|
|
2017
|
|
|
2016
|
|
|
|
|
|
|
|
|
Cash flows from operating activities:
|
|
|
|
|
|
|
Net income (loss)
|
|
$
|
6,399
|
|
|
$
|
(12,819
|
)
|
Items not involving cash:
|
|
|
|
|
|
|
|
|
Depreciation, depletion and amortization
|
|
|
2,544
|
|
|
|
1,953
|
|
Accretion of asset retirement obligations
|
|
|
307
|
|
|
|
176
|
|
Impairment of oil and gas properties
|
|
|
-
|
|
|
|
4,299
|
|
Unrealized commodity derivative (gain) loss
|
|
|
(2,158
|
)
|
|
|
2,490
|
|
Warrant derivative gain
|
|
|
(3,133
|
)
|
|
|
-
|
|
Stock-based compensation expense
|
|
|
1,106
|
|
|
|
2,440
|
|
Investment in affiliates gain
|
|
|
(1,128
|
)
|
|
|
17
|
|
Amortization of debt issuance costs
|
|
|
176
|
|
|
|
-
|
|
Other
|
|
|
(109
|
)
|
|
|
(47
|
)
|
Net change in:
|
|
|
|
|
|
|
|
|
Accounts receivable
|
|
|
(812
|
)
|
|
|
(2,925
|
)
|
Prepaid expenses, deposits and other current assets
|
|
|
(477
|
)
|
|
|
(93
|
)
|
Accounts payable, accrued liabilities and firm transportation
contracts
|
|
|
1,205
|
|
|
|
1,367
|
|
Net cash provided by (used in) operating activities
|
|
|
3,920
|
|
|
|
(3,142
|
)
|
|
|
|
|
|
|
|
|
|
Cash flows from investing activities:
|
|
|
|
|
|
|
|
|
Development and acquisition of properties and equipment
|
|
|
(1,591
|
)
|
|
|
(700
|
)
|
Acquisition of oil and gas properties
|
|
|
-
|
|
|
|
(8,117
|
)
|
Proceeds from sale of oil and gas properties and other assets
|
|
|
16
|
|
|
|
8
|
|
Other long-term assets
|
|
|
(161
|
)
|
|
|
(285
|
)
|
Investment in affiliates
|
|
|
(6,797
|
)
|
|
|
340
|
|
Net cash used in investing activities
|
|
|
(8,533
|
)
|
|
|
(8,754
|
)
|
|
|
|
|
|
|
|
|
|
Cash flows from financing activities:
|
|
|
|
|
|
|
|
|
Vested restricted stock exchanged for tax withholding
|
|
|
(399
|
)
|
|
|
(267
|
)
|
Proceeds from credit facility
|
|
|
7,210
|
|
|
|
16,937
|
|
Payments on credit facility
|
|
|
(1,300
|
)
|
|
|
(4,207
|
)
|
Distribution to non-controlling interests
|
|
|
(106
|
)
|
|
|
(14
|
)
|
Net cash provided by financing activities
|
|
|
5,405
|
|
|
|
12,449
|
|
|
|
|
|
|
|
|
|
|
Net increase in cash and cash equivalents
|
|
|
792
|
|
|
|
553
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents, beginning of period
|
|
|
858
|
|
|
|
305
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents, end of period
|
|
$
|
1,650
|
|
|
$
|
858
|
|
See
Note 15 – Supplemental Cash Flow Disclosure
See
accompanying notes to Consolidated Financial Statements.
Note
1 – Organization
Carbon Natural Gas Company’s and
its subsidiaries’ (referred to herein as “we”, “us”, or “Carbon”) business is comprised
of the assets and properties of us and our subsidiaries as well as our equity investments in Carbon Appalachian Company, LLC (“Carbon
Appalachia”) and Carbon California Company, LLC (“Carbon California”).
Appalachian and
Illinois Basin Operations
In the Appalachian
and Illinois Basins, Nytis Exploration Company, LLC (“Nytis LLC”) conducts operations for us and Carbon Appalachia.
The following illustrates this relationship as of December 31, 2017.
Ventura Basin
Operations
In California, Carbon California Operating
Company, LLC (“CCOC”), conducts Carbon California’s operations. The following illustrates this relationship
as of December 31, 2017. On February 1, 2018, Yorktown exercised the California Warrant, resulting in our aggregate sharing percentage
in Carbon California increasing from 17.81% to 56.40%. See Note 17.
Collectively, references
to us include CCOC, Nytis Exploration (USA) Inc. (“Nytis USA”) and Nytis LLC.
Note 2 –
Reverse Stock Split
Effective March
15, 2017 and pursuant to a reverse stock split approved by the shareholders and Board of Directors, each 20 shares of our issued
and outstanding common stock became one share of common stock and no fractional shares were issued. The accompanying financial
statements and related disclosures give retroactive effect to the reverse stock split for all periods presented. In connection
with the reverse stock split, the number of authorized shares of our common stock was decreased from 200,000,000 to 10,000,000.
Note 3 –
Summary of Significant Accounting Policies
Accounting policies
used by us reflect industry practices and conform to accounting principles generally accepted in the United States of America
(“GAAP”). The more significant of such accounting policies are briefly discussed below.
Principles of
Consolidation
The consolidated financial statements
include the accounts of us and our consolidated subsidiaries. We own 100% of Nytis USA. Nytis USA owns approximately 99 % of Nytis
LLC. Nytis LLC holds interests in various oil and gas partnerships.
For partnerships where we have a controlling
interest, the partnerships are consolidated. We are currently consolidating 46 partnerships, and we reflect the non-controlling
ownership interest in partnerships and subsidiaries as non-controlling interests on our consolidated statements of operations
and also reflects the non-controlling ownership interest in the net assets of the partnerships as non-controlling interests within
stockholders’ equity on our consolidated balance sheets. All significant intercompany accounts and transactions have been
eliminated.
In accordance with established practice
in the oil and gas industry, our consolidated financial statements also include our pro-rata share of assets, liabilities, income,
lease operating costs and general and administrative expenses of the oil and gas partnerships in which we have a non-controlling
interest.
Non-majority owned investments that do
not meet the criteria for pro-rata consolidation are accounted for using the equity method when we have the ability to significantly
influence the operating decisions of the investee. When we do not have the ability to significantly influence the operating decisions
of an investee, the cost method is used. All transactions, if any, with investees have been eliminated in the accompanying consolidated
financial statements.
Cash and Cash Equivalents
Cash and cash equivalents, if any, in
excess of daily requirements have been generally invested in money market accounts, certificates of deposits and other cash equivalents
with maturities of three months or less. Such investments are deemed to be cash equivalents for purposes of the consolidated financial
statements. The carrying amount of cash equivalents approximates fair value because of the short maturity and high credit quality
of these investments.
Accounts Receivable
We grant credit to all qualified customers,
which potentially subjects us to credit risk resulting from, among other factors, adverse changes in the industries in which we
operate and the financial condition of our customers. We continuously monitor collections and payments from our customers and
maintains an allowance for doubtful accounts based upon our historical experience and any specific customer collection issues
that it has identified.
At December 31, 2017 and 2016, we had
not identified any collection issues related to our oil and gas operations and consequently no allowance for doubtful accounts
was provided for on those dates. In addition, as of December 31, 2016, accounts receivable included a deposit of $1.7 million
made by us on the purchase of assets in the Ventura Basin of California through Carbon California. The deposit was reimbursed
to us upon the consummation of the acquisition by Carbon California on February 15, 2017. See Note 4 for additional information.
Revenue
Our accounts receivable - Revenue is comprised
of oil and natural gas revenues from producing activities.
Joint Interest Billings and Other
Our accounts receivable – joint
interest billings and other is comprised of receivables due from other exploration and production companies and individuals who
own working interests in the properties that we operate. For receivables from joint interest owners, we typically have the ability
to withhold future revenues disbursements to recover any non-payment of joint-interest billings.
The Company recognizes an asset or a liability,
whichever is appropriate, for revenues associated with over-deliveries or under-deliveries of natural gas to purchasers. As of
December 31, 2017, there was an imbalance due to us in the amount of approximately $193,000.
Due from Related party
Our receivables – due from related
party are comprised of receivables from Carbon California and Carbon Appalachia in our role as manager and operator of these entities.
See Note 16.
Prepaid Expense, Deposits, and Other
Current Assets
Our prepaid expense, deposit, and other
current asset account is comprised of prepaid insurance, the current portion of unamortized Credit Facilities issuance costs and
deposits.
Oil and Natural Gas Sales
We sell our oil and natural gas production
to various purchasers in the industry. The table below presents purchasers that account for 10% or more of total oil and natural
gas sales for the years ended December 31, 2017 and 2016. There are several purchasers in the areas where we sell our production.
We do not believe that changing our primary purchasers or a loss of any other single purchaser would materially impact our business.
|
|
For the years ended
December 31,
|
|
Purchaser
|
|
2017
|
|
|
2016
|
|
Purchaser A
|
|
|
23
|
%
|
|
|
4
|
%
|
Purchaser B
|
|
|
17
|
%
|
|
|
15
|
%
|
Purchaser C
|
|
|
12
|
%
|
|
|
18
|
%
|
Purchaser D
|
|
|
11
|
%
|
|
|
16
|
%
|
Purchaser E
|
|
|
8
|
%
|
|
|
17
|
%
|
We recognize an asset or a liability,
whichever is appropriate, for revenues associated with over-deliveries or under-deliveries of natural gas to purchasers. A purchaser
imbalance asset occurs when we deliver more natural gas than we nominated to deliver to the purchaser and the purchaser pays only
for the nominated amount. Conversely, a purchaser imbalance liability occurs when we deliver less natural gas than we nominated
to deliver to the purchaser and the purchaser pays for the amount nominated. As of December 31, 2017 and 2016, we had a purchaser
imbalance receivable of $193,000 within trade receivables and purchaser imbalance payable of approximately $25,000 within accounts
payable and accrued expenses, respectively, which are recognized as a current asset and current liability, respectively, in our
consolidated balance sheets. Purchaser A comprises of approximately 23% of total accounts receivable as of December 31, 2017.
Accounting for Oil and Gas Operations
We use the full cost method of accounting
for oil and gas properties. Accordingly, all costs related to the acquisition, exploration and development of oil and gas properties,
including costs of undeveloped leasehold, dry holes and leasehold equipment, are capitalized. Overhead costs incurred that are
directly identified with acquisition, exploration and development activities undertaken by us for our own account, and which are
not related to production, general corporate overhead or similar activities, are also capitalized.
Unproved properties
are excluded from amortized capitalized costs until it is determined whether or not proved reserves can be assigned to such properties.
We assess our unproved properties for impairment at least annually. Significant unproved properties are assessed individually.
Capitalized costs
are depleted by an equivalent unit-of-production method, converting gas to oil at the ratio of six thousand cubic feet of natural
gas to one barrel of oil. Depletion is calculated using capitalized costs, including estimated asset retirement costs, plus estimated
future expenditures (based on current costs) to be incurred in developing proved reserves, net of estimated salvage values.
No gain or loss
is recognized upon disposal of oil and gas properties unless such disposal significantly alters the relationship between capitalized
costs and proved reserves. All costs related to production activities, including work-over costs incurred solely to maintain or
increase levels of production from an existing completion interval, are charged to expense as incurred.
We perform a ceiling test quarterly. The
full cost ceiling test is a limitation on capitalized costs prescribed by SEC Regulation S-X Rule 4-10. The ceiling test is not
a fair value-based measurement, rather it is a standardized mathematical calculation. The ceiling test provides that capitalized
costs less related accumulated depletion and deferred income taxes may not exceed the sum of (1) the present value of future net
revenue from estimated production of proved oil and gas reserves using the un-weighted arithmetic average of the first-day-of-the
month price for the previous twelve month period, excluding the future cash outflows associated with settling asset retirement
obligations that have been accrued on the balance sheet, at a discount factor of 10%; plus (2) the cost of properties not being
amortized, if any; plus (3) the lower of cost or estimated fair value of unproved properties included in the costs being amortized,
if any; less (4) income tax effects related to differences in the book and tax basis of oil and gas properties. Should the net
capitalized costs exceed the sum of the components noted above, a ceiling test write-down or impairment would be recognized to
the extent of the excess capitalized costs. Such impairments are permanent and cannot be recovered in future periods even if the
sum of the components noted above exceeds capitalized costs in future periods.
For the year ended December 31, 2017,
we did not recognize a ceiling test impairment as our full cost pool did not exceed the ceiling limitations. For the year ended
December 31, 2016, we recognized a ceiling test impairment of approximately $4.3 million as our full cost pool exceeded its ceiling
limitations. Future declines in oil and natural gas prices, increases in future operating expenses and future development costs
could result in impairments of our oil and gas properties in future periods. Impairment changes are a non-cash charge and accordingly
would not affect cash flows but would adversely affect our net income and shareholders’ equity.
We capitalize interest in accordance with
Financial Accounting Standards Board (“FASB”) ASC 932-835-25, Extractive Activities-Oil and Gas, Interest. Therefore,
interest is capitalized for any unusually significant investments in unproved properties or major development projects not currently
being depleted. We capitalize the portion of general and administrative costs that is attributable to our acquisition, exploration
and development activities.
Other Property and Equipment
Other property and equipment are recorded
at cost upon acquisition and include office equipment, computer equipment, building, field equipment, vehicles, and software.
Depreciation of other property and equipment is calculated over three to seven years using the straight-line method.
Long-Lived Assets
We review our long-lived assets other
than oil and gas properties for impairment whenever events or changes in circumstances indicate that the carrying amount of the
asset may not be recovered. We look primarily to the estimated undiscounted future cash flows in our assessment of whether or
not long-lived assets have been impaired.
Other Long-Term Assets
Our other long-term assets are comprised
of bonds, the long-term portion of deferred debt issue and financing costs and the long-term portion of our commodity derivative
liability.
Investments in Affiliates
Investments in non-consolidated affiliates
are accounted for under either the cost or equity method of accounting, as appropriate. The cost method of accounting is generally
used for investments in affiliates in which we have less than 20% of the voting interests of a corporate affiliate or less than
a 3% to 5% interest of a partnership or limited liability company and do not have significant influence. Investments in non-consolidated
affiliates, accounted for using the cost method of accounting, are recorded at cost and impairment assessments for each investment
are made annually to determine if a decline in the fair value of the investment, other than temporary, has occurred. A permanent
impairment is recognized if a decline in the fair value occurs.
If we hold between 20% and 50% of the
voting interest in non-consolidated corporate affiliates or generally greater than a 3% to 5% interest of a partnership or limited
liability company and exert significant influence or control (e.g., through our influence with a seat on the board of directors
or management of operations), the equity method of accounting is generally used to account for the investment. Investment in affiliates
will increase or decrease by our share of the affiliates’ profits or losses and such profits or losses are recognized in
our consolidated statements of operations. If we hold greater than 50% of voting shares, we will generally consolidate the entities
under the voting interest model. For our investments in Carbon Appalachia and Carbon California, we use the hypothetical liquidation
at book value (“HLBV”) method to recognize our share of profits or losses. We review equity method investments for
impairment whenever events or changes in circumstances indicate that “an other than temporary” decline in value has
occurred.
Related Party
Transactions
Management Reimbursements
In our role as manager of Carbon California
and Carbon Appalachia, we receive management reimbursements. These reimbursements are included in general and administrative –
related party reimbursement on our consolidated statement of operations.
Operating Reimbursements
In our role as operator of Carbon California
and Carbon Appalachia, we receive reimbursements of operating expenses. These expenses are recorded directly to receivable –
related party on our consolidated balance sheets and are therefore not included in our operating expenses on our consolidated
statements of operations (see Note 16).
Warrant Liability
We issued warrants related to investments
in Carbon California and Carbon Appalachia. We account for these warrants in accordance with guidance contained in Accounting
Standards Codification (“ASC”) 815,
Derivatives and Hedging
, which requires these warrants to be recorded on
the balance sheet as either an asset or a liability measured at fair value, with changes in fair value recognized in earnings.
Accordingly, we classified the warrants as liabilities. The warrants are subject to remeasurement at each balance sheet date,
with any change in the fair value recognized as a component of other income or expense in the consolidated statement of operations.
For the year ended December 31, 2017, changes in the fair value of warrants accounted for gains of approximately $3.1 million.
Asset Retirement
Obligations
Our asset retirement
obligations (“ARO”) relate to future costs associated with the plugging and abandonment of oil and gas wells, removal
of equipment and facilities from leased acreage and returning such land to its original condition. The fair value of a liability
for an ARO is recorded in the period in which it is incurred, and the cost of such liability is recorded as an increase in the
carrying amount of the related long-lived asset by the same amount. The liability is accreted each period and the capitalized
cost is depleted on a units-of-production basis as part of the full cost pool. Revisions to estimated AROs result in adjustments
to the related capitalized asset and corresponding liability.
The estimated ARO
liability is based on estimated economic lives, estimates as to the cost to abandon the wells in the future, and federal and state
regulatory requirements. The liability is discounted using a credit-adjusted risk-free rate estimated at the time the liability
is incurred or increased as a result of a reassessment of expected cash flows and assumptions inherent in the estimation of the
liability. Upward revisions to the liability could occur due to changes in estimated abandonment costs or well economic lives,
or if federal or state regulators enact new requirements regarding the abandonment of wells. AROs are valued utilizing Level 3
fair value measurement inputs (see Note 11).
The
following table is a reconciliation of the ARO for the years ended December 31, 2017 and 2016.
|
|
Year Ended December 31,
|
|
(in thousands)
|
|
2017
|
|
|
2016
|
|
|
|
|
|
|
|
|
Balance at beginning of year
|
|
$
|
5,120
|
|
|
$
|
3,095
|
|
Accretion expense
|
|
|
307
|
|
|
|
176
|
|
Change in estimate of cash outflow
|
|
|
2,402
|
|
|
|
|
|
Additions during period
|
|
|
-
|
|
|
|
1,849
|
|
Less: sale of wells
|
|
|
(92
|
)
|
|
|
-
|
|
|
|
|
7,737
|
|
|
|
5,120
|
|
Less: ARO recognized as accounts payable and accrued liabilities
|
|
|
(380
|
)
|
|
|
(114
|
)
|
Balance at end of year
|
|
$
|
7,357
|
|
|
$
|
5,006
|
|
For the year ended December 31, 2017,
we did not have any additions of ARO compared to $1.8 million in 2016, which was primarily due to the acquisition of producing
oil and natural gas properties in the Appalachian Basin. During the year ended December 31, 2017, we increased the estimated cost
of retirement obligations for certain wells in the Appalachian Basin. Our estimated costs range from $20,000 to $30,000, which
is a better representation of current prices of supplies and services. This increase to estimated costs resulted in a $2.4 million
increase to our ARO in 2017.
Financial Instruments
Our financial instruments include cash
and cash equivalents, accounts receivables, accounts payables, accrued liabilities, commodity derivative instruments, warrant
liability, and our credit facility. The carrying value of cash and cash equivalents, accounts receivable, accounts payables and
accrued liabilities are representative of their fair value, due to the short maturity of these instruments. Our commodity derivative
instruments are recorded at fair value, as discussed below and in Note 11. The carrying amount of our credit facility approximated
fair value since borrowings bear interest at variable rates, which are representative of our credit adjusted borrowing rate.
Commodity Derivative
Instruments
We enter into commodity
derivative contracts to manage our exposure to oil and natural gas price volatility with an objective to reduce exposure to downward
price fluctuations. Commodity derivative contracts may take the form of futures contracts, swaps, collars or options. We have
elected not to designate our derivatives as cash flow hedges. All derivatives are initially and subsequently measured at estimated
fair value and recorded as assets or liabilities on the consolidated balance sheets and the changes in fair value are recognized
as gains or losses in revenues in the consolidated statements of operations.
Income Taxes
We account for income taxes using the
asset and liability method, whereby deferred tax assets and liabilities are recognized for the future tax consequences attributable
to differences between the financial statement carrying amounts of assets and liabilities and their respective tax basis, as well
as the future tax consequences attributable to the future utilization of existing tax net operating losses and other types of
carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in
the years in which those temporary differences and carryforwards are expected to be recovered or settled. The effect on deferred
tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date. With
the passage of the Tax Cut and Jobs Act (“TCJA”), we are required to remeasure deferred income taxes at the lower
21% corporate rate as of the date the TCJA was signed into law even though the reduced rate is effective January 1, 2018.
We account for uncertainty
in income taxes for tax positions taken or expected to be taken in a tax return. Only tax positions that meet the more likely
than not recognition threshold are recognized.
Stock - Based
Compensation
Compensation cost is measured at the grant
date, based on the fair value of the awards and is recognized on a straight-line basis over the requisite service period (usually
the vesting period). For performance units, since these awards are settled in cash at the end of a defined performance period,
they are measured quarterly and expensed over the remaining vesting period.
Revenue Recognition
Oil and natural gas revenues are recognized
when production volumes are sold to a purchaser at a fixed or determinable price, delivery has occurred, title has transferred
and collectability is reasonably assured. Natural gas revenues are recognized on the basis of our net working revenue interest.
Earnings Per
Common Share
Basic earnings per common share is computed
by dividing the net income (loss) attributable to common stockholders for the period by the weighted average number of common
shares outstanding during the period. The shares of restricted common stock granted to our officers, directors and employees are
included in the computation of basic net income per share only after the shares become fully vested. Diluted earnings per common
share includes both the vested and unvested shares of restricted stock and the potential dilution that could occur upon exercise
of options and warrants to acquire common stock computed using the treasury stock method, which assumes that the increase in the
number of shares is reduced by the number of shares which could have been repurchased by us with the proceeds from the exercise
of options and warrants (which were assumed to have been made at the average market price of the common shares during the reporting
period).
The following table
sets forth the calculation of basic and diluted income (loss) per share:
|
|
For the Year Ended
December 31,
|
|
(in thousands except per share amounts)
|
|
2017
|
|
|
2016
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
$
|
6,318
|
|
|
$
|
(12,406
|
)
|
Less: warrant derivative gain
|
|
|
(3,133
|
)
|
|
|
-
|
|
Diluted net income
|
|
|
3,185
|
|
|
|
(12,406
|
)
|
|
|
|
|
|
|
|
|
|
Basic weighted-average common shares outstanding during the period
|
|
|
5,662
|
|
|
|
5,468
|
|
|
|
|
|
|
|
|
|
|
Add dilutive effects of warrants and non-vested shares of restricted stock
|
|
|
790
|
|
|
|
-
|
|
|
|
|
|
|
|
|
|
|
Diluted weighted-average common shares outstanding during the period
|
|
|
6,452
|
|
|
|
5,468
|
|
|
|
|
|
|
|
|
|
|
Basic net (loss) income per common share
|
|
$
|
1.12
|
|
|
$
|
(2.27
|
)
|
Diluted net (loss) income per common share
|
|
$
|
0.49
|
|
|
$
|
(2.27
|
)
|
For the year ended December 31, 2017,
we had net income and the diluted loss per common share calculation includes the anti-dilutive effects of approximately 519,000
warrants and approximately 271,000 non-vested shares of restricted stock. In addition, approximately 259,000 restricted performance
units subject to future contingencies were excluded in the basic and diluted loss per share calculations. For the year ended December
31, 2016, we had a net loss and therefore the diluted loss per common share calculation excludes the anti-dilutive effects of
approximately 13,000 warrants and approximately 268,000 non-vested shares of restricted stock. In addition, approximately 296,000
restricted performance units subject to future contingencies were excluded from the basic and diluted loss per share calculations.
Oil and Gas Reserves
Oil and gas reserves represent theoretical
quantities of crude oil, natural gas, and natural gas liquids (“NGL”) which geological and engineering data demonstrate
with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions.
There are numerous uncertainties inherent in estimating oil and gas reserves and their values, including many factors beyond our
control. Accordingly, reserve estimates and the projected economic value of our and our equity investees’ properties will
differ from the actual future quantities of oil and gas ultimately recovered and the corresponding value associated with the recovery
of these reserves.
Use of Estimates
in the Preparation of Financial Statements
The preparation of financial statements
in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities
and expenses and disclosure of contingent assets and liabilities. Significant items subject to such estimates and assumptions
include the carrying value of oil and gas properties, the estimate of proved oil and gas reserve volumes and the related depletion
and present value of estimated future net cash flows and the ceiling test applied to capitalized oil and gas properties, determining
the amounts recorded for deferred income taxes, stock-based compensation, fair value of commodity derivative instruments, fair
value of warrants, fair value of equity method investments, fair value of assets acquired and liabilities assumed qualifying as
business contributions and asset retirement obligations. Actual results could differ from those estimates and assumptions used.
Adopted and Recently
Issued Accounting Pronouncements
In January 2017,
the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2017-01,
Business Combinations (Topic 805)
. This ASU clarifies the definition of a business with the objective of adding guidance
to assist entities with evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses.
This guidance is to be applied using a prospective method and is effective for annual periods, and interim periods within those
annual periods, beginning after December 15, 2017. Early adoption is permitted as outlined in ASU 2017-01. We elected to early
adopt this pronouncement effective January 1, 2017.
In August 2016,
the FASB issued ASU 2016-15,
Statement of Cash Flows-Classification of Certain Cash Receipts and Cash Payments
. The objective
of this update is intended to reduce the diversity in practice as to how certain cash receipts and cash payments are presented
and classified in the statement of cash flows by providing guidance for several specific cash flow issues. ASU 2016-15 is effective
for the annual periods beginning after December 15, 2017, and interim periods within those annual periods. We are currently evaluating
the impact of adopting this standard.
In February 2016,
the FASB issued ASU 2016-02,
Leases.
The objective of this ASU is to increase transparency and comparability among organizations
by recognizing lease assets and liabilities on the balance sheet and disclosing key information about leasing arrangements. This
update requires lessees to recognize a lease liability and a lease asset for all leases, including operating leases, with a term
greater than twelve months on its balance sheet. The update also expands the required quantitative and qualitative disclosures
surrounding leases. This update is effective for fiscal years beginning after December 15, 2018 and interim periods within those
fiscal years and should be applied using a modified retrospective approach. Early adoption is permitted. We have not yet determined
what the effects of adopting this updated guidance will be on our consolidated financial statements.
In November 2015,
the FASB issued ASU 2015-17,
Balance Sheet Classification of Deferred Taxes
. The objective of this update is to require
deferred tax liabilities and assets to be classified as noncurrent in a classified statement of financial position. ASU 2015-17
is effective for annual periods beginning after December 15, 2016, and interim periods within those annual periods. The standard
was adopted on January 1, 2017 and did not have a significant impact on our disclosures and financial statements.
In May 2014, the FASB issued ASU 2014-09,
Revenue from Contracts with Customers
. The objective of ASU 2014-09 is to clarify the principles for recognizing revenue
and to develop a common revenue standard for U.S. GAAP and International Financial Reporting Standards. The FASB subsequently
issued ASU 2015-14, ASU 2016-08, ASU 2016-10, ASU 2016-12 and ASU 2016-20, which deferred the effective date of ASU 2014-09 and
provided additional implementation guidance. These ASUs are effective for fiscal years, and interim periods within those years,
beginning after December 15, 2019. The standards permit retrospective application using either of the following methodologies:
(i) restatement of each prior reporting period presented or (ii) recognition of a cumulative-effect adjustment as of the date
of initial application. We plan to adopt ASU 2014-09 effective January 1, 2018. We have elected to use the modified retrospective
method for adoption. We are in the process of assessing our contracts with customers and evaluating the effect of adopting these
standards on our financial statements, accounting policies, internal controls and disclosures. The adoption is not expected to
have a significant impact on our results of operations or cash flows, however, we are currently evaluating the proper classification
of certain pipeline gathering, transportation and gas processing agreements to determine whether reclassifications to total revenues
and expenses will be necessary under the new standards.
Note 4 –
Acquisitions and Divestitures
Acquisitions
In October 2016, Nytis LLC completed the
EXCO Acquisition consisting of producing natural gas wells and natural gas gathering facilities located in our Appalachian Basin
operating area. The natural gas gathering facilities are primarily used to gather our natural gas production. The acquisition
was pursuant to a purchase and sale agreement effective October 1, 2016 (the “EXCO Purchase Agreement”) by and among
EXCO Production Company (WV), LLC, BG Production Company (WV), LLC and EXCO Resources (PA) LLC (collectively the “Sellers”)
and Nytis LLC, as the buyer. The purchase price of the acquired assets pursuant to the EXCO Purchase Agreement was $9.0 million
subject to customary closing adjustments and the assumption of certain obligations.
The EXCO Acquisition provided us with
proved developed reserves, production and operating cash flow in locations where we have similar assets.
The EXCO Acquisition qualified as a business
combination and as such, we estimated the fair value of the assets acquired and liabilities assumed as of the Closing Date. We
considered various factors in our estimate of fair value of the acquired assets including (i) reserves, (ii) production rates,
(iii) future operating and development costs, (iv) future commodity prices, including price differentials, (v) future cash flows,
and (vi) a market participant-based weighted average cost of capital.
We expensed approximately $501,000 of
transaction and due diligence costs related to the EXCO Acquisition that were included in general and administrative expenses
in the accompanying consolidated statement of operations for the year ended December 31, 2016.
The following table summarizes the consideration
paid to the Sellers and the estimated fair value of the assets acquired and liabilities assumed.
Consideration paid to Sellers:
|
|
|
|
Cash consideration
|
|
$
|
8,117
|
|
|
|
|
|
|
Recognized amounts of identifiable assets acquired and liabilities assumed:
|
|
|
|
|
Proved oil and gas properties and related support facilities
|
|
$
|
12,656
|
|
Asset retirement obligations
|
|
|
(1,845
|
)
|
Working capital
|
|
|
(2,694
|
)
|
Total identified net assets
|
|
$
|
8,117
|
|
Below are consolidated results of operations
for the year ended December 31, 2016 as though the EXCO Acquisition had been completed as of January 1, 2016. The EXCO Acquisition
closed October 3, 2016, and accordingly, our consolidated statement of operations for the year ended December 31, 2017 includes
the results of operations for the year ended December 31, 2017 of the EXCO properties acquired.
|
|
Unaudited Pro Forma Consolidated Results For Year Ended December 31,
|
|
(in thousands, except per share amounts)
|
|
2016
|
|
Revenue
|
|
$
|
13,963
|
|
Net income (loss) income before non-controlling interests
|
|
|
(6,825
|
)
|
Net income (loss) attributable to non-controlling interests
|
|
|
413
|
|
Net income (loss) attributable to controlling interests
|
|
$
|
(6,412
|
)
|
Net income (loss) per share (basic)
|
|
$
|
(1.17
|
)
|
Net income (loss) per share (diluted)
|
|
$
|
(1.17
|
)
|
Note 5 –
Property and Equipment
Net
property and equipment at December 31, 2017 and 2016 consists of the following:
(in thousands)
|
|
As of December 31,
|
|
|
|
2017
|
|
|
2016
|
|
|
|
|
|
|
|
|
Oil and gas properties:
|
|
|
|
|
|
|
Proved oil and gas properties
|
|
$
|
114,893
|
|
|
$
|
111,771
|
|
Unproved properties not subject to depletion
|
|
|
1,947
|
|
|
|
1,999
|
|
Accumulated depreciation, depletion, amortization
and impairment
|
|
|
(80,715
|
)
|
|
|
(78,559
|
)
|
Net oil and gas properties
|
|
|
36,125
|
|
|
|
35,211
|
|
|
|
|
|
|
|
|
|
|
Furniture and fixtures, computer hardware and software,
and other equipment
|
|
|
1,758
|
|
|
|
990
|
|
Accumulated depreciation and amortization
|
|
|
(1,021
|
)
|
|
|
(665
|
)
|
Net other property and equipment
|
|
|
737
|
|
|
|
325
|
|
|
|
|
|
|
|
|
|
|
Total property and equipment, net
|
|
$
|
36,862
|
|
|
$
|
35,536
|
|
We had approximately
$1.9 million and $2.0 million, at December 31, 2017 and 2016, respectively, of unproved oil and gas properties not subject to
depletion. At December 31, 2017 and 2016, our unproved properties consist principally of leasehold acquisition costs in the following
areas:
|
|
As of December 31,
|
|
(in thousands)
|
|
2017
|
|
|
2016
|
|
|
|
|
|
|
|
|
Illinois Basin:
|
|
|
|
|
|
|
|
|
Indiana
|
|
$
|
432
|
|
|
$
|
431
|
|
Illinois
|
|
|
136
|
|
|
|
298
|
|
Appalachian Basin:
|
|
|
|
|
|
|
|
|
Kentucky
|
|
|
915
|
|
|
|
750
|
|
Ohio
|
|
|
66
|
|
|
|
66
|
|
West Virginia
|
|
|
398
|
|
|
|
454
|
|
|
|
|
|
|
|
|
|
|
Total unproved properties not subject to depletion
|
|
$
|
1,947
|
|
|
$
|
1,999
|
|
During the years ended December 31, 2017
and 2016, expiring leasehold costs reclassified into proved property were approximately $52,000 and $1.3 million, respectively.
The costs not subject to depletion relate to unproved properties that are excluded from amortized capital costs until it is determined
whether or not proved reserves can be assigned to such properties. These costs do not relate to any individually significant projects.
The excluded properties are assessed for impairment at least annually.
We capitalized overhead
applicable to acquisition, development and exploration activities of approximately $66,000 and $562,000 for the years ended December
31, 2017 and 2016, respectively.
Depletion expense
related to oil and gas properties for the years ended December 31, 2017 and 2016 was approximately $2.2 million and $1.8 million
or $0.40 and $0.56 per Mcfe, respectively. Depreciation expense related to furniture and fixtures, computer hardware and software
and other equipment for the years ended December 31, 2017 and 2016 was approximately $387,000 and $114,000, respectively.
Note 6 –
Investments in Affiliates
Carbon California
Carbon California was formed in 2016 by
us, entities managed by Yorktown and Prudential, to acquire producing assets in the Ventura Basin in California. On February 15,
2017, we, Yorktown and Prudential entered into a limited liability company agreement (the “Carbon California LLC Agreement”)
of Carbon California, a Delaware limited liability company.
Prior to February 1, 2018, we held 17.81%
of the voting and profits interests, Yorktown held 38.59% of the voting and profits interests and Prudential held 43.59% of the
voting and profits interests in Carbon California. On February 1, 2018, Yorktown exercised the California Warrant, pursuant to
which Yorktown obtained additional shares of common stock in us in exchange for the transfer and assignment by Yorktown of all
of its rights in Carbon California. Following the exercise of the California Warrant by Yorktown, we own 56.41% of the voting
and profits interests, and Prudential holds the remainder of the interests, in Carbon California.
Pursuant to the Carbon California LLC
Agreement, we initially acquired a 17.81% interest in Carbon California represented by Class B Units. The Class B Units were acquired
for no cash consideration. No further equity commitments have been made or are required by us under the Carbon California LLC
Agreement, prior to February 1, 2018.
On February 15, 2017, Carbon California (i) issued and sold Class A Units to Yorktown
and Prudential for an aggregate cash consideration of $22.0 million, (ii) entered into a Note Purchase Agreement (the “Note
Purchase Agreement”) with Prudential Legacy Insurance Company of New Jersey and Prudential Insurance Company of America
for the issuance and sale of up to $25.0 million of Senior Secured Revolving Notes (the “Senior Revolving Notes”)
due February 15, 2022 and (iii) entered into a Securities Purchase Agreement (the “Securities Purchase Agreement”)
with Prudential for the issuance and sale of $10.0 million of Senior Subordinated Notes (the “Subordinated Notes”)
due February 15, 2024. We are not a guarantor of the Senior Revolving Notes or the Subordinate Notes.
The closing of the
Note Purchase Agreement and the Securities Purchase Agreement on February 15, 2017, resulted in the sale and issuance by Carbon
California of (i) Senior Revolving Notes in the principal amount of $10.0 million and (ii) Subordinated Notes in the original
principal amount of $10.0 million. The maximum principal amount available under the Senior Revolving Notes is based upon the borrowing
base attributable to Carbon California’s proved oil and gas reserves which is to be determined at least semi-annually. The
current borrowing base is $15.0 million, of which $11.0 million is outstanding as of December 31, 2017.
Net proceeds from
the offering transaction were used by Carbon California to complete the acquisitions of oil and gas assets in the Ventura Basin
of California, which acquisitions also closed on February 15, 2017. The remainder of the net proceeds may be used to fund field
development projects and to fund future complementary acquisitions and for general working capital purposes of Carbon California.
Based on our 17.8% interest in Carbon
California, as of December 31, 2017, our ability to appoint a member to the board of directors and our role of manager of Carbon
California, we are accounting for our investment in Carbon California under the equity method of accounting as we believe we can
exert significant influence. We use the HLBV to determine our share of profits or losses in Carbon California and adjusts the
carrying value of our investment accordingly. The HLBV is a balance-sheet approach that calculates the amount each member of Carbon
California would receive if Carbon California were liquidated at book value at the end of each measurement period. The change
in the allocated amount to each member during the period represents the income or loss allocated to that member. In the event
of liquidation of Carbon California, to the extent that Carbon California has net income, available proceeds are first distributed
to members holding Class A and Class B units and any remaining proceeds are then distributed to members holding Class A units.
For the period February 15, 2017 (inception) through December 31, 2017, Carbon California incurred a net loss of which our share
(as a holder of Class B units for that period) is zero. Should Carbon California generate net income in future periods, we will
not record income (or losses) until our share of such income exceeds the amount of our share of losses not previously reported.
While income may be recorded in future periods, the ability of Carbon California to make distributions to its owners, including
us, is dependent upon the terms of its credit facilities, which currently prohibit distributions unless agreed to by the lender.
In connection with our entry into the
Carbon California LLC Agreement, and Carbon California engaging in the transactions described above, we received the aforementioned
Class B Units and issued to Yorktown the California Warrant. The exercise price for the California Warrant is payable exclusively
with Class A Units of Carbon California held by Yorktown and the number of shares of our common stock for which the California
Warrant is exercisable is determined, as of the time of exercise, by dividing (a) the aggregate unreturned capital of Yorktown’s
Class A Units of Carbon California by (b) the exercise price. The California Warrant had a term of seven years and included certain
standard registration rights with respect to the shares of our common stock issuable upon exercise of the California Warrant.
Yorktown exercised the California Warrant on February 1, 2018.
The issuance of the Class B Units and
the California Warrant were in contemplation of each other, and under non-monetary related party guidance, we accounted for the
California Warrant, at issuance, based on the fair value of the California Warrant as of the date of grant (February 15, 2017)
and recorded a warrant liability with an associated offset to APIC. Future changes to the fair value of the California Warrant
are recognized in earnings. We accounted for the fair value of the Class B Units at their estimated fair value at the date of
grant, which became our investment in Carbon California with an offsetting entry to APIC.
As of the grant date of the California
Warrant, we estimated that the fair market value of the California Warrant was approximately $5.8 million and the fair value of
the Class B Units was approximately $1.9 million. As of December 31, 2017, we estimated that the fair value of the California
Warrant was approximately $2.0 million. The difference in the fair value of the California Warrant from the grant date though
December 31, 2017 was approximately $3.8 million and was recognized in warrant derivative gain in our consolidated statements
of operations for the year ended December 31, 2017.
As of December 31, 2017, Carbon California
was in breach of the covenants for its Senior Revolving Notes and Subordinated Notes; however, it obtained a waiver for the December
31, 2017 and March 31, 2018 covenants. It is anticipated that covenants will be met in the future. See
Liquidity and Management’s
Plans
within Note 1 to the Carbon California financial statements.
The following table
sets forth selected historical financial data for Carbon California.
(in thousands)
|
|
As of December 31, 2017
|
|
Current assets
|
|
$
|
3,968
|
|
Total oil and gas properties, net
|
|
$
|
43,458
|
|
Current liabilities
|
|
$
|
6,899
|
|
Non-current liabilities
|
|
$
|
23,279
|
|
Total members’ equity
|
|
$
|
18,549
|
|
(in thousands)
|
|
February 15, 2017 (Inception) through December 31,
2017
|
|
Revenues
|
|
$
|
7,235
|
|
Operating expenses
|
|
|
9,893
|
|
Loss from operations
|
|
|
(2,658
|
)
|
Net loss
|
|
|
(6,552
|
)
|
Carbon Appalachia
Carbon Appalachia
was formed in 2016 by us, Yorktown and Old Ironsides to acquire producing assets in the Appalachian Basin in Kentucky, Tennessee,
Virginia and West Virginia.
Outlined below is
a summary of i) our contributions, ii) our resulting percent of Class A unit ownership and iii) our overall resulting Sharing
Percentage of Carbon Appalachia after giving effect of all classes of ownership. Holders of units within each class of units participate
in profit or losses and distributions according to their proportionate share of each class of units (“Sharing Percentage”).
Each contribution and its use is described in detail following the table.
Timing
|
|
Capital
Contribution
|
|
Resulting Class A
Units (%)
|
|
Resulting
Sharing %
|
April 2017
|
|
$0.24 million
|
|
2.00%
|
|
2.98%
|
August 2017
|
|
$3.71 million
|
|
15.20%
|
|
16.04%
|
September 2017
|
|
$2.92 million
|
|
18.55%
|
|
19.37%
|
November 2017
|
|
Warrant exercise
|
|
26.50%
|
|
27.24%
|
On April 3, 2017,
we, Yorktown and Old Ironsides Energy, LLC (“
Old Ironsides
”), entered in to a limited liability company
agreement (the “Carbon Appalachia LLC Agreement”), with an initial equity commitment of $100.0 million, of which $37.0
million has been contributed as of December 31, 2017.
Pursuant to the
Carbon Appalachia LLC Agreement, we acquired a 2.0% interest in Carbon Appalachia for $240,000 of Class A Units associated with
our initial equity commitment of $2.0 million. We also have the ability to earn up to an additional 14.7% of Carbon Appalachia
distributions (represented by Class B Units) after certain return thresholds to the holders of Class A Units are met. The Class
B Units were acquired for no cash consideration.
In addition, we acquired a 1.0% interest
represented by Class C Units which were obtained in connection with the contribution to Carbon Appalachia of a portion of its
working interest in undeveloped properties in Tennessee. If Carbon Appalachia agrees to drill horizontal Chattanooga Shale wells
on these properties, it will pay 100% of the cost of drilling and completion of the first 20 wells to earn a 75% working interest
in such properties. We, through our subsidiary, Nytis LLC, will retain a 25% working interest in the properties. There was no
activity associated with these properties in 2017.
In connection with and concurrently with
the closing of the acquisition described below, Carbon Appalachia Enterprises, LLC, formerly known as Carbon Tennessee Company,
LLC (“Carbon Appalachia Enterprises”), a subsidiary of Carbon Appalachia, entered into a 4-year $100.0 million senior
secured asset-based revolving credit facility with LegacyTexas Bank with an initial borrowing base of $10.0 million. We are not
a guarantor of the CAE Credit Facility.
Borrowings under the credit facility,
along with the initial equity contributions made to Carbon Appalachia, were used to complete the acquisition of natural gas producing
properties and related facilities located predominantly in Tennessee (the “CNX Acquisition”). The purchase price was
$20.0 million, subject to normal and customary closing adjustments, and Carbon Appalachia Enterprises used $8.5 million drawn
from the credit facility toward the purchase price.
On August 15, 2017, Carbon Appalachia
completed the acquisition of natural gas producing properties and related facilities located predominantly in the state of West
Virginia (the “Enervest Acquisition”). The purchase price was $21.5 million, subject to normal and customary closing
adjustments.
On August 15, 2017,
the Carbon Appalachia LLC Agreement was amended and restated. Pursuant to the amended and restated Carbon Appalachia LLC Agreement,
we increased our capital commitment in Carbon Appalachia from $2.0 million to $23.6 million and our portion of any subsequent
capital call from 2.0% to 26.5%. Aggregate capital commitments of all members remained at $100.0 million. As each subsequent capital
call is made, Carbon will contribute 26.5%. We are the sole manager of Carbon Appalachia and maintain the ability to earn additional
ownership interests of Carbon Appalachia (represented by Class B Units) after certain thresholds to the holders of Class A Units
are met. We also maintain our 1.0% carried interest represented by Class C Units.
In connection with and concurrently with
the closing of the Enervest Acquisition, the borrowing base of its existing credit facility with LegacyTexas Bank increased to
$22.0 million and Carbon Appalachia Enterprises borrowed $8.0 million from its existing credit facility with LegacyTexas Bank.
Carbon Appalachia received equity funding in the amount of $14.0 million from its members, including $3.7 million from us. The
contributed funds and funds drawn from the credit facility were used to pay the purchase price.
On September 29, 2017, Carbon Appalachia
Enterprises amended its 4-year $100.0 million senior secured asset-based revolving credit facility with LegacyTexas Bank, resulting
in a borrowing base of $50.0 million with redeterminations as of April 1 and October 1 each year and the addition of East West
Bank as a participating lender. As of December 31, 2017, there was approximately $38.0 million outstanding under the credit facility.
On September 29, 2017, Carbon Appalachia
completed the acquisition of natural gas producing properties, natural gas gathering pipelines and related facilities located
predominantly in the state of West Virginia (the “Cabot Acquisition”). The purchase price was $41.3 million, subject
to normal and customary closing adjustments.
In connection with and concurrently with
the closing of the Cabot Acquisition described above, Carbon Appalachia Enterprises borrowed $20.4 million from its credit facility.
Carbon Appalachia received equity funding in the amount of $11.0 million from its members, including $2.9 million from us. The
contributed funds and funds drawn from the credit facility were used to pay the purchase price.
On November 30, 2017, the CAE Credit Facility
was amended to include the addition of Bank SNB as a participating lender.
In connection with our entry into the
Carbon Appalachia LLC Agreement, and Carbon Appalachia engaging in the transactions described above, we received the aforementioned
Class B Units and issued to Yorktown the Appalachia Warrant. The Appalachia Warrant is payable exclusively with Class A Units
of Carbon Appalachia held by Yorktown and the number of shares of our common stock for which the Appalachia Warrant is exercisable
is determined, as of the time of exercise, by dividing (a) the aggregate unreturned capital of Yorktown’s Class A Units
of Carbon Appalachia plus a required 10% internal rate of return by (b) the exercise price.
On November 1, 2017, Yorktown exercised
the Appalachia Warrant, resulting in the issuance of 432,051 shares of our common stock in exchange for Class A Units representing
approximately 7.95% of then outstanding Class A Units of Carbon Appalachia. We accounted for the exercise through extinguishment
of the warrant liability associated with the Appalachia Warrant of approximately $1.9 million and the receipt of Yorktown’s
Class A Units as an increase to investment in affiliates in the amount of approximately $2.9 million. After giving effect to the
exercise, we own 26.5% of Carbon Appalachia’s outstanding Class A Units along with 100% of its Class C Units.
The issuance of the Class B Units and
the Appalachia Warrant were in contemplation of each other, and under non-monetary related party guidance, we accounted for the
Appalachia Warrant, at issuance, based on the fair value of the Appalachia Warrant as of the date of grant (April 3, 2017) and
recorded a warrant liability with an associated offset to APIC. Future changes to the fair value of the Appalachia Warrant are
recognized in earnings. We accounted for the fair value of the Class B Units at their estimated fair value at the date of grant,
which became our investment in Carbon Appalachia with an offsetting entry to APIC.
As of the grant date of the Appalachia
Warrant, we estimated that the fair market value of the Appalachia Warrant was approximately $1.3 million and the fair value of
the Class B Units was approximately $924,000. The difference in the fair value of the Appalachia Warrant from the grant date though
its exercise on November 1, 2017, was approximately $619,000 million and was recognized in warrant derivative gain in the Company’s
consolidated statements of operations for the year ended December 31, 2017.
Based on our 27.24%
combined Class A, Class B and Class C interest (and our ability as of December 31, 2017 to earn up to an additional 14.7%) in
Carbon Appalachia, our ability to appoint a member to the board of directors and our role of manager of Carbon Appalachia, we
are accounting for our investment in Carbon Appalachia under the equity method of accounting as it believes it can exert significant
influence. We use the HLBV to determine its share of profits or losses in Carbon Appalachia and adjusts the carrying value of
its investment accordingly. Our investment in Carbon Appalachia is represented by our Class A and C interests, which it acquired
by contributing approximately $6.9 million in cash and unevaluated property. In the event of liquidation of Carbon Appalachia,
available proceeds are first distributed to members holding Class C Units then to holders of Class A Units until their contributed
capital is recovered with an internal rate of return of 10%. Any additional distributions would then be shared between holders
of Class A, Class B and Class C Units. For the period of April 3, 2017 through December 31, 2017, Carbon Appalachia incurred a
net gain, of which our share is approximately $1.1 million. The ability of Carbon Appalachia to make distributions to its owners,
including us, is dependent upon the terms of its credit facilities, which currently prohibit distributions unless agreed to by
the lender.
As of December 31, 2017, Carbon Appalachia
is in compliance with all CAE Credit Facility covenants.
The following table
sets forth, selected historical financial data for Carbon Appalachia.
(in thousands)
|
|
As of December 31, 2017
|
|
Current assets
|
|
$
|
20,794
|
|
Total oil and gas properties, net
|
|
$
|
84,402
|
|
Current liabilities
|
|
$
|
18,207
|
|
Non-current liabilities
|
|
$
|
59,420
|
|
Total members’ equity
|
|
$
|
40,929
|
|
(in thousands)
|
|
Period April 3,
2017 through December 31,
2017
|
|
Revenues
|
|
$
|
31,584
|
|
Operating expenses
|
|
|
26,764
|
|
Income from operations
|
|
|
4,820
|
|
Net income
|
|
|
3,005
|
|
The following table outlines the changes
in our investments in affiliates:
(in thousands)
|
|
Carbon California
|
|
|
Carbon Appalachia
|
|
|
CCGGC
|
|
|
Sullivan
(1)
|
|
|
Total
|
|
Balance, December 31, 2016
|
|
$
|
-
|
|
|
$
|
-
|
|
|
$
|
118
|
|
|
$
|
550
|
|
|
$
|
668
|
|
Investment in affiliates gain (loss)
|
|
|
-
|
|
|
|
1,090
|
|
|
|
38
|
|
|
|
-
|
|
|
|
1,128
|
|
Cash distributions
|
|
|
-
|
|
|
|
-
|
|
|
|
(68
|
)
|
|
|
-
|
|
|
|
(68
|
)
|
Cash contributions
|
|
|
-
|
|
|
|
6,865
|
|
|
|
-
|
|
|
|
-
|
|
|
|
6,865
|
|
Class B Units issuance
|
|
|
1,854
|
|
|
|
924
|
|
|
|
-
|
|
|
|
-
|
|
|
|
2,778
|
|
Appalachia Warrant exercise
|
|
|
-
|
|
|
|
2,896
|
|
|
|
|
|
|
|
|
|
|
|
2,896
|
|
Balance, December 31, 2017
|
|
$
|
1,854
|
|
|
$
|
11,775
|
|
|
$
|
88
|
|
|
$
|
550
|
|
|
$
|
14,267
|
|
During 2017, we received distributions
of approximately $30,000 from our investment in Sullivan Energy which we account for using the cost method of accounting and,
as such, we recognized a gain within investment in affiliates of $30,000 for the year ended December 31, 2017.
Note 7 –
Bank Credit Facility
In 2016, Carbon entered into a 4-year
$100.0 million senior secured asset-based revolving credit facility with LegacyTexas Bank (the “Credit Facility”).
LegacyTexas Bank is the initial lender and acts as administrative agent.
The Credit Facility has a maximum availability
of $100.0 million (with a $500,000 sublimit for letters of credit), which availability is subject to the amount of the borrowing
base. The initial borrowing base established under the Credit Facility was $17.0 million. The borrowing base is subject to semi-annual
redeterminations in March and September. On March 30, 2017, the borrowing base was increased to $23.0 million. As of December
31, 2017, the borrowing base was $23.0 million.
The Credit Facility is guaranteed by each
existing and future subsidiary of us (subject to certain exceptions). The obligations of us and the subsidiary guarantors under
the Credit Facility are secured by essentially all of our tangible and intangible personal and real property (subject to certain
exclusions).
Interest is payable quarterly and accrues
on borrowings under the Credit Facility at a rate per annum equal to either (i) the base rate plus an applicable margin between
0.50% and 1.50% or (ii) the Adjusted LIBOR rate plus an applicable margin between 3.50% and 4.50% at our option. The actual margin
percentage is dependent on the Credit Facility utilization percentage. We are obligated to pay certain fees and expenses in connection
with the Credit Facility, including a commitment fee for any unused amounts of 0.50%.
The Credit Facility contains certain affirmative
and negative covenants that, among other things, limit our ability to (i) incur additional debt; (ii) incur additional liens;
(iii) sell, transfer or dispose of assets; (iv) merge or consolidate, wind-up, dissolve or liquidate; (v) make dividends and distributions
on, or repurchases of, equity; (vi) make certain investments; (vii) enter into certain transactions with our affiliates; (viii)
enter into sales-leaseback transaction; (ix) make optional or voluntary payment of debt; (x) change the nature of our business;
(xi) change our fiscal year to make changes to the accounting treatment or reporting practices; (xii) amend constituent documents;
and (xiii) enter into certain hedging transactions.
The affirmative and negative covenants
are subject to various exceptions, including certain basket amounts and acceptable transaction levels. In addition, the Credit
Facility requires Carbon’s compliance, on a consolidated basis, with (i) a maximum Debt/EBITDA ratio of 3.5 to 1.0 and (ii)
a minimum current ratio of 1.0 to 1.0, commencing with the quarter ended March 31, 2017.
In the third quarter of 2017, we contributed
approximately $6.6 million to Carbon Appalachia to fund its share of producing oil and gas properties acquired during the third
quarter. This funding was provided primarily with borrowings under the Credit Facility. The Debt/EBITDA and current ratio covenants
negotiated at the time the Credit Facility was established did not contemplate our contribution for its investment in Carbon Appalachia
and, as a result, we were not in compliance with financial covenants associated with the Credit Facility as of December 31, 2017.
However, we have obtained a waiver of the Debt/EBITDA ratio and the current ratio covenants as of December 31, 2017. On March
27, 2018, the Credit Facility was amended to revise the calculation of the Leverage Ratio from a Debt/EBITDA ratio to a Net Debt/Adjusted
EBITDA ratio, reset the testing period used in the determination of Adjusted EBITDA, eliminate the minimum current ratio and substitute
alternative liquidity requirements, including maximum allowed current liabilities in relation to current assets, minimum cash
balance requirements and maximum aged trade payable requirements.
We may at any time repay the loans under
the Credit Facility, in whole or in part, without penalty. We must pay down borrowings under the Credit Facility or provide mortgages
of additional oil and natural gas properties to the extent that outstanding loan and letters of credit exceed the borrowing base.
As required under the terms of the Credit
Facility, we entered into derivative contracts at fixed pricing for a certain percentage of our production. We are party to an
ISDA Master Agreement with BP Energy Company that establishes standard terms for the derivative contracts and an inter-creditor
agreement with LegacyTexas Bank and BP Energy Company whereby any credit exposure related to the derivative contracts entered
by us and BP Energy Company is secured by the collateral and backed by the guarantees supporting the Credit Facility.
As of December 31, 2017, there were approximately
$22.1 million in outstanding borrowings and approximately $0.86 million of additional borrowing capacity available under the Credit
Facility. Our effective borrowing rate at December 31, 2017 was approximately 5.67%.
We incurred fees directly associated with
the issuance of the Credit Facility and amortize these fees over the life of the Credit Facility. The current portion of these
fees are included in prepaid expense, deposits and other current assets and the long-term portion is included in other long-term
assets for a combined value of $700,000. As of December 31, 2017, and 2016, we have unamortized deferred issuance costs of $484,000
and $596,000, respectively. During the years ended December 31, 2017 and 2016, we amortized $176,000 and $51,000, respectively,
as interest expense.
Note 8 –
Income Taxes
The provision for
income taxes for the years ended December 31, 2017 and 2016 consists of the following:
(in thousands)
|
|
For the Year Ended
|
|
|
|
December 31,
|
|
|
|
2017
|
|
|
2016
|
|
|
|
|
|
|
|
|
Current income tax (benefit) expense
|
|
$
|
(74
|
)
|
|
$
|
-
|
|
Deferred income tax (benefit) expense
|
|
|
7,080
|
|
|
|
(4,472
|
)
|
Change in valuation allowance
|
|
|
(7,080
|
)
|
|
|
4,472
|
|
|
|
|
|
|
|
|
|
|
Total income tax (benefit) expense
|
|
$
|
(74
|
)
|
|
$
|
-
|
|
The effective income tax rate for the
years ended December 31, 2017 and 2016 differed from the statutory U.S. federal income tax rate as follows:
|
|
For the Year Ended
|
|
|
|
December 31,
|
|
|
|
2017
|
|
|
2016
|
|
|
|
|
|
|
|
|
Federal income tax rate
|
|
|
35.0
|
%
|
|
|
35.0
|
%
|
State income taxes, net of federal benefit
|
|
|
3.8
|
|
|
|
3.5
|
|
Permanent Differences
|
|
|
(20.5
|
)
|
|
|
1.1
|
|
Non-controlling interest in consolidated partnerships
|
|
|
(0.8
|
)
|
|
|
(0.4
|
)
|
True-up of prior year depletion in excess of basis
|
|
|
1.1
|
|
|
|
.2
|
|
Stock-based compensation deficiency
|
|
|
3.1
|
|
|
|
(2.9
|
)
|
Rate changes of prior year deferred
|
|
|
(1.8
|
)
|
|
|
0.2
|
|
True-up of prior year deferred
|
|
|
(4.5
|
)
|
|
|
(1.8
|
)
|
Effect of tax cuts and TCJA
|
|
|
91.0
|
|
|
|
-
|
|
Increase in valuation allowance and other
|
|
|
(107.7
|
)
|
|
|
(34.9
|
)
|
|
|
|
|
|
|
|
|
|
Total income tax expense (benefit)
|
|
|
(1.1
|
)%
|
|
|
-
|
%
|
The tax effects of temporary differences
that gave rise to significant portions of the deferred tax assets and liabilities at December 31, 2017 and 2016 are presented
below:
(in thousands)
|
|
As of December 31,
|
|
|
|
2017
|
|
|
2016
|
|
|
|
|
|
|
|
|
Deferred tax assets
|
|
|
|
|
|
|
Net operating loss carryforwards
|
|
$
|
6,407
|
|
|
$
|
8,274
|
|
Depletion carryforwards
|
|
|
1,934
|
|
|
|
2,740
|
|
Accrual and other
|
|
|
450
|
|
|
|
726
|
|
Stock-based compensation
|
|
|
476
|
|
|
|
968
|
|
Derivatives
|
|
|
-
|
|
|
|
730
|
|
Asset retirement obligations
|
|
|
1,944
|
|
|
|
1,936
|
|
Property, plant and equipment
|
|
|
2,972
|
|
|
|
6,439
|
|
Total deferred tax assets
|
|
|
14,183
|
|
|
|
21,813
|
|
|
|
|
|
|
|
|
|
|
Deferred tax liability
|
|
|
|
|
|
|
|
|
Interest in partnerships
|
|
|
(790
|
)
|
|
|
(762
|
)
|
Derivative and other
|
|
|
(57
|
)
|
|
|
-
|
|
|
|
|
|
|
|
|
|
|
Less valuation allowance
|
|
|
(13,336
|
)
|
|
|
(21,051
|
)
|
|
|
|
|
|
|
|
|
|
Net deferred tax asset
|
|
$
|
-
|
|
|
$
|
-
|
|
As of December 31, 2017, we have net operating
loss (“NOL”) carryforwards of approximately $21.2 million available to reduce future years’ federal taxable
income. The federal NOLs expire in various years through 2037. We have various state NOL carryforwards available to reduce future
years’ state taxable income, which are dependent on apportionment percentages and state laws that can change from year to
year and impact the amount of such carryforwards. These state NOL carryforwards will expire in the future based upon each jurisdiction’s
specific law surrounding NOL carryforwards. Tax returns are subject to audit by various taxation authorities. The results of any
audits will be accounted for in the period in which they are determined.
We believe that
the tax positions taken in our tax returns satisfy the more likely than not threshold for benefit recognition. Accordingly, no
liabilities have been recorded by us. Any potential adjustments for uncertain tax positions would be a reclassification between
the deferred tax asset related to our NOL carryforwards and another deferred tax asset.
Our policy is to
classify accrued penalties and interest related to unrecognized tax benefits in our income tax provision. As of December 31, 2017,
we did not have any accrued interest or penalties associated with any unrecognized tax benefits, nor was any interest expense
recognized during the current year.
On December 22, 2017, the U.S. government
enacted comprehensive tax legislation commonly referred to as the Tax Cuts and Jobs Act (the “TCJA”). The TCJA makes
broad and complex changes to the U.S. tax code applicable to certain items in 2017 as well as those applicable to 2018 and subsequent
years.
ASC 740 requires the recognition of the
tax effects of the of the TCJA for annual periods that include December 22, 2017. At December 31, 2017, we have made reasonable
estimates of the effects on our existing deferred tax balances. We have remeasured certain federal deferred tax assets and liabilities
based upon the rates at which they are expected to reverse in the future, which is generally 21.0% percent. The provisional amount
recognized related to the remeasurement of its federal deferred tax balance was $6.0 million, which was subject to a valuation
allowance at December 31, 2017.
We will continue to analyze the TCJA and
future IRS regulations, refine our calculations and gain a more thorough understanding of how individual states are implementing
this new law. This further analysis could potentially affect the measurement of deferred tax balances or potentially give rise
to new deferred tax amounts.
We file income tax returns in the U.S. federal jurisdiction and in various states, each with varying
statutes of limitations. The 2014 through 2017 tax years generally remain subject to examination by federal and state tax authorities.
Note 9 –
Stockholders’ Equity
Authorized and
Issued Capital Stock
Effective March
15, 2017 and pursuant to a reverse stock split approved by the shareholders and Board of Directors, each 20 shares of issued and
outstanding common stock became one share of common stock and no fractional shares were issued. References to the number of shares
and price per share give retroactive effect to the reverse stock split for all periods presented. In connection with the reverse
stock split, the number of authorized shares of our common stock was decreased from 200,000,000 to 10,000,000.
As of December 31,
2017, we had 10,000,000 shares of common stock authorized with a par value of $0.01 per share, of which approximately 6,000,000
were issued and outstanding, and 1,000,000 shares of preferred stock authorized with a par value of $0.01 per share, none of which
were issued and outstanding. During the year ended December 31, 2017, the increase in our issued and outstanding common stock
reflects the exercise by the holder of the Appalachia Warrant (see Note 6), resulting in the issuance of approximately 432,000
shares of our common stock in addition to restricted stock and performance units, net of shares exchanged for payroll tax obligations
paid by us, that vested during the year in exchange for Class A Units in Carbon Appalachia representing approximately 7.95% of
the then outstanding Class A Units.
Carbon Stock
Incentive Plans
We have two stock
plans, the Carbon 2011 Stock Incentive Plan and the Carbon 2015 Stock Incentive Plan (collectively the “Carbon Plans”).
The Carbon Plans were approved by our shareholders and in the aggregate provide for the issuance of approximately 1.1 million
shares of common stock to our officers, directors, employees or consultants eligible to receive the awards under the Carbon Plans.
The Carbon Plans
provide for the granting of incentive stock options, non-qualified stock options, restricted stock awards, performance awards
and phantom stock awards, or a combination of the foregoing, as to employees, officers, directors or consultants, provided that
only employees may be granted incentive stock options and directors may only be granted restricted stock awards and phantom stock
awards.
Restricted Stock
Restricted stock awards for employees
vest ratably over a three-year service period or cliff vest at the end of a three-year service period. For non-employee directors,
the awards vest upon the earlier of a change in control of us or the date their membership on the Board of Directors is terminated
other than for cause. We recognize compensation expense for these restricted stock grants based on the grant date fair value of
the shares, amortized ratably over three years for employee awards (based on the required service period for vesting) and seven
years for non-employee director awards (based on a market survey of the average tenure of directors among U.S. public companies).
For restricted stock granted between 2014 and 2017, we recognized compensation expense based on the grant date fair value of the
shares, utilizing an enterprise value approach, using valuation metrics primarily based on multiples of cash flow from operations,
production and reserves. For restricted stock and performance units granted in 2013, we utilized the closing price of our stock
on the date of grant to recognize compensation expense. The following table shows a summary of our unvested restricted stock under
the Carbon Plans as of December 31, 2017 and 2016 as well as activity during the years then ended.
|
|
|
|
|
Weighted Avg
|
|
|
|
Number
|
|
|
Grant Date
|
|
|
|
of Shares
|
|
|
Fair Value
|
|
Restricted stock awards, unvested, January 1, 2016
|
|
|
199,000
|
|
|
$
|
10.37
|
|
|
|
|
|
|
|
|
|
|
Granted
|
|
|
134,501
|
|
|
|
5.40
|
|
|
|
|
|
|
|
|
|
|
Vested
|
|
|
(64,668
|
)
|
|
|
10.84
|
|
|
|
|
|
|
|
|
|
|
Forfeited
|
|
|
(1,083
|
)
|
|
|
6.20
|
|
|
|
|
|
|
|
|
|
|
Restricted stock awards, unvested, December 31, 2016
|
|
|
267,750
|
|
|
|
7.78
|
|
|
|
|
|
|
|
|
|
|
Granted
|
|
|
81,050
|
|
|
|
7.20
|
|
|
|
|
|
|
|
|
|
|
Vested
|
|
|
(64,915
|
)
|
|
|
8.38
|
|
|
|
|
|
|
|
|
|
|
Forfeited
|
|
|
(13,050
|
)
|
|
|
6.19
|
|
|
|
|
|
|
|
|
|
|
Restricted stock awards, unvested, December 31, 2017
|
|
|
270,835
|
|
|
$
|
7.54
|
|
Compensation costs
recognized for these restricted stock grants were approximately $664,000 and $742,000 for the years ended December 31, 2017 and
2016, respectively. As of December 31, 2017, there was approximately $1.1 million of unrecognized compensation costs related to
these restricted stock grants which we expect to be recognized over the next 6.3 years.
Restricted Performance
Units
Performance units
represent a contractual right to receive one share of our common stock subject to the terms and conditions of the agreements,
including the achievement of certain performance measures relative to a defined peer group or the growth of certain performance
measures over a defined period of time as well as, in some cases, continued service requirements. The following table shows a
summary of our unvested performance units as of December 31, 2017 and 2016 as well as activity during the years then ended.
|
|
Number
|
|
|
|
of Shares
|
|
Restricted performance units, unvested, January 1, 2016
|
|
|
314,311
|
|
|
|
|
|
|
Granted
|
|
|
80,000
|
|
|
|
|
|
|
Vested
|
|
|
(84,480
|
)
|
|
|
|
|
|
Forfeited
|
|
|
(13,520
|
)
|
|
|
|
|
|
Restricted performance units, unvested, December 31, 2016
|
|
|
296,311
|
|
|
|
|
|
|
Granted
|
|
|
60,050
|
|
|
|
|
|
|
Vested
|
|
|
(80,000
|
)
|
|
|
|
|
|
Forfeited
|
|
|
(17,550
|
)
|
|
|
|
|
|
Restricted performance units, unvested, December 31, 2017
|
|
|
258,811
|
|
We account for the
performance units granted during 2014 through 2017 at their fair value determined at the date of grant, which were $11.80, $8.00,
$5.40 and $7.20 per share, respectively. The final measurement of compensation cost will be based on the number of performance
units that ultimately vest. At December 31, 2017, we estimated that none of the performance units granted in 2016 and 2017 would
vest, and, accordingly, no compensation cost has been recorded for these performance units. During 2016, we estimated that it
was probable that the performance units granted in 2014 and 2015 would vest and therefore compensation costs of approximately
$442,000 and $1.2 million related to these performance units were recognized for the years ended December 31, 2017 and 2016, respectively.
As of December 31, 2017, if change in control and other performance provisions pursuant to the terms and conditions of these award
agreements are met in full, the estimated unrecognized compensation cost related to the performance units granted in 2014 through
2017 would be approximately $2.1 million.
Note 10 –
Accounts Payable and Accrued Liabilities
Accounts payable
and accrued liabilities at December 31, 2017 and 2016 consist of the following:
(in thousands)
|
|
|
|
|
|
|
|
|
As of December 31,
|
|
|
|
2017
|
|
|
2016
|
|
|
|
|
|
|
|
|
Accounts payable
|
|
$
|
3,274
|
|
|
$
|
2,315
|
|
Oil and gas revenue suspense
|
|
|
1,776
|
|
|
|
1,415
|
|
Gathering and transportation payables
|
|
|
497
|
|
|
|
468
|
|
Production taxes payable
|
|
|
214
|
|
|
|
113
|
|
Drilling advances received from joint venture partner
|
|
|
245
|
|
|
|
955
|
|
Accrued drilling costs
|
|
|
-
|
|
|
|
4
|
|
Accrued lease operating costs
|
|
|
684
|
|
|
|
282
|
|
Accrued ad valorem taxes-current
|
|
|
1,054
|
|
|
|
1,552
|
|
Accrued general and administrative expenses
|
|
|
2,473
|
|
|
|
1,572
|
|
Accrued asset retirement obligation-current
|
|
|
380
|
|
|
|
-
|
|
Accrued interest
|
|
|
247
|
|
|
|
184
|
|
Other liabilities
|
|
|
374
|
|
|
|
261
|
|
|
|
|
|
|
|
|
|
|
Total accounts payable and accrued liabilities
|
|
$
|
11,218
|
|
|
$
|
9,121
|
|
Note 11 –
Fair Value Measurements
Authoritative guidance
defines fair value as the price that would be received to sell an asset or paid to transfer a liability (an exit price) in an
orderly transaction between market participants at the measurement date. The guidance establishes a hierarchy for inputs used
in measuring fair value that maximizes the use of observable inputs and minimizes the use of unobservable inputs by requiring
that the most observable inputs be used when available. Observable inputs are inputs that market participants would use in pricing
the asset or liability developed based on market data obtained from sources independent of us. Unobservable inputs are inputs
that reflect our assumptions of what market participants would use in pricing the asset or liability developed based on the best
information available in the circumstances. The hierarchy is broken down into three levels based on the reliability of the inputs
as follows:
|
Level 1:
|
Quoted
prices are available in active markets for identical assets or liabilities;
|
|
Level 2:
|
Quoted
prices in active markets for similar assets or liabilities that are observable for the
asset or liability; or
|
|
Level 3:
|
Unobservable
pricing inputs that are generally less observable from objective sources, such as discounted
cash flow models or valuations.
|
Financial assets
and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. Our policy
is to recognize transfers in and/or out of fair value hierarchy as of the end of the reporting period for which the event or change
in circumstances caused the transfer. We have consistently applied the valuation techniques discussed below for all periods presented.
The following table
presents our financial assets and liabilities that were accounted for at fair value on a recurring basis by level within the fair
value hierarchy:
(in thousands)
|
|
Fair Value Measurements Using
|
|
|
|
Level 1
|
|
|
Level 2
|
|
|
Level 3
|
|
|
Total
|
|
December 31, 2017
|
|
|
|
|
|
|
|
|
|
|
|
|
Asset:
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivatives
|
|
$
|
-
|
|
|
$
|
225
|
|
|
$
|
-
|
|
|
$
|
225
|
|
Liabilities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Warrant
derivative liability
|
|
$
|
-
|
|
|
$
|
-
|
|
|
$
|
2,017
|
|
|
$
|
2,017
|
|
December 31, 2016
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liability:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivatives
|
|
$
|
-
|
|
|
$
|
1,932
|
|
|
$
|
-
|
|
|
$
|
1,932
|
|
Commodity Derivative
As of December 31,
2017, our commodity derivative financial instruments are comprised of eight natural gas, eight oil swap, and one natural gas costless
collar agreements. As of December 31, 2016, our commodity derivative financial instruments were comprised of eight natural gas
swap agreements and nine oil swap agreements. The fair values of these agreements are determined under an income valuation technique.
The valuation model requires a variety of inputs, including contractual terms, published forward prices, volatilities for options
and discount rates, as appropriate. Our estimates of fair value of derivatives include consideration of the counterparty’s
credit worthiness, our credit worthiness and the time value of money. The consideration of these factors results in an estimated
exit-price for each derivative asset or liability under a market place participant’s view. All of the significant inputs
are observable, either directly or indirectly; therefore, our derivative instruments are included within the Level 2 fair value
hierarchy. The counterparty for all of our outstanding commodity derivative financial instruments as of December 31, 2017 is BP
Energy Company.
Warrant Derivative
A third-party valuation
specialist is utilized to determine the fair value of our California Warrant and Appalachia Warrant. These warrants are designated
as Level 3. We review these valuations, including the related model inputs and assumptions, and analyze changes in fair value
measurements between periods. We corroborate such inputs, calculations and fair value changes using various methodologies, and
reviews unobservable inputs for reasonableness utilizing relevant information from other published sources.
We estimated the
fair value of the California Warrant on February 15, 2017, the grant date of the warrant, to be approximately $5.8 million, using
a call option pricing model with the following assumptions: a seven-year term, exercise price of $7.20, volatility rate of 41.8%
and a risk-free rate of 2.3%. As we will receive Class A units in Carbon California in the event the holder exercises the California
Warrant, we also considered the fair value of the Class A units in its valuation. We remeasured the California Warrant as of December
31, 2017, using a Monte Carlo valuation model which utilized unobservable inputs including the percentage return on our shares
at various timelines, the percentage return on the privately-held Carbon California Class A units at various timelines, an exercise
price of $7.20, volatility rate of 45%, a risk-free rate of 2.1% and an estimated remaining term of 6.4 years. As of December
31, 2017, the fair value of the California Warrant was approximately $2.0 million.
We estimated the
fair value of the Appalachia Warrant on April 3, 2017, the grant date of the warrant, to be approximately $1.3 million, using
a call option pricing model with the following assumptions: a seven-year term, exercise price of $7.20, volatility rate of 39.3%
and a risk-free rate of 2.1%. As we will receive Class A units in Carbon Appalachia in the event the holder exercises the Appalachia
Warrant, we also considered the fair value of the Class A units in its valuation. We remeasured the Appalachia Warrant as of November
1, 2017, immediately prior to its exercise, using a Monte Carlo valuation model which utilized unobservable inputs including the
percentage return on our shares at various timelines, the percentage return on the privately-held Carbon Appalachia Class A units
at various timelines, an exercise price of $7.20, volatility rate of 45%, a risk-free rate of 2.1% and an estimated remaining
term of 6.5 years. As of December 31, 2017, the warrant liability had been extinguished.
The following table
summarizes the changes in fair value of our financial instruments classified as Level 3 in the fair value hierarchy:
(in thousands)
|
|
California Warrant
|
|
|
Appalachia Warrant
|
|
|
Total
|
|
|
|
|
|
|
|
|
|
|
|
Balance, December 31, 2016
|
|
$
|
-
|
|
|
$
|
-
|
|
|
$
|
-
|
|
Warrant liability
|
|
|
5,769
|
|
|
|
1,325
|
|
|
|
7,094
|
|
Unrealized (gain) loss included in warrant gain
|
|
|
(3,752
|
)
|
|
|
619
|
|
|
|
(3,133
|
)
|
Settlement of warrant liability
|
|
|
-
|
|
|
|
(1,944
|
)
|
|
|
(1,944
|
)
|
Balance, December 31, 2017
|
|
$
|
2,017
|
|
|
$
|
-
|
|
|
$
|
2,017
|
|
Assets and Liabilities
Measured and Recorded at Fair Value on a Non-Recurring Basis
The fair value of
each of the following assets and liabilities measured and recorded at fair value on a non-recurring basis are based on unobservable
pricing inputs and therefore, are included within the Level 3 fair value hierarchy.
We use the income
valuation technique to estimate the fair value of asset retirement obligations using the amounts and timing of expected future
dismantlement costs, credit-adjusted risk-free rates and time value of money. During the year ended December 31, 2017, we recorded
$2.4 million in additions to asset retirement obligations compared to additions of approximately $1.8 million for the year ended
December 31, 2016. See Note 3 for additional information.
To determine the
fair value of the proved developed properties acquired in the EXCO Acquisition in 2016, we primarily used the income approach
and made market assumptions as to projections of estimated quantities of oil and natural gas reserves, future production rates,
future commodity prices including price differentials as of the Closing Date, future operating and development costs and a market
participant weighted average cost of capital.
The fair value of the non-controlling
interest in the partnerships we are required to consolidate was determined based on the net discounted cash flows of the proved
developed producing properties attributable to the non-controlling interests in these partnerships.
We assume, at times, certain firm transportation
contracts as part of our acquisitions of oil and natural gas properties. The fair value of the firm transportation obligations
was determined based upon the contractual obligations assumed by us and discounted based upon our effective borrowing rate. These
contractual obligations are being amortized on a monthly basis as we pay these firm transportation obligations in the future.
Asset Retirement Obligation
The fair value of our asset retirement
obligation liability is recorded in the period in which it is incurred or assumed by taking into account the cost of abandoning
oil and gas wells ranging from $20,000 to $30,000, which is based on our historical experience and industry expectations for similar
work; the estimated timing of reclamation ranging from one to 75 years based on estimates from reserve engineers; an inflation
rate of 1.92%; and a credit adjusted risk-free rate of 7.24%, which takes into account our credit risk and the time value of money.
Given the unobservable nature of the inputs, the initial measurement of the asset retirement obligation liability is deemed to
use Level 3 inputs (see Note 3). During the year ended December 31, 2017, we recorded additions to asset retirement obligations
of approximately $2.4 million, which was the result of increases in the costs estimated to perform plugging and reclamation activities
within the Appalachian Basin. We use the income valuation technique to estimate the fair value of asset retirement obligations
using the amounts and timing of expected future dismantlement costs, credit-adjusted risk-free rates and time value of money.
Class B Units
We received Class B units from Carbon
California and Carbon Appalachia as part of the entry into the Carbon California LLC Agreement and Carbon Appalachia LLC Agreement,
respectively. We estimated the fair value of the Class B units, in each case, by utilizing the assistance of third-party valuation
specialists. The fair values were based upon enterprise values derived from inputs including estimated future production rates,
future commodity prices including price differentials as of the dates of closing, future operating and development costs and comparable
market participants.
Note 12 – Physical Delivery Contracts and Commodity
Derivatives
We historically have used commodity-based
derivative contracts to manage exposures to commodity price on certain of our oil and natural gas production. We do not hold or
issue derivative financial instruments for speculative or trading purposes. We also have entered into fixed price delivery contracts
to effectively provide commodity price hedges. Because these contracts are not expected to be net cash settled, they are considered
to be normal sales contracts and not derivatives. Therefore, these contracts are not recorded at fair value in the consolidated
financial statements.
Pursuant to the terms of our credit facility
with LegacyTexas Bank, we have entered into swap and collar derivative agreements to hedge certain of our oil and natural gas
production through 2019. As of December 31, 2017, these derivative agreements consisted of the following:
|
|
Natural
Gas Swaps
|
|
|
Natural
Gas Collars
|
|
|
Oil
Swaps
|
|
|
|
|
|
|
Weighted
|
|
|
|
|
|
Weighted
|
|
|
|
|
|
Weighted
|
|
|
|
|
|
|
Average
|
|
|
|
|
|
Average
Price
|
|
|
|
|
|
Average
|
|
Year
|
|
MMBtu
|
|
|
Price
(a)
|
|
|
MMBtu
|
|
|
Range (a)
|
|
|
Bbl
|
|
|
Price
(b)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2018
|
|
|
3,390,000
|
|
|
$
|
3.01
|
|
|
|
60,000
|
|
|
|
$3.00
- $3.48
|
|
|
|
63,000
|
|
|
$
|
53.55
|
|
2019
|
|
|
2,596,000
|
|
|
$
|
2.86
|
|
|
|
-
|
|
|
|
-
|
|
|
|
48,000
|
|
|
$
|
53.76
|
|
(a)
|
NYMEX Henry Hub
Natural Gas futures contract for the respective period.
|
|
|
(b)
|
NYMEX Light Sweet
Crude West Texas Intermediate futures contract for the respective period.
|
For our swap instruments, we receive a
fixed price for the hedged commodity and pays a floating price to the counterparty. The fixed-price payment and the floating-price
payment are netted, resulting in a net amount due to or from the counterparty.
Costless collars are designed to establish
floor and ceiling prices on anticipated future oil and gas production. The ceiling establishes a maximum price that we will receive
for the volumes under contract, while the floor establishes a minimum price.
The following table summarizes the fair
value of the derivatives recorded in the consolidated balance sheets (Note 11). These derivative instruments are not designated
as cash flow hedging instruments for accounting purposes:
(in thousands)
|
|
As of December 31,
|
|
|
|
2017
|
|
|
2016
|
|
Commodity derivative contracts:
|
|
|
|
|
|
|
Commodity derivative asset
|
|
$
|
215
|
|
|
$
|
-
|
|
Other long-term assets
|
|
$
|
10
|
|
|
$
|
-
|
|
|
|
|
|
|
|
|
|
|
Commodity derivative liabilities
|
|
$
|
-
|
|
|
$
|
1,341
|
|
Commodity derivative liabilities, non-current
|
|
$
|
-
|
|
|
$
|
591
|
|
The table below summarizes the commodity
settlements and unrealized gains and losses related to our derivative instruments for the years ended December 31, 2017 and 2016.
These commodity settlements and unrealized gains and losses are recorded and included in commodity derivative gain or loss in
the accompanying consolidated statements of operations.
(in thousands)
|
|
For the year ended
December 31,
|
|
|
|
2017
|
|
|
2016
|
|
Commodity derivative contracts:
|
|
|
|
|
|
|
Settlement gains
|
|
$
|
770
|
|
|
$
|
231
|
|
Unrealized gains (loss)
|
|
|
2,158
|
|
|
|
(2,490
|
)
|
|
|
|
|
|
|
|
|
|
Total settlement and unrealized gains (losses), net
|
|
$
|
2,928
|
|
|
$
|
(2,259
|
)
|
Commodity derivative settlement gains
and losses are included in cash flows from operating activities in our consolidated statements of cash flows.
The counterparty in all our derivative
instruments is BP Energy Company. We have entered into an International Swaps and Derivatives Association (“ISDA”)
Master Agreement with BP Energy Company that establishes standard terms for the derivative contracts and an inter-creditor agreement
with LegacyTexas Bank and BP Energy Company whereby any credit exposure related to the derivative contracts entered into by us
and BP Energy Company is secured by the collateral and backed by the guarantees supporting the credit facility.
We net our derivative instrument fair
value amounts executed with BP Energy Company pursuant to the ISDA master agreement, which provides for the net settlement over
the term of the contracts and in the event of default or termination of the contracts. The following table summarizes the location
and fair value amounts of all derivative instruments in the Consolidated Balance Sheet, as well as the gross recognized derivative
assets, liabilities and amounts offset in the Consolidated Balance Sheet as of December 31, 2017.
|
|
|
|
|
|
|
|
|
|
Net
|
|
|
|
|
|
Gross
|
|
|
|
|
|
Recognized
|
|
|
|
|
|
Recognized
|
|
|
Gross
|
|
|
Fair Value
|
|
|
|
|
|
Assets/
|
|
|
Amounts
|
|
|
Assets/
|
|
|
|
Balance Sheet Classification
|
|
Liabilities
|
|
|
Offset
|
|
|
Liabilities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivative assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivative
|
|
$
|
624
|
|
|
$
|
(409
|
)
|
|
$
|
215
|
|
|
|
Other long-term assets
|
|
|
250
|
|
|
|
(240
|
)
|
|
|
10
|
|
Total derivative assets
|
|
|
|
$
|
874
|
|
|
$
|
(649
|
)
|
|
$
|
225
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivative liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivative
|
|
$
|
(409
|
)
|
|
$
|
409
|
|
|
$
|
-
|
|
|
|
Commodity derivative: non-current
|
|
|
(240
|
)
|
|
|
240
|
|
|
|
-
|
|
Total derivative liabilities
|
|
|
|
$
|
(649
|
)
|
|
$
|
649
|
|
|
$
|
-
|
|
The following table summarizes the location
and fair value amounts of all derivative instruments in the Consolidated Balance Sheet, as well as the gross recognized derivative
assets, liabilities and amounts offset in the Consolidated Balance Sheet as of December 31, 2016.
|
|
|
|
|
|
|
|
|
|
Net
|
|
|
|
|
|
Gross
|
|
|
|
|
|
Recognized
|
|
|
|
|
|
Recognized
|
|
|
Gross
|
|
|
Fair Value
|
|
|
|
|
|
Assets/
|
|
|
Amounts
|
|
|
Assets/
|
|
|
|
Balance Sheet Classification
|
|
Liabilities
|
|
|
Offset
|
|
|
Liabilities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivative assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivative
|
|
$
|
-
|
|
|
$
|
-
|
|
|
$
|
-
|
|
|
|
Other long-term assets
|
|
|
249
|
|
|
|
(249
|
)
|
|
|
-
|
|
Total derivative assets
|
|
|
|
$
|
249
|
|
|
$
|
(249
|
)
|
|
$
|
-
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivative liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivative
|
|
$
|
1,341
|
|
|
$
|
-
|
|
|
$
|
1,341
|
|
|
|
Commodity derivative: non-current
|
|
|
840
|
|
|
|
(249
|
)
|
|
|
591
|
|
Total derivative liabilities
|
|
|
|
$
|
2,181
|
|
|
$
|
(249
|
)
|
|
$
|
1,932
|
|
Due to the volatility of oil and natural
gas prices, the estimated fair values of our derivatives are subject to large fluctuations from period to period.
Note 13 – Commitments and Contingencies
We have entered into employment agreements
with certain of our executives and officers. The term of the agreements generally ranges from one to two years and provides for
renewal provisions in one year increments thereafter. The agreements provide for, among other items, severance and continuation
of benefit payments upon termination of employment or certain change of control events.
We have entered into long-term firm transportation
contracts to ensure the transport for certain of our gas production to purchasers. Firm transportation volumes and the related
demand charges for the remaining term of these contracts at December 31, 2017 are summarized in the table below.
Period
|
|
Dekatherms
per day
|
|
|
Demand
Charges
|
|
Jan 2018 - Apr 2018
|
|
|
5,530
|
|
|
$
|
0.20 -
$0.65
|
|
May 2018 - Mar 2020
|
|
|
3,230
|
|
|
$
|
0.20 - $0.62
|
|
Apr 2020 – May 2020
|
|
|
2,150
|
|
|
$
|
0.20
|
|
Jun 2020 – May 2036
|
|
|
1,000
|
|
|
$
|
0.20
|
|
A liability of approximately $261,000
related to firm transportation contracts assumed in the EXCO Acquisition in 2016, which represents the remaining commitment, is
reflected on our Consolidated Balance Sheet as of December 31, 2017. The fair value of these firm transportation obligations was
determined based upon the contractual obligations assumed by us and discounted based upon our effective borrowing rate. These
contractual obligations are being amortized monthly as we pay these firm transportation obligations in the future.
We lease, under an operating lease arrangement,
approximately 8,500 square feet of administrative office space in Denver, Colorado that expires in 2023, approximately 5,300 square
feet of office space in Lexington, Kentucky that expires in 2019, and 9,500 square feet of office space in Santa Paula, California
that expires in 2021. For the years ended December 31, 2017 and 2016, we incurred rental expenses of $255,000 and $220,000, respectively.
We have minimum lease payments for our office space and equipment of approximately $436,000 for 2018, $390,000 for 2019, $382,000
for 2020, $275,000 for 2021, and $270,000 for 2022.
Capital Commitment
In our participation as a Class A member
of Carbon Appalachia we made a capital commitment of $23.6 million, of which we have contributed $6.9 million as of December 31,
2017.
As of December 31, 2017, we had no capital commitments associated
with Carbon California.
During March 2018, management became aware
that one of our field employees had been misappropriating funds from our suspended revenue accounts, or suspense accounts, over
a period of several years. Promptly following the discovery of the misappropriation, we terminated the employee and engaged an
external forensic specialist to lead an investigation to determine the extent and impact on our financial statements. That investigation
revealed that the employee’s ability to misappropriate funds from the suspense accounts was eliminated in 2017 when we moved
our revenue accounting function to our Denver office and instituted our current set of revenue accounting practices and internal
controls. As a result, the employee no longer had access to the suspense accounts.
The discovery of the misappropriation
was made in March 2018 when the employee attempted to misappropriate funds from a different source. This attempt was identified
under the Company’s current internal controls.
The investigation is still ongoing, but
based on the results so far, we have recorded a provision at December 31, 2017 of $250,000 to reflect the estimated loss of suspended
revenue. Depending upon the final results of the investigation, which we are seeking to conclude as soon as reasonably practicable,
we may determine that the estimate should be increased or decreased. Furthermore, we will no longer be using printed manual checks
for payments. Revenue and other checks will require approval from more than one individual and we are evaluating our segregation
of duties, specifically related to the cash disbursement process, and will adjust where possible to strengthen the system of internal
control. We have determined that this event constituted a significant deficiency, but not a material weakness, at December 31,
2017.
Note 14 – Retirement Savings Plan
We have a 401(k) plan available to eligible
employees. The plan provides for 6% matching which vests immediately. For the years ended December 31, 2017 and 2016, we contributed
approximately $175,000 and $99,000, respectively, for 401(k) contributions and related administrative expenses.
Note 15 – Supplemental Cash
Flow Disclosure
Supplemental cash flow disclosures are
presented below:
(in thousands)
|
|
For the Years Ended
December 31,
|
|
|
|
2017
|
|
|
2016
|
|
|
|
|
|
|
|
|
Cash paid during the period for:
|
|
|
|
|
|
|
Interest payments
|
|
$
|
967
|
|
|
$
|
156
|
|
Income taxes
|
|
|
-
|
|
|
|
-
|
|
|
|
|
|
|
|
|
|
|
Non-cash transactions:
|
|
|
|
|
|
|
|
|
Increase in asset retirement obligations
|
|
$
|
2,402
|
|
|
$
|
1,849
|
|
Increase (decrease) in accounts payable and accrued liabilities
included in oil and gas properties
|
|
$
|
67
|
|
|
$
|
1,099
|
|
Obligations assumed with acquisitions
|
|
$
|
-
|
|
|
$
|
2,694
|
|
Equity method investments
|
|
$
|
5,674
|
|
|
$
|
-
|
|
Note 16 – Related Parties
During the year ended December 31, 2017,
we were engaged in the following transactions with related parties:
Carbon California
We received 5,077 Class B units of Carbon
California, representing 17.81% of the voting and profits interest.
Carbon California Operating Company (“CCOC”)
is our subsidiary and the operator of Carbon California through an operating agreement. The operating agreement includes reimbursements
and allocations made under the agreement. As of December 31, 2017, approximately $300,000 is due from Carbon California and included
in accounts receivable – due from related party on the consolidated balance sheets.
On February 15, 2017, we entered into
a management service agreement with Carbon California whereby we provide general management and administrative services.
We receive $600,000 annually, payable in four equal quarterly installments. We also received a one-time reimbursement of
$500,000 in connection with the CRC and Mirada Acquisitions. Carbon California reimburses us for all management related expenses
such as travel, required third-party geological and/or accounting consulting, and other necessary expenses incurred by us in the
normal course of managing Carbon California. For the year ended December 31, 2017, we recorded $1.0 million in total management
reimbursements. There were no outstanding management reimbursements unpaid as of December 31, 2017.
Carbon Appalachia
We received 1,000 Class B units of Carbon
Appalachia, representing a future profits interest after certain return thresholds to Class A Units are met. We also received
121 Class C Units of Carbon Appalachia, representing an approximate 1.0% profits interest, in exchange for unevaluated property
in Tennessee.
Nytis is the operator of Carbon Appalachia
through an operating agreement. The operating agreement includes reimbursements and allocations made under the agreement. As of
December 31, 2017, approximately $1.8 million is due from Carbon Appalachia and included in accounts receivable – due from
related party on the consolidated balance sheets.
On April 3, 2017, we entered into a management
service agreement with Carbon Appalachia whereby we provide general management and administrative services. We initially
received a quarterly reimbursement of $75,000; however, after the Enervest Acquisition in August, the amount of the reimbursement
now varies quarterly based upon the percentage of our production in relation to the total of our production and Carbon Appalachia.
We also received a one-time reimbursement of $300,000 in connection with the CNX Acquisition. Total reimbursements recorded by
us for the year ended December 31, 2017, were approximately $1.6 million, of which approximately $579,000 was included in accounts
receivable – due from related party on the consolidated balance sheets as of December 31, 2017.
Ohio Basic Minerals
During 2017, we received $96,000 in management
reimbursements from Ohio Basic Minerals.
Note 17 – Subsequent Events
On February 1, 2018, Yorktown exercised
the California Warrant resulting in us receiving 11,000 Class A Units in Carbon California and issuing 1,527,778 shares of its
Common Stock to Yorktown. As a result, our ownership of Class A Units of Carbon California increased from zero to 11,000 or from
0% to 46.96% (which equates to a sharing percentage interest of 38.59%). We also hold all of the Class B Units of Carbon California
which represent a sharing percentage of 17.81%, resulting in our aggregate sharing percentage increasing from 17.81% to 56.40%.
On March 27, 2018, we amended our senior
secured asset-based revolving credit facility with LegacyTexas Bank, adjusting certain covenants, the specifics of which are described
in the amended agreement.
On March 28, 2018, our Credit Facility
borrowing base was increased to $25.0 million. Pursuant to the credit agreement amendment entered into on March 27, 2018, we are
subject to a minimum liquidity covenant of $750,000.
Note 18– Supplemental Financial
Data – Oil and Gas Producing Activities (unaudited)
Estimated Proved Oil and Gas Reserves
The reserve estimates as of December 31,
2017 and 2016 presented herein were made in accordance with oil and gas reserve estimation and disclosure authoritative accounting
guidance.
Proved oil and gas reserves as of December
31, 2017 and 2016 were calculated based on the prices for oil and gas during the twelve-month period before the reporting date,
determined as an un-weighted arithmetic average of the first-day-of-the month price for each month within such period. This average
price is also used in calculating the aggregate amount and changes in future cash inflows related to the standardized measure
of discounted future cash flows. Undrilled locations can be classified as having proved undeveloped reserves only if a development
plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances justify
a longer time. SEC rules dictate the types of technologies that a company may use to establish reserve estimates, including the
extraction of non-traditional resources, such as bitumen extracted from oil sands as well as oil and gas extracted from shales.
Our estimates of our net proved, net proved
developed, and net proved undeveloped oil and gas reserves and changes in our net proved oil and gas reserves for 2017 and 2016
are presented in the table below. Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience
and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from
known reservoirs, and under existing economic conditions, operating methods, and government regulation before the time at which
contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain. Existing economic
conditions include the average prices for oil and gas during the twelve-month period prior to the reporting date of December 31,
2017 and 2016 unless prices are defined by contractual arrangements, excluding escalations based upon future conditions. Prices
do not include the effects of commodity derivatives. CGA evaluated and prepared independent estimated proved reserves quantities
and related pre-tax future cash flows as of December 31, 2017 and 2016. To facilitate the preparation of an independent reserve
study, we provided CGA our reserve database and related supporting technical, economic, production and ownership information.
Estimated reserves and related pre-tax future cash flows for the non-controlling interests of the consolidated partnerships included
in our consolidated financial statements were based on CGA’s estimated reserves and related pre-tax future cash flows for
the specific properties in the partnerships and have been added to CGA’s reserve estimates for December 31, 2017 and 2016.
See Note 3 for additional information.
Proved developed oil and gas reserves
are proved reserves that can be expected to be recovered (i) through existing wells with existing equipment and operating methods
or in which the cost of the required equipment is relatively minor compared with the cost of a new well or (ii) through installed
extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving
a well.
Proved undeveloped oil and gas reserves
are proved reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively
major expenditure is required for recompletion.
As of December 31, 2017, we held a 17.81%
and 27.24% proportionate share of Carbon California and Carbon Appalachia, respectively. This proportionate share amount reflects
our aggregated sharing percentage based on all classes of ownership held in each equity investee. These proportionate share amounts
assume each equity investee is operating as a going concern, and no adjustments have been made that could be required based on
priority of units and hurdle rates upon liquidation or distributions.
A summary of the changes in quantities
of proved oil and gas reserves for the years ended December 31, 2017 and 2016 are as follows (in thousands):
|
|
Company
|
|
|
Company’s
share of Carbon California
|
|
|
|
|
|
Company’s
share
of Carbon Appalchia
|
|
|
Total
|
|
|
|
Oil
|
|
|
Natural Gas
|
|
|
Total
|
|
|
Oil
|
|
|
Natural Gas
|
|
|
NGL
|
|
|
Total
|
|
|
Oil
|
|
|
Natural Gas
|
|
|
Total
|
|
|
Oil
|
|
|
Natural Gas
|
|
|
NGL
|
|
|
Total
|
|
|
|
MBbls
|
|
|
MMcf
|
|
|
MMcfe
|
|
|
MBbls
|
|
|
MMcf
|
|
|
(MBbls)
|
|
|
MMcfe
|
|
|
MBbls
|
|
|
MMcf
|
|
|
MMcfe
|
|
|
MBbls
|
|
|
MMcf
|
|
|
(MBbls)
|
|
|
MMcfe
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
January 1, 2016
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved reserves, beginning
of year
|
|
|
598
|
|
|
|
29,958
|
|
|
|
33,546
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
598
|
|
|
|
29,958
|
|
|
|
-
|
|
|
|
33,546
|
|
Revisions of previous estimates
|
|
|
110
|
|
|
|
2,207
|
|
|
|
2,867
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
110
|
|
|
|
2,207
|
|
|
|
-
|
|
|
|
2,867
|
|
Extensions and discoveries
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
Production
|
|
|
(79
|
)
|
|
|
(2,823
|
)
|
|
|
(3,297
|
)
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
(79
|
)
|
|
|
(2,823
|
)
|
|
|
-
|
|
|
|
(3,297
|
)
|
Purchases of reserves in-place
|
|
|
253
|
|
|
|
44,923
|
|
|
|
46,441
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
253
|
|
|
|
44,923
|
|
|
|
-
|
|
|
|
46,441
|
|
Sales
of reserves in-place
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
December 31,
2016
|
|
|
882
|
|
|
|
74,265
|
|
|
|
79,557
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
882
|
|
|
|
74,265
|
|
|
|
-
|
|
|
|
79,557
|
|
Revisions of previous estimates
|
|
|
107
|
|
|
|
12,195
|
|
|
|
12,835
|
|
|
|
-
|
|
|
|
-
|
|
|
|
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
107
|
|
|
|
12,195
|
|
|
|
-
|
|
|
|
12,837
|
|
Extensions and discoveries
|
|
|
16
|
|
|
|
138
|
|
|
|
232
|
|
|
|
-
|
|
|
|
-
|
|
|
|
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
16
|
|
|
|
138
|
|
|
|
-
|
|
|
|
234
|
|
Production (2)
|
|
|
(86
|
)
|
|
|
(4,896
|
)
|
|
|
(5,414
|
)
|
|
|
(25
|
)
|
|
|
(63
|
)
|
|
|
(4
|
)
|
|
|
(237
|
)
|
|
|
(2
|
)
|
|
|
(1,178
|
)
|
|
|
(1,328
|
)
|
|
|
(136
|
)
|
|
|
(4,984
|
)
|
|
|
(4
|
)
|
|
|
(5,824
|
)
|
Purchases of reserves in-place
(1)
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
1,650
|
|
|
|
3,075
|
|
|
|
231
|
|
|
|
14,361
|
|
|
|
74
|
|
|
|
91,935
|
|
|
|
101,835
|
|
|
|
3,300
|
|
|
|
4,725
|
|
|
|
231
|
|
|
|
25,911
|
|
Sales
of reserves in-place
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
|
|
|
|
-
|
|
December 31, 2017
|
|
|
919
|
|
|
|
81,702
|
|
|
|
87,210
|
|
|
|
1,625
|
|
|
|
3,012
|
|
|
|
227
|
|
|
|
14,124
|
|
|
|
72
|
|
|
|
90,757
|
|
|
|
100,507
|
|
|
|
4,169
|
|
|
|
86,339
|
|
|
|
227
|
|
|
|
112,715
|
|
(1)
|
Related to Carbon
Appalachia the purchases of reserves-in-place represent our aggregate share for the year ended December 31, 2017. We held
a 2.98%, 16.04%, 19.37%, and 27.24% proportionate share of Carbon Appalachia for the period April 3, 2017 through August 14,
2017; August 15, 2017 through September 28, 2017; September 29, 2017 through October 31, 2017; and November 1, 2017 through
December 31, 2017, respectively.
|
(2)
|
Related to Carbon
Appalachia, the net sales (in standard measure change) and production figures were calculated utilizing the same methodology
as the purchase of reserves-in-place discussed above.
|
|
|
2017
|
|
|
2016
|
|
|
|
Oil
(MBbls)
|
|
|
Natural Gas (MMcf)
|
|
|
NGL (MBbls)
|
|
|
Total (MMcfe)
|
|
|
Oil
(MBbls)
|
|
|
Natural Gas (MMcf)
|
|
|
NGL
(MBbls)
|
|
|
Total (MMcfe)
|
|
Company
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved developed reserves at:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
End of Year
|
|
|
903
|
|
|
|
81,702
|
|
|
|
-
|
|
|
|
87,120
|
|
|
|
851
|
|
|
|
74,265
|
|
|
|
-
|
|
|
|
79,557
|
|
Proved undeveloped reserves at:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
End of Year
|
|
|
16
|
|
|
|
-
|
|
|
|
-
|
|
|
|
96
|
|
|
|
31
|
|
|
|
-
|
|
|
|
-
|
|
|
|
186
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Company’s share of Carbon California
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved developed reserves at:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
End of Year
|
|
|
1,006
|
|
|
|
2,194
|
|
|
|
163
|
|
|
|
9,208
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
Proved undeveloped reserves at:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
End of Year
|
|
|
619
|
|
|
|
818
|
|
|
|
63
|
|
|
|
4,910
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Company’s share of Carbon Appalachia
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved developed reserves at:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
End of Year (1) (2)
|
|
|
72
|
|
|
|
90,757
|
|
|
|
-
|
|
|
|
91,189
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
Proved undeveloped reserves at:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
End of Year
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved developed reserves at:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
-
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
End of Year
|
|
|
1,981
|
|
|
|
174,653
|
|
|
|
163
|
|
|
|
187,517
|
|
|
|
851
|
|
|
|
74,265
|
|
|
|
-
|
|
|
|
79,557
|
|
Proved undeveloped reserves at:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
-
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
End of Year
|
|
|
635
|
|
|
|
818
|
|
|
|
63
|
|
|
|
5,006
|
|
|
|
31
|
|
|
|
-
|
|
|
|
-
|
|
|
|
186
|
|
(1)
|
Related to Carbon
Appalachia the purchases of reserves-in-place represent our aggregate share for the year ended December 31, 2017. We held
a 2.98%, 16.04%, 19.37%, and 27.24% proportionate share of Carbon Appalachia for the period April 3, 2017 through August 14,
2017; August 15, 2017 through September 28, 2017; September 29, 2017 through October 31, 2017; and November 1, 2017 through
December 31, 2017, respectively.
|
(2)
|
Related to Carbon
Appalachia, the net sales (in standard measure change) and production figures were calculated utilizing the same methodology
as the purchase of reserves-in-place discussed above.
|
|
|
2017
|
|
|
2016
|
|
|
|
Oil
|
|
|
Natural Gas
|
|
|
Total
|
|
|
Oil
|
|
|
Natural Gas
|
|
|
Total
|
|
|
|
MBbls
|
|
|
MMcf
|
|
|
MMcfe
|
|
|
MBbls
|
|
|
MMcf
|
|
|
MMcfe
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved reserves, beginning of year
|
|
|
882
|
|
|
|
74,265
|
|
|
|
79,557
|
|
|
|
598
|
|
|
|
29,958
|
|
|
|
33,546
|
|
Revisions of previous estimates
|
|
|
107
|
|
|
|
12,195
|
|
|
|
12,837
|
|
|
|
110
|
|
|
|
2207
|
|
|
|
2867
|
|
Extensions and discoveries
|
|
|
16
|
|
|
|
138
|
|
|
|
234
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
Production
|
|
|
(86
|
)
|
|
|
(4,896
|
)
|
|
|
(5,412
|
)
|
|
|
(79
|
)
|
|
|
(2,823
|
)
|
|
|
(3,297
|
)
|
Purchases of reserves in-place (1) (2)
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
253
|
|
|
|
44,923
|
|
|
|
46,441
|
|
Sales of reserves in-place
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
Proved reserves, end of year
|
|
|
919
|
|
|
|
81,702
|
|
|
|
87,216
|
|
|
|
882
|
|
|
|
74,265
|
|
|
|
79,557
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved developed reserves at:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
End of Year
|
|
|
903
|
|
|
|
81,702
|
|
|
|
87,120
|
|
|
|
882
|
|
|
|
74,265
|
|
|
|
79,371
|
|
Proved undeveloped reserves at:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
End of Year
|
|
|
16
|
|
|
|
-
|
|
|
|
96
|
|
|
|
31
|
|
|
|
-
|
|
|
|
186
|
|
(1)
|
Related to Carbon
Appalachia the purchases of reserves-in-place represent our aggregate share for the year ended December 31, 2017. We held
a 2.98%, 16.04%, 19.37%, and 27.24% proportionate share of Carbon Appalachia for the period April 3, 2017 through August 14,
2017; August 15, 2017 through September 28, 2017; September 29, 2017 through October 31, 2017; and November 1, 2017 through
December 31, 2017, respectively.
|
(2)
|
Related to Carbon
Appalachia, the net sales (in standard measure change) and production figures were calculated utilizing the same methodology
as the purchase of reserves-in-place discussed above.
|
The estimated proved reserves for December
31, 2017 and 2016 includes approximately 3.0 and 3.1 Bcfe, respectively, attributed to non-controlling interests of consolidated
partnerships.
Aggregate Capitalized Costs
The aggregate capitalized costs relating
to oil and gas producing activities at the end of each of the years indicated were as follows:
|
|
2017
|
|
|
2016
|
|
(in thousands)
|
|
|
|
Oil and gas properties
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Company
|
|
|
|
|
|
|
Proved oil and gas properties
|
|
$
|
114,893
|
|
|
$
|
112,579
|
|
Unproved properties not subject to depletion
|
|
|
1,947
|
|
|
|
1,999
|
|
Accumulated depreciation, depletion, amortization and impairment
|
|
|
(80,715
|
)
|
|
|
(78,596
|
)
|
Total Company oil and gas properties, net
|
|
$
|
36,125
|
|
|
$
|
35,982
|
|
|
|
|
|
|
|
|
|
|
Company’s share of Carbon California
|
|
|
|
|
|
|
|
|
Proved oil and gas properties
|
|
$
|
7,635
|
|
|
$
|
-
|
|
Unproved properties not subject to depletion
|
|
|
266
|
|
|
|
-
|
|
Accumulated depreciation, depletion, amortization and impairment
|
|
|
(208
|
)
|
|
|
-
|
|
Total Company’s share of Carbon California oil and gas properties,
net
|
|
$
|
7,693
|
|
|
$
|
-
|
|
|
|
|
|
|
|
|
|
|
Company’s share of Carbon Appalachia
|
|
|
|
|
|
|
|
|
Proved oil and gas properties
|
|
$
|
22,951
|
|
|
$
|
-
|
|
Unproved properties not subject to depletion
|
|
|
485
|
|
|
|
-
|
|
Accumulated depreciation, depletion, amortization and impairment
|
|
|
(445
|
)
|
|
|
-
|
|
Total Company’s share of Carbon Appalachia
oil and gas properties, net
|
|
$
|
22,991
|
|
|
$
|
-
|
|
Costs Incurred in Oil and Gas Property
Acquisition, Exploration, and Development Activities
The following costs were incurred in oil
and gas property acquisition, exploration, and development activities during the years ended December 31, 2017 and 2016:
|
|
2017
|
|
|
2016
|
|
(in thousands)
|
|
|
|
|
|
|
Company
|
|
|
|
|
|
|
Property acquisition costs:
|
|
|
|
|
|
|
Unevaluated properties
|
|
$
|
1
|
|
|
$
|
97
|
|
Proved properties and gathering facilities
|
|
|
289
|
|
|
|
8,117
|
|
Development costs
|
|
|
952
|
|
|
|
360
|
|
Gathering facilities
|
|
|
43
|
|
|
|
42
|
|
Asset retirement obligation
|
|
|
2,309
|
|
|
|
1,849
|
|
Total costs incurred
|
|
$
|
3,594
|
|
|
$
|
10,465
|
|
|
|
|
|
|
|
|
|
|
Company’s share of Carbon California
|
|
|
|
|
|
|
|
|
Property acquisition costs:
|
|
|
|
|
|
|
|
|
Unevaluated properties
|
|
$
|
266
|
|
|
$
|
-
|
|
Proved properties and gathering facilities
|
|
|
7,682
|
|
|
|
-
|
|
Development costs
|
|
|
412
|
|
|
|
-
|
|
Gathering facilities
|
|
|
47
|
|
|
|
-
|
|
Asset retirement obligation
|
|
|
483
|
|
|
|
-
|
|
Total costs incurred
|
|
$
|
8,890
|
|
|
$
|
-
|
|
|
|
|
|
|
|
|
|
|
Company’s share of Carbon Appalachia
|
|
|
|
|
|
|
|
|
Property acquisition costs:
|
|
|
|
|
|
|
|
|
Unevaluated properties
|
|
$
|
483
|
|
|
$
|
-
|
|
Proved properties and gathering facilities
|
|
|
19,286
|
|
|
|
-
|
|
Development costs
|
|
|
24
|
|
|
|
-
|
|
Gathering facilities
|
|
|
2,544
|
|
|
|
-
|
|
Asset retirement obligation
|
|
|
3,592
|
|
|
|
-
|
|
Total costs incurred
|
|
$
|
25,929
|
|
|
$
|
-
|
|
Our investment in unproved properties
as of December 31, 2017, by the year in which such costs were incurred is set forth in the table below:
|
|
2017
|
|
|
2016
|
|
|
2015
and Prior
|
|
(in thousands)
|
|
|
|
|
|
|
|
|
|
Acquisition costs
|
|
|
|
|
|
|
|
|
|
Company
|
|
$
|
1
|
|
|
$
|
97
|
|
|
$
|
1,849
|
|
Company’s share of Carbon California
|
|
|
266
|
|
|
|
-
|
|
|
|
-
|
|
Company’s share of Carbon Appalachia
|
|
|
485
|
|
|
|
-
|
|
|
|
-
|
|
Total acquisition costs
|
|
$
|
752
|
|
|
$
|
97
|
|
|
$
|
1,849
|
|
Results of Operations from Oil and
Gas Producing Activities
Results of operations from oil and gas
producing activities for the years ended December 31, 2017 and 2016 are presented below:
(in thousands)
|
|
|
|
|
|
2017
|
|
|
2016
|
|
|
|
|
|
|
|
|
Revenues
|
|
|
|
|
|
|
Oil and gas sales, including commodity derivative gains and losses
|
|
|
|
|
|
|
Company
|
|
$
|
22,439
|
|
|
$
|
8,184
|
|
Company’s share of Carbon California
|
|
$
|
1,289
|
|
|
$
|
-
|
|
Company’s share of Carbon Appalachia
|
|
|
5,273
|
|
|
|
-
|
|
Total oil and gas sales, including commodity derivative gains and losses
|
|
|
29,001
|
|
|
|
8,184
|
|
|
|
|
|
|
|
|
|
|
Expenses:
|
|
|
|
|
|
|
|
|
Production expenses
|
|
|
|
|
|
|
|
|
Company
|
|
|
9,589
|
|
|
|
5,640
|
|
Company’s share of Carbon California
|
|
|
664
|
|
|
|
-
|
|
Company’s share of Carbon Appalachia
|
|
|
1,522
|
|
|
|
-
|
|
Total production expenses
|
|
|
11,775
|
|
|
|
5,640
|
|
|
|
|
|
|
|
|
|
|
Depletion expense
|
|
|
|
|
|
|
|
|
Company
|
|
|
2,157
|
|
|
|
1,839
|
|
Company’s share of Carbon California
|
|
|
208
|
|
|
|
-
|
|
Company’s share of Carbon Appalachia
|
|
|
445
|
|
|
|
-
|
|
Total depletion expense
|
|
|
2,810
|
|
|
|
1,839
|
|
|
|
|
|
|
|
|
|
|
Accretion of asset retirement obligations
|
|
|
|
|
|
|
|
|
Company
|
|
|
307
|
|
|
|
176
|
|
Company’s share of Carbon California
|
|
|
34
|
|
|
|
-
|
|
Company’s share of Carbon Appalachia
|
|
|
54
|
|
|
|
-
|
|
Total accretion of asset obligation
|
|
|
395
|
|
|
|
176
|
|
|
|
|
|
|
|
|
|
|
Impairment of oil and gas properties
|
|
|
|
|
|
|
|
|
Company
|
|
|
-
|
|
|
|
4,299
|
|
Company’s share of Carbon California
|
|
|
-
|
|
|
|
-
|
|
Company’s share of Carbon Appalachia
|
|
|
-
|
|
|
|
-
|
|
Total accretion of asset obligation
|
|
|
-
|
|
|
|
4,299
|
|
|
|
|
|
|
|
|
|
|
Total expenses
|
|
|
14,979
|
|
|
|
11,954
|
|
Results of operations from oil and gas producing
activities
|
|
$
|
14,021
|
|
|
$
|
(3,770
|
)
|
|
|
|
|
|
|
|
|
|
Depletion rate per Mcfe
|
|
$
|
0.47
|
|
|
$
|
0.56
|
|
Standardized Measure of Discounted
Future Net Cash Flows
Future oil and gas sales are calculated
applying the prices used in estimating our proved oil and gas reserves to the year-end quantities of those reserves. Future price
changes were considered only to the extent provided by contractual arrangements in existence at each year-end. Future production
and development costs, which include costs related to plugging of wells, removal of facilities and equipment, and site restoration,
are calculated by estimating the expenditures to be incurred in producing and developing the proved oil and gas reserves at the
end of each year, based on year-end costs and assuming continuation of existing economic conditions. Future income tax expenses
are computed by applying the appropriate year-end statutory tax rates to the estimated future pretax net cash flows relating to
proved oil and gas reserves, less the tax basis of the properties involved. The future income tax expenses give effect to tax
deductions, credits, and allowances relating to the proved oil and gas reserves. Carbon California and Carbon Appalachia does
not include the future net effect of income taxes because Carbon California and Carbon Appalachia is treated as partnerships for
tax purposes and is not subject to federal income taxes. All cash flow amounts, including income taxes, are discounted at 10%.
Changes in the demand for oil and natural
gas, inflation, and other factors make such estimates inherently imprecise and subject to substantial revision. This table should
not be construed to be an estimate of the current market value of our proved reserves. Management does not rely upon the information
that follows in making investment decisions.
(in thousands)
|
|
December 31,
|
|
|
|
2017
|
|
|
2016
|
|
|
|
|
|
|
|
|
Company:
|
|
|
|
|
|
|
Future cash inflows
|
|
$
|
283,664
|
|
|
$
|
214,658
|
|
Future production costs
|
|
|
(119,501
|
)
|
|
|
(103,252
|
)
|
Future development costs
|
|
|
(210
|
)
|
|
|
(315
|
)
|
Future income taxes
|
|
|
(35,482
|
)
|
|
|
(14,858
|
)
|
Future net cash flows
|
|
|
128,471
|
|
|
|
96,233
|
|
10% annual discount
|
|
|
(71,389
|
)
|
|
|
(51,522
|
)
|
Standardized measure of discounted future net cash
flows
|
|
$
|
57,082
|
|
|
$
|
44,711
|
|
|
|
|
|
|
|
|
|
|
Company’s share of Carbon California
|
|
|
|
|
|
|
|
|
Future cash inflows
|
|
$
|
97,841
|
|
|
$
|
-
|
|
Future production costs
|
|
|
(62,187
|
)
|
|
|
-
|
|
Future development costs
|
|
|
(5,809
|
)
|
|
|
-
|
|
Future income taxes (2)
|
|
|
-
|
|
|
|
-
|
|
Future net cash flows
|
|
|
29,845
|
|
|
|
-
|
|
10% annual discount
|
|
|
(16,288
|
)
|
|
|
-
|
|
Standardized measure of discounted future net cash
flows
|
|
$
|
13,557
|
|
|
$
|
-
|
|
|
|
|
|
|
|
|
|
|
Company’s share of Carbon Appalachia
|
|
|
|
|
|
|
|
|
Future cash inflows (1) (4)
|
|
$
|
271,638
|
|
|
$
|
-
|
|
Future production costs (1)
|
|
|
(151,501
|
)
|
|
|
-
|
|
Future development costs (1)
|
|
|
(27
|
)
|
|
|
-
|
|
Future income taxes (3)
|
|
|
-
|
|
|
|
-
|
|
Future net cash flows
|
|
|
120,110
|
|
|
|
-
|
|
10% annual discount
|
|
|
(73,890
|
)
|
|
|
-
|
|
Standardized measure of discounted future net cash
flows
|
|
$
|
46,220
|
|
|
$
|
-
|
|
|
(1)
|
Related to Carbon
Appalachia the purchases of reserves-in-place represent our aggregate share for the year ended December 31, 2017. We held
a 2.98%, 16.04%, 19.37%, and 27.24% proportionate share of Carbon Appalachia for the period April 3, 2017 through August 14,
2017; August 15, 2017 through September 28, 2017; September 29, 2017 through October 31, 2017; November 1, 2017 through December
31, 2017, respectively.
|
|
(2)
|
Carbon California
does not include the net changes in future income taxes because Carbon California is treated as a partnership for taxes and
is not subject to federal income taxes.
|
|
(3)
|
Carbon Appalachia
does not include the net changes in future income taxes because Carbon California is treated as a partnership for taxes and
is not subject to federal income taxes
|
|
(4)
|
Related to Carbon
Appalachia, the net sales (in standard measure change) and production figures was calculated utilizing the same methodology
as the purchase of reserves-in-place discussed above.
|
Changes in the Standardized Measure
of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves
An analysis of the changes in the standardized
measure of discounted future net cash flows during each of the last two years is as follows:
|
|
December 31,
|
|
|
|
Company
|
|
|
Company’s Share of Carbon California
|
|
|
Company’s Share of Carbon Appalachia
|
|
|
Total
|
|
(in thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at January 1, 2016
|
|
|
|
|
|
|
|
|
|
|
|
|
Standardized measure of discounted future net
cash flows, beginning of year
|
|
$
|
25,032
|
|
|
$
|
-
|
|
|
$
|
-
|
|
|
$
|
25,032
|
|
Sales of oil and gas, net of production costs and taxes
|
|
|
(4,804
|
)
|
|
|
-
|
|
|
|
-
|
|
|
|
(4,804
|
)
|
Price revisions
|
|
|
(786
|
)
|
|
|
-
|
|
|
|
-
|
|
|
|
(786
|
)
|
Extensions, discoveries and improved recovery, less related
costs
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
Changes in estimated future development costs
|
|
|
248
|
|
|
|
-
|
|
|
|
-
|
|
|
|
248
|
|
Development costs incurred during the period
|
|
|
102
|
|
|
|
-
|
|
|
|
-
|
|
|
|
102
|
|
Quantity revisions
|
|
|
2,091
|
|
|
|
-
|
|
|
|
-
|
|
|
|
2,091
|
|
Accretion of discount
|
|
|
2,503
|
|
|
|
-
|
|
|
|
-
|
|
|
|
2,503
|
|
Net changes in future income taxes
|
|
|
(4,633
|
)
|
|
|
-
|
|
|
|
-
|
|
|
|
(4,633
|
)
|
Purchases of reserves-in-place
|
|
|
26,776
|
|
|
|
-
|
|
|
|
-
|
|
|
|
26,776
|
|
Sales of reserves-in-place
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
Changes in production rate timing
and other
|
|
|
(1,818
|
)
|
|
|
-
|
|
|
|
-
|
|
|
|
(1,818
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at December 31, 2016
|
|
$
|
44,711
|
|
|
$
|
-
|
|
|
$
|
-
|
|
|
$
|
44,711
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales of oil and gas, net of production costs and taxes
(4)
|
|
|
(10,038
|
)
|
|
|
(516
|
)
|
|
|
(1,240
|
)
|
|
|
(12,231
|
)
|
Price revisions
|
|
|
17,588
|
|
|
|
-
|
|
|
|
-
|
|
|
|
17,588
|
|
Extensions, discoveries and improved recovery, less related
costs
|
|
|
298
|
|
|
|
-
|
|
|
|
-
|
|
|
|
298
|
|
Changes in estimated future development costs
|
|
|
(324
|
)
|
|
|
-
|
|
|
|
-
|
|
|
|
(324
|
)
|
Development costs incurred during the period
|
|
|
804
|
|
|
|
-
|
|
|
|
-
|
|
|
|
804
|
|
Quantity revisions
|
|
|
11,196
|
|
|
|
-
|
|
|
|
-
|
|
|
|
11,196
|
|
Accretion of discount
|
|
|
4,471
|
|
|
|
-
|
|
|
|
-
|
|
|
|
4,471
|
|
Net changes in future income taxes (2) (3)
|
|
|
(7,425
|
)
|
|
|
-
|
|
|
|
-
|
|
|
|
(7,425
|
)
|
Purchases of reserves-in-place (1)
|
|
|
-
|
|
|
|
14,073
|
|
|
|
47,460
|
|
|
|
61,533
|
|
Sales of reserves-in-place
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
Changes in production rate timing
and other
|
|
|
(4,199
|
)
|
|
|
-
|
|
|
|
-
|
|
|
|
(4,199
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Standardized
measure of discounted future net cash flows, at
December 31, 2017
|
|
$
|
57,082
|
|
|
$
|
13,557
|
|
|
$
|
46,220
|
|
|
$
|
116,422
|
|
|
(1)
|
Related to Carbon
Appalachia the purchases of reserves-in-place represent our aggregate share for the year ended December 31, 2017. We held
a 2.98%, 16.04%, 19.37%, and 27.24% proportionate share of Carbon Appalachia for the period April 3, 2017 through August 14,
2017; August 15, 2017 through September 28, 2017; September 29, 2017 through October 31, 2017; and November 1, 2017 through
December 31, 2017, respectively.
|
|
(2)
|
Carbon California
does not include the net changes in future income taxes because Carbon California is treated as a partnership for taxes and
is not subject to federal income taxes.
|
|
(3)
|
Carbon Appalachia
does not include the net changes in future income taxes because Carbon California is treated as a partnership for taxes and
is not subject to federal income taxes.
|
|
(4)
|
Related to Carbon
Appalachia, the net sales (in standard measure change) and production figures was calculated utilizing the same methodology
as the purchase of reserves-in-place discussed above.
|
The twelve-month weighted averaged adjusted
prices in effect at December 31, 2017 and 2016 were as follows:
|
|
2017
|
|
|
2016
|
|
Oil
(per Bbl)
|
|
$
|
51.34
|
|
|
$
|
40.40
|
|
Natural Gas (per
Mcf)
|
|
$
|
2.98
|
|
|
$
|
2.41
|
|
CARBON APPALACHIAN
COMPANY, LLC
Consolidated Balance Sheets
(In thousands)
|
|
June 30,
|
|
|
December 31,
|
|
|
|
2018
|
|
|
2017
|
|
ASSETS
|
|
(unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
Current assets:
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$
|
12,657
|
|
|
$
|
4,512
|
|
Accounts receivable:
|
|
|
|
|
|
|
|
|
Revenue
|
|
|
3,133
|
|
|
|
10,682
|
|
Trade receivables
|
|
|
3,880
|
|
|
|
1,569
|
|
Commodity derivative asset
|
|
|
60
|
|
|
|
1,884
|
|
Inventories
|
|
|
1,230
|
|
|
|
1,660
|
|
Prepaid expense and deposits
|
|
|
515
|
|
|
|
487
|
|
Total current assets
|
|
|
21,475
|
|
|
|
20,794
|
|
|
|
|
|
|
|
|
|
|
Property and equipment (see note 4)
|
|
|
|
|
|
|
|
|
Oil and gas properties, full cost method of accounting:
|
|
|
|
|
|
|
|
|
Proved, net
|
|
|
81,722
|
|
|
|
82,622
|
|
Unproved
|
|
|
1,819
|
|
|
|
1,780
|
|
Other property, plant, and equipment, net
|
|
|
10,842
|
|
|
|
12,677
|
|
Total property and equipment
|
|
|
94,383
|
|
|
|
97,079
|
|
|
|
|
|
|
|
|
|
|
Other non-current assets
|
|
|
1,109
|
|
|
|
683
|
|
Total assets
|
|
$
|
116,967
|
|
|
$
|
118,556
|
|
|
|
|
|
|
|
|
|
|
LIABILITIES AND MEMBERS’ EQUITY
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current liabilities:
|
|
|
|
|
|
|
|
|
Accounts payable and accrued liabilities
|
|
$
|
9,883
|
|
|
$
|
12,070
|
|
Due to related parties (see note 10)
|
|
|
1,087
|
|
|
|
1,852
|
|
Firm transportation contract obligation (see
note 9)
|
|
|
3,561
|
|
|
|
4,285
|
|
Total current liabilities
|
|
|
14,531
|
|
|
|
18,207
|
|
|
|
|
|
|
|
|
|
|
Non-current liabilities:
|
|
|
|
|
|
|
|
|
Asset retirement obligations
|
|
|
4,818
|
|
|
|
4,789
|
|
Firm transportation contract obligation
|
|
|
13,227
|
|
|
|
14,843
|
|
Production and property taxes payable
|
|
|
2,008
|
|
|
|
1,813
|
|
Revolver (see note 5)
|
|
|
37,975
|
|
|
|
37,975
|
|
Total non-current liabilities
|
|
|
58,028
|
|
|
|
59,420
|
|
|
|
|
|
|
|
|
|
|
Commitments and contingencies (see note 9)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Members’ equity:
|
|
|
|
|
|
|
|
|
Members’ contributions
|
|
|
37,924
|
|
|
|
37,924
|
|
Retained earnings
|
|
|
6,484
|
|
|
|
3,005
|
|
Total members’ equity
|
|
|
44,408
|
|
|
|
40,929
|
|
|
|
|
|
|
|
|
|
|
Total liabilities and members’ equity
|
|
$
|
116,967
|
|
|
$
|
118,556
|
|
See accompanying Notes to Consolidated
Financial Statements.
CARBON APPALACHIAN COMPANY, LLC
Consolidated Statement of Operations
(In thousands)
|
|
Three months ended
|
|
|
For the period
April 3,
2017
through
|
|
|
Six months
ended
|
|
|
|
June 30,
2018
|
|
|
June 30,
2017
|
|
|
June 30,
2018
|
|
|
|
(unaudited)
|
|
|
(unaudited)
|
|
|
(unaudited)
|
|
Revenue:
|
|
|
|
|
|
|
|
|
|
Natural gas sales
|
|
$
|
12,621
|
|
|
$
|
1,007
|
|
|
$
|
25,556
|
|
Oil sales
|
|
|
255
|
|
|
|
154
|
|
|
|
813
|
|
Transportation and handling
|
|
|
694
|
|
|
|
241
|
|
|
|
1,476
|
|
Marketing gas sales
|
|
|
5,602
|
|
|
|
-
|
|
|
|
17,046
|
|
Commodity derivative gain (loss)
|
|
|
(493
|
)
|
|
|
155
|
|
|
|
(469
|
)
|
Total revenue
|
|
|
18,679
|
|
|
|
1,557
|
|
|
|
44,422
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating
|
|
|
5,262
|
|
|
|
233
|
|
|
|
10,961
|
|
Transportation, gathering, and compression
|
|
|
1,962
|
|
|
|
147
|
|
|
|
5,921
|
|
Production and property taxes
|
|
|
1,098
|
|
|
|
35
|
|
|
|
2,278
|
|
Marketing gas purchases
|
|
|
4,652
|
|
|
|
-
|
|
|
|
13,912
|
|
General and administrative
|
|
|
844
|
|
|
|
770
|
|
|
|
1,383
|
|
Management and operating fee, related party (see note 10)
|
|
|
1,050
|
|
|
|
75
|
|
|
|
2,102
|
|
Depreciation, depletion and amortization
|
|
|
1,218
|
|
|
|
493
|
|
|
|
2,934
|
|
Accretion of asset retirement obligations
|
|
|
135
|
|
|
|
74
|
|
|
|
265
|
|
Total expenses
|
|
|
16,221
|
|
|
|
1,757
|
|
|
|
39,756
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income (loss)
|
|
|
2,458
|
|
|
|
(200
|
)
|
|
|
4,666
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense
|
|
|
(605
|
)
|
|
|
(129
|
)
|
|
|
(1,187
|
)
|
Total other expense
|
|
|
(605
|
)
|
|
|
(129
|
)
|
|
|
(1,187
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
$
|
1,854
|
|
|
$
|
(329
|
)
|
|
$
|
3,479
|
|
See accompanying Notes to Consolidated
Financial Statements.
CARBON APPALACHIAN COMPANY, LLC
Consolidated Statement of Members’ Equity
(In thousands, except unit amounts) (unaudited)
|
|
Members'
Contributions
|
|
|
|
|
|
Total
|
|
|
|
Class
A Units
|
|
|
Amount
|
|
|
Class
B Units
|
|
|
Amount
|
|
|
Class
C Units
|
|
|
Amount
|
|
|
Retained
Earnings
|
|
|
Members'
Equity
|
|
Balances at December 31,
2017
|
|
|
37,000
|
|
|
$
|
37,000
|
|
|
|
1,000
|
|
|
$
|
924
|
|
|
|
121
|
|
|
$
|
-
|
|
|
$
|
3,005
|
|
|
$
|
40,929
|
|
Net income
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
3,479
|
|
|
|
3,479
|
|
Balances at June 30, 2018
|
|
|
37,000
|
|
|
$
|
37,000
|
|
|
|
1,000
|
|
|
$
|
924
|
|
|
|
121
|
|
|
$
|
-
|
|
|
$
|
6,484
|
|
|
$
|
44,408
|
|
See accompanying Notes to Consolidated
Financial Statements.
CARBON APPALACHIAN
COMPANY, LLC
Consolidated Statement of Cash Flows
(In thousands)
|
|
For the six months ended June 30,
|
|
|
|
2018
|
|
|
|
(unaudited)
|
|
Cash flows from operating activities:
|
|
|
|
Net income
|
|
$
|
3,479
|
|
Items not involving cash:
|
|
|
|
|
Depreciation, depletion and amortization
|
|
|
2,934
|
|
Accretion of asset retirement obligations
|
|
|
265
|
|
Commodity derivative gain
|
|
|
1,371
|
|
(Gain)/loss on sale of property and equipment
|
|
|
(20
|
)
|
Amortization of Revolver issuance costs
|
|
|
95
|
|
Net change in:
|
|
|
|
|
Accounts receivable
|
|
|
5,238
|
|
Inventories
|
|
|
430
|
|
Prepaid expense and deposits
|
|
|
(28
|
)
|
Accounts payable, accrued liabilities and firm transportation contract
obligations
|
|
|
(4,536
|
)
|
Due to related parties
|
|
|
(765
|
)
|
Net cash provided by operating activities
|
|
|
8,463
|
|
|
|
|
|
|
Cash flows from investing activities:
|
|
|
|
|
Development of oil and gas properties
|
|
|
(396
|
)
|
Purchases of property and equipment
|
|
|
(47
|
)
|
Sale of property and equipment
|
|
|
225
|
|
Net cash used in investing activities
|
|
|
(218
|
)
|
|
|
|
|
|
Cash flows from financing activities:
|
|
|
|
|
Debt issuance costs
|
|
|
(100
|
)
|
Net cash used in financing activities
|
|
|
(100
|
)
|
|
|
|
|
|
Net increase in cash and cash equivalents
|
|
|
8,145
|
|
|
|
|
|
|
Cash and cash equivalents, beginning of period
|
|
|
4,512
|
|
|
|
|
|
|
Cash and cash equivalents, end of period
|
|
$
|
12,657
|
|
See note 11 – Supplemental Cash Flow Disclosure
See accompanying Notes to Consolidated
Financial Statements.
Notes to Consolidated
Financial Statements
Note 1 – Organization
On December 16, 2016, Carbon Appalachian
Company, LLC (the “Company” or “CAC”) was formed, as a Delaware limited liability company, by Carbon Energy
Corporation (“Carbon”) a Delaware Corporation, entities managed by Yorktown Energy Partners XI, L.P. (“Yorktown”),
and entities managed by Old Ironsides (“Old Ironsides”), to acquire producing assets in the Appalachian Basin in Kentucky,
Tennessee, Virginia and West Virginia. The Company began substantial operations on April 3, 2017. The Company is engaged primarily
in acquiring, developing, exploiting, producing, processing, marketing, and transporting oil and natural gas in the Appalachia
Basin.
Equity and ownership
On April 3, 2017, Carbon, Yorktown
and Old Ironsides entered in to a limited liability company agreement (the “Carbon Appalachia LLC Agreement”), with
an initial equity commitment of $100.0 million, of which $37.0 million has been contributed as of June 30, 2018.
On April 3, 2017, the Company (i) issued
Class A Units to Carbon, Yorktown and Old Ironsides for an aggregate cash consideration of $12.0 million, (ii) issued Class B Units
to Carbon, and (iii) issued Class C Units to Carbon. Additionally, Carbon Appalachia Enterprises, LLC, formerly known as Carbon
Tennessee Company, LLC (“Carbon Appalachia Enterprises”), a subsidiary of the Company, entered into a 4-year $100.0
million senior secured asset-based revolving credit facility with LegacyTexas Bank (the “Revolver”) with an initial
borrowing base of $10.0 million.
On April 3, 2017, borrowings under
the Revolver, along with the initial equity contributions made to the Company, were used to complete the acquisition of natural
gas producing properties and related facilities located predominantly in Tennessee (the “Knox-Coalfield Acquisition”).
The purchase price was $20.0 million, subject to normal and customary closing adjustments. Carbon Appalachia Enterprises used
$8.5 million drawn from the credit facility toward the purchase price.
In connection with Carbon entering
into the Carbon Appalachia LLC Agreement, and Carbon Appalachia engaging in the transactions described above, Carbon received
1,000 Class B Units and issued to Yorktown a warrant to purchase approximately 408,000 shares of Carbon’s common stock at
an exercise price dictated by the warrant agreement (the “Appalachia Warrant”). The Appalachia Warrant is payable
exclusively with Class A Units of Carbon Appalachia held by Yorktown. On November 1, 2017, Yorktown exercised the Appalachia Warrant,
resulting in Carbon acquiring 2,940 Class A Units from Yorktown.
Net proceeds from the April 3, 2017
transactions were used by the Company to complete the Knox-Coalfield acquisition. The remainder of the net proceeds were used
to fund field development projects, future complementary acquisitions, and working capital.
On August 15, 2017, the Carbon Appalachia
LLC Agreement was amended and, as a result, Carbon will contribute its initial commitment of future capital contributions as well
as Yorktown’s, and Yorktown will not participate in future capital contributions. The Company issued Class A Units to Carbon
and Old Ironsides for an aggregate cash consideration of $14.0 million. The borrowing base of the Revolver increased to $22.0
million and Carbon Appalachia Enterprises borrowed $8.0 million under the Revolver.
On August 15, 2017, Carbon Appalachia
completed the acquisition of natural gas producing properties and related facilities located predominantly in the state of West
Virginia (the “Enervest Acquisition”). The purchase price was $21.5 million, subject to normal and customary closing
adjustments. The contributions from members and funds drawn from the credit facility were used to pay the purchase price.
On September 29, 2017, the Company issued
Class A Units to Carbon and Old Ironsides for an aggregate cash consideration of $11.0 million. The Revolver was amended to include
East West Bank as a participating lender, the borrowing base of the Revolver increased to $50.0 million and Carbon Appalachia
Enterprises borrowed $20.4 million from the Revolver.
On September 29, 2017, Carbon Appalachia
completed the acquisition of natural gas producing properties, natural gas gathering pipelines and related facilities located
predominantly in the state of West Virginia (the “Cabot Acquisition”). The purchase price was $41.3 million, subject
to normal and customary closing adjustments. The contributions from members and funds drawn from the credit facility were used
to pay the purchase price.
On November 30, 2017, Carbon Appalachia
Enterprises amended the Revolver, resulting in the addition of Bank SNB as a participating lender. The borrowing base of $50.0
million was unchanged.
On April 30, 2018, the Revolver was
amended, resulting in an increase in the borrowing base to $70.0 million (see note 12). As of June 30, 2018, the Revolver’s
borrowing base is $70.0 million, of which approximately $38.0 million is outstanding.
As of June 30, 2018, Old Ironsides
holds 27,195 Class A Units, which equates to a 72.76% aggregate share ownership of the Company and Carbon holds (i) 9,805 Class
A Units, (ii) 1,000 Class B Units and (iii) 121 Class C Units, which equates to a 27.24% aggregate share ownership of the Company.
Note 2 – Summary of Significant
Accounting Policies
Accounting policies used by the Company
reflect industry practices and conform to accounting principles generally accepted in the United States of America. The more significant
of such accounting policies are briefly discussed below.
Basis of Presentation
The accompanying unaudited condensed
consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United
States (“GAAP”) for interim financial information. Accordingly, they do not include all the information and footnotes
required by GAAP for complete financial statements. In the opinion of management, the accompanying unaudited condensed consolidated
financial statements include all adjustments (consisting of normal and recurring accruals) considered necessary to present fairly
our financial position as of June 30, 2018 and December 31, 2017, and our results of operations for the three and six months ended
June 30, 2018. Operating results for the six months ended June 30, 2018, are not necessarily indicative of the results that may
be expected for the full year because of the impact of fluctuations in prices received for oil and natural gas, natural production
declines, the uncertainty of exploration and development drilling results and other factors.
Principles of Consolidation
The consolidated financial statements
include the accounts of the Company and its consolidated subsidiaries. The Company’s subsidiaries consist of Carbon Tennessee
Mining Company, LLC, Carbon Appalachia Group, LLC, Carbon Appalachia Enterprises, LLC, Coalfield Pipeline Company, Knox Energy,
LLC, Carbon West Virginia Company, LLC and Cranberry Pipeline Corporation. All significant intercompany accounts and transactions
have been eliminated.
Asset Retirement Obligations
The Company’s asset retirement
obligations (“ARO”) relate to future costs associated with the plugging and abandonment of oil and gas wells, removal
of equipment and facilities from leased acreage and returning such land to its original condition. The fair value of a liability
for an ARO is recorded in the period in which it is incurred or assumed, and the amount of such liability is recorded as an increase
in the carrying amount of the related long-lived asset. The liability is accreted each period and the capitalized cost is depleted
on a units-of-production basis as part of the full cost pool. Revisions to estimated ARO result in adjustments to the related
capitalized asset and corresponding liability.
The estimated ARO liability is based
on estimated economic lives, estimates as to the cost to abandon the wells in the future, and federal and state regulatory requirements.
The liability is discounted using a credit-adjusted risk-free rate estimated at the time the liability is incurred or increased
from a reassessment of expected cash flows and assumptions inherent in the estimation of the liability. As of June 30, 2018, the
Company has $4.8 million as a non-current liability and $236,000 as a current liability within accounts payable. Revisions to
the liability could occur due to changes in estimated abandonment costs or well economic lives, or if federal or state regulators
enact new requirements regarding the abandonment of wells. ARO is valued utilizing Level 3 fair value measurement inputs (see
note 7).
The following table is a reconciliation
of ARO (in thousands).
|
|
For the six months ended
June 30,
2018
|
|
|
|
|
|
Balance at beginning of period
|
|
$
|
4,789
|
|
Accretion expense
|
|
|
265
|
|
|
|
|
|
|
Balance at end of period
|
|
$
|
5,054
|
|
Income Taxes
The Company has elected to be treated
as a partnership for income tax purposes. Accordingly, taxable income and losses are reported on the income tax returns of the
Company’s members and no provision for income taxes has been recorded on the accompanying financial statements. Interest
and penalties associated with tax positions are recorded in the period assessed as general and administrative expenses. The Company’s
tax returns are subject to examination by tax authorities through the current period for state and federal tax reporting purposes.
Pursuant to the Bipartisan Budget Act
of 2015 (the “Act”), as of January 1, 2018, the Act allows the adjustment resulting from IRS audits of partnerships
to be assessed at the partnership level.
Use of Estimates in the Preparation
of Financial Statements
The preparation of financial statements
in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions
that affect the reported amounts of assets, liabilities and expenses and disclosure of contingent assets and liabilities. Significant
items subject to such estimates and assumptions include the carrying value of oil and gas properties, estimates of proved oil
and gas reserve volumes and the related depletion and present value of estimated future net cash flows and the ceiling test applied
to capitalized oil and gas properties, determining the amounts recorded for fair value of commodity derivative instruments, fair
value of assets acquired and liabilities assumed qualifying as business combination or asset acquisition, estimated lives of other
property and equipment, asset retirement obligations and accrued liabilities and revenues.
Recently Adopted Accounting Pronouncement
In May 2014, the Financial Accounting
Standards Board (“FASB”) issued Accounting Standard Update (“ASU”) 2014-09,
Revenue from Contracts
with Customers
(Topic 606) (“ASU 2014-09”), which establishes a comprehensive new revenue recognition standard
designed to depict the transfer of goods or services to a customer in an amount that reflects the consideration the entity expects
to receive in exchange for those goods or services. In March 2016, the FASB released certain implementation guidance through ASU
2016-08 (collectively with ASU 2014-09, the “Revenue ASUs”) to clarify principal versus agent considerations. The
Revenue ASUs allow for the use of either the full or modified retrospective transition method, and the standard is effective for
annual reporting periods beginning after December 15, 2017 including interim periods within that period, with early adoption permitted
for annual reporting periods beginning after December 15, 2016. We adopted the guidance using the modified retrospective method
on the effective date of January 1, 2018. We did not record a cumulative-effect adjustment to the opening balance of retained
earnings as no adjustment was necessary. The adoption of the Revenue ASUs did not impact net income or cash flows. See note 10
for the new disclosures required by the Revenue ASUs.
Recently Issued Accounting Pronouncements
In February 2016, the FASB issued ASU
2016-02, “
Leases
(Topic 842)” (“ASU 2016-02”), which establishes a comprehensive new lease
standard designed to increase transparency and comparability among organizations by recognizing lease assets and lease liabilities
on the balance sheet and disclosing key information about leasing arrangements. In transition, lessees and lessors are required
to recognize and measure leases at the beginning of the earliest period presented using a modified retrospective approach. The
modified retrospective approach includes a number of optional practical expedients that entities may elect to apply. An entity
that elects to apply the practical expedients will, in effect, continue to account for leases that commence before the effective
date in accordance with previous GAAP standards. ASU 2016-02 is effective for fiscal years, beginning after December 15, 2020
and should be applied using a modified retrospective approach. Early adoption is permitted. The Company is currently evaluating
the impact on its financial statements of adopting ASU 2016-02.
There were various updates recently
issued by the FASB, most of which represented technical corrections to the accounting literature or application to specific industries
and are not expected to a have a material impact on our reported financial position, results of operations, or cash flows.
Note 3 – Acquisitions
Knox-Coalfield
On April 3, 2017, the Company acquired
natural gas producing properties and related facilities located predominantly in Tennessee for a purchase price of $20.0 million,
subject to normal purchase adjustments, with an effective date of February 1, 2017, for oil and gas assets and April 3, 2017 for
the corporate entity acquired (the “Knox-Coalfield Acquisition”). Consideration to fund the Knox-Coalfield Acquisition
was provided by contributions from the Company’s members of $12.0 million and $8.5 million in funds drawn from its Revolver
(see note 5).
The Knox-Coalfield Acquisition qualified
as a business combination as defined by Accounting Standards Codification (“ASC”) 805,
Business Combinations
and, as such, the Company estimated the fair value of the assets acquired and liabilities assumed as of the closing date of April
3, 2017.
The Company, utilizing the assistance
of third-party valuation specialists, considered various factors in its estimate of fair value of the acquired assets including
(i) reserves, (ii) production rates, (iii) future operating and development costs, (iv) future commodity prices, including price
differentials, (v) future cash flows, (vi) a market participant-based weighted average cost of capital, and (vii) real estate
market conditions.
The following table summarizes the
consideration paid and the estimated fair value of the assets acquired and liabilities assumed (in thousands).
Consideration paid:
|
|
|
|
Cash consideration
|
|
$
|
19,055
|
|
|
|
|
|
|
Recognized amounts of identifiable assets acquired and liabilities assumed:
|
|
|
|
|
Proved oil and gas properties
|
|
$
|
12,228
|
|
Unproved oil and gas properties
|
|
|
1,774
|
|
Property, plant, and equipment
|
|
|
5,858
|
|
Asset retirement obligation
|
|
|
(772
|
)
|
Accounts payable and accrued liabilities
|
|
|
(33
|
)
|
Total net assets acquired
|
|
$
|
19,055
|
|
Enervest
On August 15, 2017, the Company acquired
natural gas producing properties and related facilities located predominantly in the state of West Virginia for a purchase price
of $21.5 million, subject to normal purchase adjustments, with an effective date of May 1, 2017 (“Enervest Acquisition”).
Consideration to fund the Enervest Acquisition was provided by contributions from the Company’s members of $14.0 million
and $8.0 million in funds drawn from its Revolver (see note 5).
The assets acquired consist of oil and
gas leases and the associated mineral interests, oil and gas wells, a field office building and associated land, vehicles and other
miscellaneous equipment. The Company also acquired various contracts. The Company, utilizing the assistance of third-party valuation
specialists to estimate fair value, has determined that substantially all of the fair value of the assets acquired are related
to the production assets and, as such the Enervest Acquisition does not meet the definition of a business. Therefore, the Company
has accounted for the transaction as an asset acquisition and has allocated the purchase price based on the relative fair value
of the assets acquired.
In determining the relative fair value,
the fair value of the production assets was determined using the income approach using Level 3 inputs according to the ASC 820,
Fair Value
, hierarchy. The fair value of the other assets was determined using the market approach using Level 3 inputs.
The determination of the fair value of the oil and gas assets and other property and equipment acquired and accrued liabilities
assumed required significant judgement, including estimates relating to the production assets and the other assets acquired. The
Company recorded $1.8 million in ARO, $162,000 in firm transportation contract obligations and $247,000 in accounts payable and
accrued liabilities associated with the acquired assets. Below is the detail of the assets acquired (in thousands):
Identifiable assets acquired:
|
|
|
|
Assets:
|
|
|
|
Proved (producing) oil and gas properties
|
|
$
|
20,948
|
|
Property, plant and equipment
|
|
|
150
|
|
Total identified assets
|
|
$
|
21,098
|
|
Cabot
On September 29, 2017, the Company
acquired natural gas producing properties and related facilities as well as transmission pipeline facilities and equipment located
predominantly in the state of West Virginia for a purchase price of $41.3 million, subject to normal purchase adjustments, with
an effective date of April 1, 2017 for oil and gas assets and September 29, 2017, for the corporate entity acquired (the “Cabot
Acquisition”). Consideration to fund the Cabot Acquisition was provided by contributions from the Company’s members
of $11.0 million and $20.4 million in funds drawn from its Revolver (see note 5).
The Cabot Acquisition qualified as
a business combination as defined by ASC 805,
Business Combinations,
and, as such, the Company estimated the fair value
of the assets acquired and liabilities assumed as of the closing date of September 29, 2017.
The Company, utilizing the assistance of
third-party valuation specialists, considered various factors in its estimate of fair value of the acquired assets and liabilities
including (i) reserves, (ii) production rates, (iii) future operating and development costs, (iv) future commodity prices, including
price differentials, (v) future cash flows, (vi) a market participant-based weighted average cost of capital, and (vii) real estate
market conditions.
The allocation of the purchase price
is considered preliminary and is subject to change upon completion of the determination of the fair value of all assets acquired
and liabilities assumed. The Company continues to work with our third-party valuation specialists to finalize the fair value of
the buildings, pipeline facilities and equipment and oil and gas assets and expects to finalize the valuation by no later than
September 29, 2018. The following table summarizes the preliminary consideration paid and the estimated fair value of the assets
acquired, and liabilities assumed (in thousands).
Consideration paid:
|
|
|
|
Cash consideration
|
|
$
|
34,383
|
|
|
|
|
|
|
Recognized amounts of identifiable assets acquired, and liabilities
assumed:
|
|
|
|
|
Proved oil and gas properties
|
|
$
|
49,920
|
|
Property, plant and equipment
|
|
|
7,744
|
|
Inventory
|
|
|
467
|
|
Accounts receivable – trade receivables
|
|
|
850
|
|
Furniture and fixtures, computer hardware and software, and other equipment
|
|
|
22
|
|
Firm transportation contract obligations
|
|
|
(18,966
|
)
|
Production and property taxes
|
|
|
(2,370
|
)
|
Asset retirement obligation
|
|
|
(2,020
|
)
|
Accounts payable and accrued liabilities
|
|
|
(1,264
|
)
|
Total net assets acquired
|
|
$
|
34,383
|
|
Old Ironsides Membership Interest
Purchase Agreement
On May 4, 2018, Carbon entered into
a Membership Interest Purchase Agreement (the “MIPA”) with Old Ironsides. Old Ironsides owns 73.5%, and Carbon owns
the remaining 26.5%, of the issued and outstanding Class A Units of Carbon Appalachia. Carbon also owns all of the Class B and
Class C Units of Carbon Appalachia. Pursuant to the MIPA, Carbon may acquire all of Old Ironsides’ membership interests
of Carbon Appalachia. Following the closing of the transaction, Carbon would own 100% of the issued and outstanding ownership
interests in Carbon Appalachia, and Carbon Appalachia will become a wholly-owned subsidiary of Carbon.
Subject to the terms and conditions
of the MIPA, Carbon will pay Old Ironsides, approximately $58.0 million at closing, subject to adjustment, in accordance with
the MIPA. Carbon intends to fund the acquisition through the issuance of additional equity, for which Carbon has already filed
a registration statement.
The MIPA contains termination rights
for Carbon and Old Ironsides, including, among others, if the closing of the transaction has not occurred on or before October
15, 2018. The MIPA may also be terminated by mutual written consent of Carbon and Old Ironsides.
Note 4 – Property and Equipment
Net property and equipment at June 30, 2018 and December
31, 2017 consists of the following (in thousands):
|
|
As of
June, 30
|
|
|
As of
December 31,
|
|
|
|
2018
|
|
|
2017
|
|
Oil and gas properties:
|
|
|
|
|
|
|
Proved oil and gas properties
|
|
$
|
85,593
|
|
|
$
|
84,255
|
|
Unproved properties not subject to depletion
|
|
|
1,819
|
|
|
|
1,780
|
|
Accumulated depreciation, depletion and amortization
|
|
|
(3,871
|
)
|
|
|
(1,633
|
)
|
Net oil and gas properties
|
|
|
83,541
|
|
|
|
84,402
|
|
|
|
|
|
|
|
|
|
|
Pipeline facilities and equipment
|
|
|
8,132
|
|
|
|
9,338
|
|
Base gas
|
|
|
2,122
|
|
|
|
2,122
|
|
Buildings
|
|
|
1,247
|
|
|
|
1,247
|
|
Vehicles
|
|
|
550
|
|
|
|
550
|
|
Furniture and fixtures, computer hardware and software, and other equipment
|
|
|
293
|
|
|
|
226
|
|
Accumulated depreciation and amortization
|
|
|
(1,502
|
)
|
|
|
(806
|
)
|
Net other property and equipment
|
|
|
10,842
|
|
|
|
12,677
|
|
|
|
|
|
|
|
|
|
|
Total property and equipment
|
|
$
|
94,383
|
|
|
$
|
97,079
|
|
The Company had approximately $1.8
million at June 30, 2018 and December 31, 2017, of unproved oil and gas properties not subject to depletion. At June 30, 2018
and December 31, 2017, the Company’s unproved properties consist principally of leasehold acquisition costs in Tennessee.
During the three and six months ended
June 30, 2018, no expiring leasehold costs were reclassified into proved property. The costs not subject to depletion relate to
unproved properties that are excluded from amortized capital costs until it is determined whether or not proved reserves can be
assigned to such properties. These costs do not relate to any individually significant projects. The excluded properties are assessed
for impairment at least annually.
Depletion expense related to oil and
gas properties for the three and six months ended June 30, 2018 was approximately $930,000, or $0.26 per Mcfe, and $2.2 million,
or $0.25 per Mcfe, respectively. Depreciation and amortization expense related to buildings, furniture and fixtures, computer
hardware and software, and other equipment for the three and six months ended June 30, 2018 was approximately $288,000 and $695,000,
respectively.
Note 5 – Revolver
On April 3, 2017, Carbon Appalachia Enterprises
entered into a 4-year $100.0 million senior secured asset-based revolving credit facility with LegacyTexas Bank (the “Revolver”)
with an initial borrowing base of $10.0 million.
On August 15, 2017, in connection with
and concurrently with the closing of the Enervest Acquisition, the borrowing base of the Revolver increased to $22.0 million and
Carbon Appalachia Enterprises borrowed $8.0 million from the Revolver to partially fund the Enervest Acquisition.
On September 29, 2017, Carbon Appalachia
Enterprises amended the Revolver, resulting in a borrowing base of $50.0 million with redeterminations as of April 1 and October
1 each year and the addition of East West Bank as a participating lender. In connection with and concurrently with the closing
of the Cabot Acquisition, Carbon Appalachia Enterprises borrowed $20.4 million from the Revolver to partially fund the Cabot Acquisition.
On November 30, 2017, Carbon Appalachia
Enterprises amended the Revolver, resulting in the addition of Bank SNB as a participating lender. The borrowing base of $50.0
million and commitment of $100.0 million was unchanged.
The Revolver bears interest at an applicable
margin ranging from 3.00% to 4.00%, depending on utilization, plus the applicable 30, 60 or 90-day London interbank offered rate
(“LIBOR”), at the Company’s election. As of June 30, 2018, the Company’s effective borrowing rate on the
Revolver was 5.90%. In addition, the Revolver includes a 0.50% unused available line fee.
On April 30, 2018, the Revolver was
amended, resulting in an increase in the borrowing base to $70.0 million (see note 12).
As of June 30, 2018, the Revolver has
an outstanding balance of $38.0 million and a borrowing base of $70.0 million. The maximum principal amount available under the
Revolver is based upon the borrowing base attributable to the Company’s proved oil and gas reserves which is determined
at least semi-annually.
The Revolver is secured by all of the assets
of the Company. The Revolver requires the Company, as of each quarter end, to hedge 75% of its anticipated production for the next
30 months. Distributions to equity members are generally restricted.
In the event of default or deficiency
in the borrowing base, an additional 2.0% interest rate would apply. In such an event, a cure period exists allowing the Company
to obtain compliance.
The Company incurred fees directly
associated with the issuance of the Revolver and amortizes these fees over the life of the Revolver. The current portion of these
fees are recorded as prepaid expense and deposits and the non-current portion as other non-current assets for a combined value
of $589,000 and $584,000 as of June 30, 2018 and December 31, 2017, respectively. For the three and six months ended June 30,
2018, the Company amortized approximately $50,000 and $95,000, respectively, associated with these fees.
The Revolver agreement requires the
Company to maintain certain financial and non-financial covenants which include the following ratios: leverage ratio, current
ratio, and other qualitative covenants as defined in the Revolver agreement including commodity hedging requirements. As of June
30, 2018, the Company was compliant with its covenants.
Interest Expense
For the three and six months ended
June 30, 2018, the Company incurred interest expense of approximately $605,000 and $1.2 million, respectively. Approximately $50,000
and $95,000 was amortization of the Revolver issuance costs for the three and six months ended June 30, 2018.
Note 6 – Accounts Payable and Accrued Liabilities
Accounts payable and accrued liabilities
at June 30, 2018 and December 31, 2017 consists of the following (in thousands):
|
|
June 30,
2018
|
|
|
December 31,
2017
|
|
Accounts payable
|
|
$
|
2,676
|
|
|
$
|
3,878
|
|
Accrued liabilities
|
|
|
913
|
|
|
|
3,685
|
|
Accrued ad valorem taxes
|
|
|
2,355
|
|
|
|
1,812
|
|
Accrued lease operating
|
|
|
492
|
|
|
|
1,135
|
|
Transportation, gathering and compression
|
|
|
1,574
|
|
|
|
361
|
|
Property and production taxes
|
|
|
1,712
|
|
|
|
675
|
|
Accrued interest
|
|
|
97
|
|
|
|
107
|
|
Other
|
|
|
64
|
|
|
|
417
|
|
Total accounts payable and accrued liabilities
|
|
$
|
9,883
|
|
|
$
|
12,070
|
|
Note 7 – Fair Value Measurements
Authoritative guidance defines fair value
as the price that would be received to sell an asset or paid to transfer a liability (an exit price) in an orderly transaction
between market participants at the measurement date. The guidance establishes a hierarchy for inputs used in measuring fair value
that maximizes the use of observable inputs and minimizes the use of unobservable inputs by requiring that the most observable
inputs be used when available. Observable inputs are inputs that market participants would use in pricing the asset or liability
developed based on market data obtained from sources independent of the Company. Unobservable inputs are inputs that reflect the
Company’s assumptions of what market participants would use in pricing the asset or liability developed based on the best
information available in the circumstances. The hierarchy is broken down into three levels based on the reliability of the inputs
as follows:
|
Level
1:
|
Quoted
prices are available in active markets for identical assets or liabilities;
|
|
|
|
|
Level 2:
|
Quoted prices in
active markets for similar assets or liabilities that are observable for the asset or liability; or
|
|
|
|
|
Level 3:
|
Unobservable pricing
inputs that are generally less observable from objective sources, such as discounted cash flow models or valuations.
|
Financial assets and liabilities are classified
based on the lowest level of input that is significant to the fair value measurement. The Company’s policy is to recognize
transfers in and/or out of fair value hierarchy as of the end of the reporting period for which the event or change in circumstances
caused the transfer. The Company has consistently applied the valuation techniques discussed below throughout the period presented.
The following table presents the Company’s
financial assets that were accounted for at fair value on a recurring basis as of June 30, 2018 and December 31, 2017 by level
within the fair value hierarchy (in thousands):
|
|
Fair Value Measurements Using
|
|
At June 30, 2018
|
|
Level 1
|
|
|
Level 2
|
|
|
Level 3
|
|
|
Total
|
|
Assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivatives - current
|
|
$
|
-
|
|
|
$
|
60
|
|
|
$
|
-
|
|
|
$
|
60
|
|
Commodity derivatives – other non-current assets
|
|
$
|
-
|
|
|
$
|
607
|
|
|
$
|
-
|
|
|
$
|
607
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
At December 31, 2017
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivatives – current
|
|
$
|
-
|
|
|
$
|
1,884
|
|
|
$
|
-
|
|
|
$
|
1,884
|
|
Commodity derivatives – other non-current assets
|
|
$
|
-
|
|
|
$
|
155
|
|
|
$
|
-
|
|
|
$
|
155
|
|
As of June 30, 2018, the Company’s
commodity derivative financial instruments are comprised of natural gas and oil swap and collar agreements. The fair values of
these agreements are determined under an income valuation technique. Swaps are valued using the income technique. Collars are
valued using the option model. The valuation model requires a variety of inputs, including contractual terms, published forward
prices, volatilities for options and discount rates, as appropriate. The Company’s estimates of the fair value of derivatives
include consideration of the counterparty’s credit worthiness, the Company’s credit worthiness and the time value
of money. The consideration of these factors results in an estimated exit-price for each derivative asset or liability under a
market place participant’s view. All the significant inputs are observable, either directly or indirectly; therefore, the
Company’s derivative instruments are included within the Level 2 fair value hierarchy. The counterparty for all the Company’s
outstanding commodity derivative financial instruments as of June 30, 2018 is BP Energy Company (“BPEC”).
Assets and Liabilities Measured and
Recorded at Fair Value on a Non-Recurring Basis
Acquired accounts receivable, accounts
payable, and other accrued liabilities were determined to be representative of fair value given their short-term nature. Acquired
base gas and gas inventory was valued based on prevailing market rates for natural gas on the closing date of the Cabot Acquisition
on September 29, 2017.
The fair values of each of the following
assets and liabilities, measured upon the acquisition date in year ended December 31, 2017, and recorded at fair value on a non-recurring
basis, are based on unobservable pricing inputs and therefore, are included within the Level 3 fair value hierarchy.
Asset Retirement Obligation
The fair value of the Company’s
asset retirement obligation liability is calculated as of the date of closing of each of the Company’s acquisitions, when
the liability was assumed, by estimating i) the cost of abandoning oil and gas wells ranging from $15,000 to $30,000 based on
market participant expectations for similar work; ii) the timing of reclamation ranging from 2-75 years based on economic lives
of its properties as estimated by reserve engineers; iii) an inflation rate between 1.81% and 2.04%; and iv) a credit adjusted
risk-free rate of 6.59%, which takes into account the Company’s credit risk and the time value of money (asset acquisitions)
or a range of 13.5% - 15.0% representing a market participant’s weighted average cost of capital (business combinations).
Given the unobservable nature of the inputs, the initial measurement of the asset retirement obligation liability is deemed to
use Level 3 inputs (see note 2).
Firm Transportation Obligation
The Company assumed liabilities associated
with firm transportation contracts in connection with the Enervest Acquisition and Cabot Acquisition. The fair value of these
acquired firm transportation obligations was estimated based upon i) the contractual obligations assumed by the Company (including
the length of contracts, committed volumes, and demand charges described in note 9), ii) estimated usage from a market-participant
perspective, and iii) a discount rate of 15.0% based upon a market participant’s estimated weighted average cost of capital.
Class B Units
The Company issued Class B Units to
Carbon as part of entering into the Carbon Appalachia LLC Agreement. The $924,000 fair value of the Class B Units was estimated
by the Company utilizing the assistance of third-party valuation specialists. The fair value was based upon enterprise values
derived from inputs including estimated future production rates, future commodity prices including price differentials as of the
date of closing, future operating and development costs and comparable market participants.
Acquired Assets
For assets accounted for as business combinations,
including the Knox-Coalfield Acquisition and Cabot Acquisition (see note 3), to determine the fair value of the assets acquired,
the Company primarily used the income approach and made market assumptions as to projections of estimated quantities of oil and
natural gas reserves, future production rates, future commodity prices including price differentials as of the date of closing,
future operating and development costs, a market participant weighted average cost of capital, and the condition of vehicles and
equipment.
For the assets acquired in the Enervest
Acquisition and accounted for as an asset acquisition, to determine the fair value of the assets acquired, the Company primarily
used the income approach and made market assumptions as to projections of estimated quantities of oil and natural gas reserves,
future production rates, future commodity prices including price differentials as of the date of closing, future operating and
development costs and its weighted average cost of capital.
Note 8 – Commodity Derivatives
The Company has entered into commodity-based
derivative contracts at various times to manage exposures to commodity price on certain of its oil and natural gas production.
The Company does not hold or issue derivative financial instruments for speculative or trading purposes.
Pursuant to the terms of the Company’s
Revolver, the Company has entered into derivative agreements to hedge certain of its oil and natural gas production for 2018 through
2021. As of June 30, 2018, these derivative agreements consisted of the following:
|
|
Natural Gas Swaps
|
|
|
Natural Gas Collars
|
|
|
Oil Swaps
|
|
|
|
|
|
|
Weighted
|
|
|
|
|
|
Weighted
|
|
|
|
|
|
Weighted
|
|
|
|
|
|
|
Average
|
|
|
|
|
|
Average Price
|
|
|
|
|
|
Average
|
|
Year
|
|
MMBtu
|
|
|
Price (a)
|
|
|
MMBtu
|
|
|
Range (a)
|
|
|
Bbl
|
|
|
Price (b)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2018
|
|
|
5,370,000
|
|
|
$
|
2.97
|
|
|
|
800,000
|
|
|
|
$2.85
- $3.19
|
|
|
|
7,500
|
|
|
$
|
50.81
|
|
2019
|
|
|
11,515,000
|
|
|
$
|
2.86
|
|
|
|
480,000
|
|
|
|
$2.85
- $3.19
|
|
|
|
12,000
|
|
|
$
|
50.35
|
|
2020
|
|
|
11,418,000
|
|
|
$
|
2.74
|
|
|
|
-
|
|
|
|
-
|
|
|
|
6,000
|
|
|
$
|
54.75
|
|
2021
|
|
|
2,598,000
|
|
|
$
|
2.69
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
(a)
|
NYMEX
Henry Hub Natural Gas futures contract for the respective period.
|
(b)
|
NYMEX Light Sweet
Crude West Texas Intermediate futures contract for the respective period.
|
For its swap instruments, the Company
receives a fixed price for the hedged commodity and pays a floating price to the counterparty. The fixed-price payment and the
floating-price payment are netted, resulting in a net amount due to or from the counterparty. Collars are designed to establish
floor and ceiling prices on anticipated future oil and gas production. The ceiling establishes a maximum price that the Company
will receive for the volumes under contract, while the floor establishes a minimum price.
The following table summarizes the
fair value of the derivatives recorded in the unaudited consolidated balance sheets as of June 30, 2018 and audited consolidated
balance sheet as of December 31, 2017. These derivative instruments are not designated as cash flow hedging instruments for accounting
purposes (in thousands):
Commodity derivative contracts:
|
|
June 30,
2018
|
|
|
December 31,
2017
|
|
Current assets
|
|
$
|
60
|
|
|
$
|
1,884
|
|
Other non-current assets
|
|
$
|
607
|
|
|
$
|
155
|
|
The table below summarizes the commodity
settlements and unrealized gains and losses related to the Company’s derivative instruments for the three and six months
ended June 30, 2018 and are included in commodity derivative gain or loss in the accompanying consolidated statement of operations.
|
|
June 30, 2018
|
|
|
For the period
April 3,
2017
|
|
|
|
Three months ended
|
|
|
Six months ended
|
|
|
through
June 30,
2018
|
|
Commodity derivative contracts:
|
|
|
|
|
|
|
|
|
|
Commodity derivative gain - realized
|
|
$
|
455
|
|
|
$
|
902
|
|
|
$
|
34
|
|
Commodity derivative (loss) – unrealized
|
|
|
(948
|
)
|
|
|
(1,371
|
)
|
|
|
121
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total commodity derivative gain
|
|
$
|
(493
|
)
|
|
$
|
(469
|
)
|
|
$
|
155
|
|
Commodity derivative gains and losses
that have settled are included in cash flows from operating activities in the unaudited consolidated statement of cash flows.
The counterparty in the Company’s
derivative instruments is BP Energy Company (“BPEC”). The Company has entered into an International Swaps and Derivative
Association, Inc. (“ISDA”) Master Agreement with BPEC that establishes standard terms for the derivative contracts
and an inter-creditor agreement with participating lenders in the Revolver and BPEC whereby any credit exposure related to the
derivative contracts entered into by the Company and BPEC is secured by the collateral and backed by the guarantees supporting
the credit facility.
The Company nets its derivative instrument
fair value amounts executed with its counterparty pursuant to an ISDA master agreement, which provides for the net settlement
over the term of the contracts and in the event of default or termination of the contracts. The Company’s derivative instruments
are recorded as assets in the unaudited balance sheet as of June 30, 2018.
|
|
|
|
|
|
|
|
|
Net
|
|
|
|
|
Gross
|
|
|
|
|
|
Recognized
|
|
|
|
|
Recognized
|
|
|
Gross
|
|
|
Fair Value
|
|
|
Consolidated Balance Sheet
|
|
Assets/
|
|
|
Amounts
|
|
|
Assets/
|
|
|
Classification
|
|
(Liabilities)
|
|
|
Offset
|
|
|
(Liabilities)
|
|
At June 30, 2018
|
|
|
|
|
|
|
|
|
|
|
Commodity derivative assets:
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivative asset
|
|
$
|
1,034
|
|
|
$
|
(974
|
)
|
|
$
|
60
|
|
|
Other non-current assets
|
|
|
-
|
|
|
|
607
|
|
|
|
607
|
|
Commodity derivative assets
|
|
|
$
|
1,304
|
|
|
$
|
(367
|
)
|
|
$
|
667
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivative liabilities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivative liability
|
|
$
|
(367
|
)
|
|
$
|
367
|
|
|
$
|
-
|
|
|
Other non-current liabilities
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
Total derivative liabilities
|
|
|
$
|
(367
|
)
|
|
$
|
367
|
|
|
$
|
-
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
At December 31, 2017
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivative assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivative asset
|
|
$
|
2,288
|
|
|
$
|
(404
|
)
|
|
$
|
1,884
|
|
|
Other non-current assets
|
|
|
1,150
|
|
|
|
(995
|
)
|
|
|
155
|
|
Commodity derivative assets
|
|
|
$
|
3,438
|
|
|
$
|
(1,399
|
)
|
|
$
|
2,039
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivative liabilities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivative liability
|
|
$
|
404
|
|
|
$
|
(404
|
)
|
|
$
|
-
|
|
|
Other non-current liabilities
|
|
|
995
|
|
|
|
(955
|
)
|
|
|
-
|
|
Total derivative liabilities
|
|
|
$
|
1,399
|
|
|
$
|
(1,399
|
)
|
|
$
|
-
|
|
Due to the volatility of oil and natural
gas prices, the estimated fair values of the Company’s derivatives are subject to large fluctuations from period to period.
Note 9 – Commitments and Contingencies
In connection with the Enervest Acquisition
and Cabot Acquisition, the Company acquired long-term firm transportation contracts that were entered into to ensure the transport
for certain gas production to purchasers. Firm transportation volumes and the related demand charges for the remaining term of
these contracts at June 30, 2018 are summarized in the table below.
Period
|
|
Dekatherms per day
|
|
Demand Charges
|
Jul 2018 – Oct 2020
|
|
6,300
|
|
$0.21
|
Jul 2018 – May 2027
|
|
29,900
|
|
$0.21
|
Jul 2018 – Aug 2022
|
|
19,441
|
|
$0.56
|
As of June 30, 2018, the remaining
commitment related to the firm transportation contracts assumed in the Cabot Acquisition and Enervest Acquisition is $16.8 million
and reflected in the Company’s unaudited consolidated balance sheet. The fair values of these firm transportation obligations
were determined based upon the contractual obligations assumed by the Company and discounted based upon the Company’s effective
borrowing rate. These contractual obligations are being amortized monthly as the Company pays these firm transportation obligations
in the future.
Legal and Environmental
We are not aware of any legal or environmental
material pending or threatened litigation or of any proceedings known to be contemplated by governmental authorities or regulators
which are, or would be, likely to have a material adverse effect upon the Company or our operations, taken as a whole.
Note 10 – Related Parties
During the period ended June 30, 2018,
the Company was engaged in the following transactions with related parties (in thousands):
Nytis Exploration Company LLC (“Nytis”)
is a subsidiary of Carbon and the operator of the Company’s properties through an operating agreement. The operating agreement
includes reimbursements and allocations made under the agreement. Approximately $1.1 million in reimbursements was included in
due to related parties as of June 30, 2018.
Management Services
The Company entered into a management
service agreement with Carbon whereby Carbon provides general management and administrative services to the Company. The amount
of the reimbursement to Carbon is based upon the percentage of production of the Company as a percentage of the total volume of
production from Carbon and the Company. The Company reimburses Carbon for all management related expenses such as travel, required
third-party geological and/or accounting consulting, and other necessary expenses incurred by Carbon in the normal course of managing
the Company.
The Company incurred approximately
$750,000 and $1.5 million in management reimbursements for the three and six months ended June 30, 2018, respectively. Additionally,
the Company reimbursed Carbon for approximately $298,000 and $595,000 in general and administrative expenses and was recorded
as management reimbursements, related party in the statement of operations for the three and six months ended June 30, 2018, respectively.
Approximately $23,000 was included in due to related parties as of June 30, 2018.
Note 11 – Supplemental Cash
Flow Disclosure
Supplemental cash flow disclosures
for the six months ended June 30, 2018 are presented below (in thousands):
Cash paid during the period for:
|
|
|
|
Interest payments
|
|
$
|
1,197
|
|
REPORT OF INDEPENDENT
REGISTERED PUBLIC ACCOUNTING FIRM
To the Members and Board of Directors
Carbon Appalachian Company, LLC
Denver, Colorado
OPINION ON THE FINANCIAL STATEMENTS
We have audited the accompanying consolidated
balance sheet of Carbon Appalachian Company, LLC (the “Company”) as of December 31, 2017, and the related consolidated
statements of operations, members’ equity, and cash flows, for the period from April 3, 2017 through December 31, 2017,
and the related notes (collectively referred to as the “financial statements”). In our opinion, the financial statements
present fairly, in all material respects, the financial position of the Company as of December 31, 2017, and the results of its
operations and its cash flows for the period from April 3, 2017 through December 31, 2017, in conformity with accounting principles
generally accepted in the United States of America.
BASIS FOR OPINION
These financial statements are the responsibility
of the Company’s management. Our responsibility is to express an opinion on the Company’s financial statements based
on our audit. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (“PCAOB”)
and are required to be independent with respect to the Company in accordance with relevant ethical requirements relating to our
audit.
We conducted our audit in accordance with
the auditing standards of the PCAOB and in accordance with auditing standards generally accepted in the United States of America.
Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements
are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to
perform, an audit of its internal control over financial reporting. As part of our audit we are required to obtain an understanding
of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company’s
internal control over financial reporting. Accordingly, we express no such opinion.
Our audit included performing procedures
to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures
that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures
in the financial statements. Our audit also included evaluating the accounting principles used and significant estimates made
by management, as well as evaluating the overall presentation of the financial statements. We believe that our audit provides
a reasonable basis for our opinion.
/s/
EKS&H LLLP
|
|
EKS&H LLLP
|
|
March 31, 2018
Denver, Colorado
We have served as the Company’s auditor since 2017.
CARBON APPALACHIAN
COMPANY, LLC
Consolidated Balance Sheet
(In thousands)
|
|
December 31,
|
|
|
|
2017
|
|
ASSETS
|
|
|
|
|
|
|
|
Current assets:
|
|
|
|
Cash and cash equivalents
|
|
$
|
4,512
|
|
Accounts receivable:
|
|
|
|
|
Revenue
|
|
|
10,682
|
|
Trade receivables
|
|
|
1,569
|
|
Commodity derivative asset
|
|
|
1,884
|
|
Inventories
|
|
|
1,660
|
|
Prepaid expense and deposits
|
|
|
487
|
|
Total current assets
|
|
|
20,794
|
|
|
|
|
|
|
Property and equipment (note 4)
|
|
|
|
|
Oil and gas properties,
full cost method of accounting:
|
|
|
|
|
Proved, net
|
|
|
82,622
|
|
Unproved
|
|
|
1,780
|
|
Other property, plant,
and equipment, net
|
|
|
12,677
|
|
Total property and equipment
|
|
|
97,079
|
|
|
|
|
|
|
Other non-current assets
|
|
|
683
|
|
Total assets
|
|
$
|
118,556
|
|
|
|
|
|
|
LIABILITIES AND MEMBERS’ EQUITY
|
|
|
|
|
|
|
|
|
|
Current liabilities:
|
|
|
|
|
Accounts payable
and accrued liabilities
|
|
$
|
12,070
|
|
Due to related parties
(note 11)
|
|
|
1,852
|
|
Firm transportation
contract obligation
|
|
|
4,285
|
|
Total current liabilities
|
|
|
18,207
|
|
|
|
|
|
|
Non-current liabilities:
|
|
|
|
|
Asset retirement
obligations
|
|
|
4,789
|
|
Firm transportation
contract obligation
|
|
|
14,843
|
|
Production and property
taxes payable
|
|
|
1,813
|
|
Revolver (note 5)
|
|
|
37,975
|
|
Total non-current liabilities
|
|
|
59,420
|
|
|
|
|
|
|
Commitments and contingencies (note 9)
|
|
|
|
|
|
|
|
|
|
Members’ equity:
|
|
|
|
|
Members’ contributions
|
|
|
37,924
|
|
Retained earnings
|
|
|
3,005
|
|
Total members’ equity
|
|
|
40,929
|
|
|
|
|
|
|
Total liabilities and members’ equity
|
|
$
|
118,556
|
|
See accompanying Notes to Consolidated
Financial Statements.
CARBON APPALACHIAN COMPANY, LLC
Consolidated Statement of Operations
(In thousands)
|
|
For the period April 3,
2017 (inception)
through December 31, 2017
|
|
|
|
|
|
Revenue:
|
|
|
|
Natural gas sales
|
|
$
|
16,128
|
|
Oil sales
|
|
|
685
|
|
Transportation and handling
|
|
|
911
|
|
Marketing gas sales
|
|
|
11,315
|
|
Commodity derivative gain
|
|
|
2,545
|
|
Total revenue
|
|
|
31,584
|
|
|
|
|
|
|
Expenses:
|
|
|
|
|
Lease operating
|
|
|
5,587
|
|
Transportation, gathering, and compression
|
|
|
4,160
|
|
Production and property taxes
|
|
|
1,464
|
|
Marketing gas purchases
|
|
|
9,290
|
|
General and administrative
|
|
|
2,044
|
|
Depreciation, depletion and amortization
|
|
|
2,439
|
|
Accretion of asset retirement obligations
|
|
|
198
|
|
Management and operating fee, related party (note
11)
|
|
|
1,582
|
|
Total expenses
|
|
|
26,764
|
|
|
|
|
|
|
Operating income
|
|
|
4,820
|
|
|
|
|
|
|
Other expenses:
|
|
|
|
|
Class B Units issuance (note 10)
|
|
|
924
|
|
Interest expense
|
|
|
891
|
|
Total other expense
|
|
|
1,815
|
|
|
|
|
|
|
Net income
|
|
$
|
3,005
|
|
See accompanying Notes to Consolidated
Financial Statements.
CARBON APPALACHIAN
COMPANY, LLC
Consolidated Statement of Members’ Equity
(In thousands, except unit amounts)
|
|
Members’ Contributions
|
|
|
|
|
|
Total
|
|
|
|
Class A Units
|
|
|
Amount
|
|
|
Class B Units
|
|
|
Amount
|
|
|
Class C Units
|
|
|
Amount
|
|
|
Retained Earnings
|
|
|
Members’ Equity
|
|
April 3, 2017
|
|
|
-
|
|
|
$
|
-
|
|
|
|
|
|
|
$
|
-
|
|
|
|
-
|
|
|
$
|
-
|
|
|
$
|
-
|
|
|
$
|
-
|
|
Initial capital members’ unit contributions
(note 10)
|
|
|
37,000
|
|
|
|
37,000
|
|
|
|
1,000
|
|
|
|
924
|
|
|
|
121
|
|
|
|
-
|
|
|
|
-
|
|
|
|
37,924
|
|
Net income
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
3,005
|
|
|
|
3,005
|
|
Balances at December 31, 2017
|
|
|
37,000
|
|
|
$
|
37,000
|
|
|
|
1,000
|
|
|
$
|
924
|
|
|
|
121
|
|
|
$
|
-
|
|
|
$
|
3,005
|
|
|
$
|
40,929
|
|
See accompanying Notes to Consolidated
Financial Statements.
CARBON APPALACHIAN
COMPANY, LLC
Consolidated Statement of Cash Flows
(In thousands)
|
|
For the
period from
April 3,
2017
(inception)
through
December 31,
|
|
|
|
2017
|
|
|
|
|
|
Cash flows from operating activities:
|
|
|
|
Net income
|
|
$
|
3,005
|
|
Items not involving cash:
|
|
|
|
|
Depreciation, depletion and amortization
|
|
|
2,439
|
|
Accretion of asset retirement obligations
|
|
|
198
|
|
Commodity derivative gain
|
|
|
(2,039
|
)
|
Amortization of Revolver issuance costs
|
|
|
79
|
|
Class B units issuance
|
|
|
924
|
|
Net change in:
|
|
|
|
|
Accounts receivable
|
|
|
(12,168
|
)
|
Inventories
|
|
|
270
|
|
Prepaid expense and deposits
|
|
|
(307
|
)
|
Accounts payable, accrued liabilities and firm transportation contract obligation
|
|
|
10,184
|
|
Due to related parties
|
|
|
1,852
|
|
Net cash provided by operating activities
|
|
|
4,437
|
|
|
|
|
|
|
Cash flows from investing activities:
|
|
|
|
|
Development of oil and gas properties and other property, plant, and equipment
|
|
|
(528
|
)
|
Acquisition of oil and gas properties
|
|
|
(73,585
|
)
|
Other non-current assets
|
|
|
(124
|
)
|
Net cash used in investing activities
|
|
|
(74,237
|
)
|
|
|
|
|
|
Cash flows from financing activities:
|
|
|
|
|
Members’ contributions
|
|
|
37,000
|
|
Proceeds from Revolver
|
|
|
37,975
|
|
Payments of Revolver issuance costs
|
|
|
(663
|
)
|
Net cash provided by financing activities
|
|
|
74,312
|
|
|
|
|
|
|
Net increase in cash and cash equivalents
|
|
|
4,512
|
|
|
|
|
|
|
Cash and cash equivalents, beginning of period
|
|
|
-
|
|
|
|
|
|
|
Cash and cash equivalents, end of period
|
|
$
|
4,512
|
|
See note 12 – Supplemental Cash Flow Disclosure
See accompanying Notes to Consolidated
Financial Statements.
Notes to Consolidated
Financial Statements
Note 1 – Organization
On December 16, 2016, Carbon Appalachian
Company, LLC (the “Company,” “Carbon Appalachia” or “CAC”) was formed, as a Delaware limited
liability company, by Carbon Natural Gas Company (“Carbon”) a Delaware Corporation, entities managed by Yorktown Energy
Partners XI, L.P. (“Yorktown”), and entities managed by Old Ironsides (“Old Ironsides”), to acquire producing
assets in the Appalachian Basin in Kentucky, Tennessee, Virginia and West Virginia. The Company began substantial operations on
April 3, 2017 (“Inception”). The Company is engaged primarily in acquiring, developing, exploiting, producing, processing,
marketing, and transporting oil and natural gas in the Appalachia Basin.
Equity and ownership
On April 3, 2017, Carbon, Yorktown and
Old Ironsides entered in to a limited liability company agreement (the “Carbon Appalachia LLC Agreement”), with an
initial equity commitment of $100.0 million, of which $37.0 million has been contributed as of December 31, 2017.
On April 3, 2017, the Company (i) issued
Class A Units to Carbon, Yorktown and Old Ironsides for an aggregate cash consideration of $12.0 million, (ii) issued Class B
Units to Carbon, and (iii) issued Class C Units to Carbon. Additionally, Carbon Appalachia Enterprises, LLC, formerly known as
Carbon Tennessee Company, LLC (“Carbon Appalachia Enterprises”), a subsidiary of the Company, entered into a 4-year
$100.0 million senior secured asset-based revolving credit facility with LegacyTexas Bank (the “Revolver”) with an
initial borrowing base of $10.0 million.
On April 3, 2017, borrowings under the
Revolver, along with the initial equity contributions made to the Company, were used to complete the acquisition of natural gas
producing properties and related facilities located predominantly in Tennessee (the “Knox-Coalfield Acquisition”).
The purchase price was $20.0 million, subject to normal and customary closing adjustments. Carbon Appalachia Enterprises used
$8.5 million drawn from the credit facility toward the purchase price.
In connection with Carbon entering into
the Carbon Appalachia LLC Agreement, and Carbon Appalachia engaging in the transactions described above, Carbon received 1,000
Class B units and issued to Yorktown a warrant to purchase approximately 408,000 shares of Carbon’s common stock at an exercise
price dictated by the warrant agreement (the “Appalachia Warrant”). The Appalachia Warrant is payable exclusively
with Class A Units of Carbon Appalachia held by Yorktown. On November 1, 2017, Yorktown exercised the Appalachia Warrant, resulting
in Carbon acquiring 2,940 Class A Units from Yorktown.
Net proceeds from the April 3, 2017 transactions
were used by the Company to complete the Knox-Coalfield, EnerVest, and Cabot (defined below). The remainder of the net proceeds
were used to fund field development projects, future complementary acquisitions, and working capital.
On August 15, 2017, the Carbon Appalachia
LLC Agreement was amended and, as a result, Carbon will contribute its initial commitment of future capital contributions as well
as Yorktown’s, and Yorktown will not participate in future capital contributions. The Company issued Class A Units to Carbon
and Old Ironsides for an aggregate cash consideration of $14.0 million. The borrowing base of the Revolver increased to $22.0
million and Carbon Appalachia Enterprises borrowed $8.0 million under the Revolver.
On August 15, 2017, Carbon Appalachia
completed the acquisition of natural gas producing properties and related facilities located predominantly in the state of West
Virginia (the “Enervest Acquisition”). The purchase price was $21.5 million, subject to normal and customary closing
adjustments. The contributions from members and funds drawn from the credit facility were used to pay the purchase price.
On September 29, 2017, the Company issued
Class A Units to Carbon and Old Ironsides for an aggregate cash consideration of $11.0 million. The Revolver was amended to include
East West Bank as a participating lender, the borrowing base of the Revolver increased to $50.0 million and Carbon Appalachia
Enterprises borrowed $20.4 million from the Revolver.
On September 29, 2017, Carbon Appalachia
completed the acquisition of natural gas producing properties, natural gas gathering pipelines and related facilities located
predominantly in the state of West Virginia (the “Cabot Acquisition”). The purchase price was $41.3 million, subject
to normal and customary closing adjustments. The contributions from members and funds drawn from the credit facility were used
to pay the purchase price.
On November 30, 2017, Carbon Appalachia
Enterprises amended the Revolver, resulting in the addition of Bank SNB as a participating lender. The borrowing base of $50.0
million was unchanged.
As of December 31, 2017, Old Ironsides
holds 27,195 Class A Units, which equates to 72.76% Aggregate Share ownership of the Company and Carbon holds (i) 9,805 Class
A Units, (ii) 1,000 Class B Units and (iii) 121 Class C Units, which equates to 27.24% Aggregate Share ownership of the Company.
As of December 31, 2017, the Revolver’s
borrowing base is $50.0 million, of which $38.0 million is outstanding.
Note 2 – Summary of Significant
Accounting Policies
Accounting policies used by the Company
reflect industry practices and conform to accounting principles generally accepted in the United States of America. The more significant
of such accounting policies are briefly discussed below.
Principles of Consolidation
The consolidated financial statements
include the accounts of the Company and its consolidated subsidiaries. The Company’s subsidiaries consist of Carbon Tennessee
Mining Company, LLC, Carbon Appalachia Group, LLC, Carbon Appalachia Enterprises, LLC, Coalfield Pipeline Company, Knox Energy,
LLC, Carbon West Virginia Company, LLC and Cranberry Pipeline Corporation. All significant intercompany accounts and transactions
have been eliminated.
Cash and Cash Equivalents
Cash and cash equivalents have been generally
invested in money market accounts, certificates of deposits and other cash equivalents with maturities of three months or less.
Such investments are deemed to be cash equivalents for purposes of the consolidated financial statements. The carrying amount
of cash equivalents approximate fair value because of the short maturity and high credit quality of these investments. At times,
the Company may have cash and cash equivalent balances more than federal insured amounts within their accounts.
The Company continually monitors its position
with and the credit quality of the financial institutions in which it invests.
Accounts Receivable
The Company’s accounts receivable
include (i) revenue receivables primarily comprised of revenues from gas marketing sales from large, well-known industrial companies
totaling approximately $8.3 million; and (ii) revenue receivables primarily comprised of oil and natural gas revenues from producing
wells activities and from other large well-known exploration and production companies and recorded on a net basis to the Company’s
revenue interest totaling approximately $2.4 million.
A purchaser imbalance asset occurs when
the Company delivers more natural gas than it nominated to deliver to the purchaser and the purchaser pays only for the nominated
amount. Conversely, a purchaser imbalance liability occurs when the Company delivers less natural gas than it nominated to deliver
to the purchaser and the purchaser pays for the amount nominated. As of December 31, 2017, the Company had a purchaser imbalance
receivable of approximately $194,000 which is recognized as a current asset in trade receivables on the consolidated balance sheet.
Trade receivables are those from joint
interest billing in the properties that the Company operates which are subject to joint operating agreements as well as any outstanding
receivables associated with its acquisitions. As of December 31, 2017, trade receivables included approximately $1.6 million associated
with the Cabot Acquisition. The Company grants credit to all qualified customers, which potentially subjects the Company to credit
risk resulting from, among other factors, adverse changes in the oil, natural gas, and natural gas liquids production in which
the Company operates and the financial condition of its customers. The Company continuously monitors collections and payments
from its customers and is developing historical experience with specific customer collection issues that it has identified. At
December 31, 2017, the Company had not identified any collection issues related to its oil and gas operations and therefore no
allowance for doubtful accounts was provided for.
Prepaid Expense and Deposits
The Company’s prepaid expense and
deposit account is comprised of prepaid insurance, bonds and the current portion of unamortized Revolver issuance costs. The remaining
unamortized Revolver issuance costs are within other non-current assets. As of December 31, 2017, the total unamortized Revolver
issuance costs are $584,000, of which $180,000 are included in prepaid expense and deposits.
Inventories
Inventories, which consist primarily of
natural gas, are recorded at the lower of cost or net realizable value.
Gas that is available for immediate use,
referred to as working gas, is recorded within current assets.
Inventory consists of material and supplies
used in connection with the Company’s maintenance, storage and handling. These inventories are stated at the lower of cost
or net realizable value.
Other Non-Current Assets
Other non-current assets are comprised
of bonds, the non-current portion of unamortized Revolver issuance costs and the non-current portion of derivative liabilities.
Revenue
The Company recognizes revenues for sales
and services when persuasive evidence of an arrangement exists, when custody is transferred, or services are rendered, fees are
fixed or determinable and collectability is reasonably assured.
The Company recognizes an asset or a liability,
whichever is appropriate, for revenues associated with over-deliveries or under-deliveries of natural gas to purchasers.
Natural Gas and Oil Sales
Oil and natural gas revenues are recognized
when production volumes are sold to a purchaser at a fixed or determinable price, delivery has occurred, title has transferred,
and collectability is reasonably assured. Natural gas and oil revenues are recognized based on the Company’s net revenue
interest.
Marketing Gas Revenue
The Company sells production purchased
from third parties as well as production from its own oil and gas producing properties. From Inception through December 31, 2017,
approximately $9.9 million in intercompany activity is eliminated between revenue – marketing and gas purchases - marketing
on the statement of operations.
Storage
Under fee-based arrangements, the Company
receives a fee for storing natural gas. The revenues earned are directly related to the volume of natural gas that flows through
the Company’s systems and are not directly dependent on commodity prices.
Transportation, gathering, and compression
The Company generally purchases natural
gas from producers at the wellhead or other receipt points, gathers the wellhead natural gas through our gathering system, and
then sells the natural gas based on published index market prices. The Company remits to the producers either an agreed-upon percentage
of the actual proceeds that we receive from our sales of natural gas or an agreed-upon percentage of the proceeds based on index
related prices for the natural gas, regardless of the actual amount of the sales proceeds we receive. The Company’s revenues
under percent-of-proceeds/index arrangements generally correlates with the price of natural gas.
Concentrations of Credit Risk
There are numerous significant purchasers
in the areas where the Company sells its production and demand for the Company’s products remains high. Management does
not believe that changing its primary purchasers or a loss of any other single purchaser would materially impact the Company’s
business. For the period from Inception through December 31, 2017, one customer accounted for 30% of total third-party revenues.
As of December 31, 2017, the same customer accounted for 16% of trade receivable and three other customers accounted for 38% of
trade receivable.
Accounting for Oil and Gas Operations
The Company uses the full cost method
of accounting for oil and gas properties. Accordingly, all costs related to the acquisition, exploration and development of oil
and gas properties, including costs of undeveloped leasehold, dry holes and leasehold equipment, are capitalized. Overhead costs
incurred that are directly identified with acquisition, exploration and development activities undertaken by the Company for its
own account, and which are not related to production, general corporate overhead or similar activities, are also capitalized.
Unproved properties are excluded from
amortized capitalized costs until it is determined whether or not proved reserves can be assigned to such properties. The Company
assesses its unproved properties for impairment at least annually. Significant unproved properties are assessed individually.
From Inception through December 31, 2017, the Company did not recognize an unproved property impairment.
Capitalized costs are depleted by an equivalent
unit-of-production method, converting gas to oil at the ratio of six thousand cubic feet of natural gas to one barrel of oil.
Depletion is calculated using capitalized costs, including estimated asset retirement costs, plus estimated future expenditures
(based on current costs) to be incurred in developing proved reserves and related estimated asset retirement costs, net of estimated
salvage values.
No gain or loss is recognized upon disposal
of oil and gas properties unless such disposal significantly alters the relationship between capitalized costs and proved reserves.
All costs related to production activities, including work-over costs incurred solely to maintain or increase levels of production
from an existing completion interval, are charged to expense as incurred.
The Company performs a ceiling test on
a quarterly basis. The full cost ceiling test is a limitation on capitalized costs prescribed by SEC Regulation S-X Rule 4-10.
The ceiling test is not a fair value-based measurement, rather it is a standardized mathematical calculation. The ceiling test
provides that capitalized costs less related accumulated depletion and deferred income taxes may not exceed the sum of (1) the
present value of future net revenue from estimated production of proved oil and gas reserves using the unweighted arithmetic average
of the first-day-of-the month price for the previous twelve month period, excluding the future cash outflows associated with settling
asset retirement obligations that have been accrued on the Balance Sheet, at a discount factor of 10%; plus (2) the cost of properties
not being amortized, if any; plus (3) the lower of cost or estimated fair value of unproved properties included in the costs being
amortized, if any; less (4) income tax effects related to differences in the book and tax basis of oil and gas properties. Should
the net capitalized costs exceed the sum of the components noted above, a ceiling test write-down or impairment would be recognized
to the extent of the excess capitalized costs. Such impairments are permanent and cannot be recovered in future periods even if
the sum of the components noted above exceeds capitalized costs in future periods.
From Inception through December 31, 2017,
the Company did not recognize a ceiling test impairment. Future declines in oil and natural gas prices could result in impairments
of the Company’s oil and gas properties in future periods. The effect of price declines will impact the ceiling test value
until such time commodity prices stabilize or improve. Impairments are a non-cash charge and accordingly would not affect cash
flows but would adversely affect the Company’s results of operations and members’ equity.
We capitalize interest in accordance with
Financial Accounting Standards Board (“FASB”) ASC 932-835-25, Extractive Activities-Oil and Gas, Interest. Therefore,
interest is capitalized for any unusually significant investments in unproved properties or major development projects not currently
being depleted. We capitalize the portion of general and administrative costs that is attributable to our acquisition, exploration
and development activities.
Oil and Gas Reserves
Oil and gas reserves represent theoretical
quantities of crude oil, natural gas, and natural gas liquids (“NGL”) which geological and engineering data demonstrate
with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions.
There are numerous uncertainties inherent in estimating oil and gas reserves and their values, including many factors beyond the
Company’s control. Accordingly, reserve estimates and the projected economic value of the Seneca properties will differ
from the actual future quantities of oil and gas ultimately recovered and the corresponding value associated with the recovery
of these reserves.
Other Property and Equipment
Other property and equipment are recorded
at cost. Costs of renewals and improvements that substantially extend the useful lives of the assets are capitalized. Maintenance
and repair costs which do not extend the useful lives of property and equipment are charged to expense as incurred. Depreciation
and amortization is calculated using the straight-line method over the estimated useful lives of the assets. Office furniture,
automobiles, and computer hardware and software are depreciated over three to five years. Buildings are depreciated over 27.5
years, and pipeline facilities and equipment are depreciated over twenty years. Leasehold improvements are depreciated, using
the straight-line method, over the shorter of the lease term or the useful life of the asset. When other property and equipment
is sold or retired, the capitalized costs and related accumulated depreciation and amortization are removed from the accounts.
Base Gas
Gas that is used to maintain wellhead
pressures within the storage fields, referred to as non-working gas, is recorded other property and equipment on the consolidated
balance sheet. Base gas is held in a storage field that is not intended for sale but is required for efficient and reliable operation
of the facility.
Long-Lived Assets
The Company reviews its long-lived assets
other than oil and gas properties for impairment whenever events or changes in circumstances indicate that the carrying amount
of the asset may not be recovered. The Company looks primarily to the estimated undiscounted future cash flows in its assessment
of whether long-lived assets have been impaired. During the period ended December 31, 2017, the Company did not recognize any
impairment.
Asset Retirement Obligations
The Company’s asset retirement obligations
(“ARO”) relate to future costs associated with the plugging and abandonment of oil and gas wells, removal of equipment
and facilities from leased acreage and returning such land to its original condition. The fair value of a liability for an ARO
is recorded in the period in which it is incurred or assumed, and the cost of such liability is recorded as an increase in the
carrying amount of the related long-lived asset by the same amount for asset acquisitions. The liability is accreted each period
and the capitalized cost is depleted on a units-of-production basis as part of the full cost pool. Revisions to estimated ARO
result in adjustments to the related capitalized asset and corresponding liability.
The estimated ARO liability is based on
estimated economic lives, estimates as to the cost to abandon the wells in the future, and federal and state regulatory requirements.
The liability is discounted using a credit-adjusted risk-free rate estimated at the time the liability is incurred or increased
from a reassessment of expected cash flows and assumptions inherent in the estimation of the liability. Revisions to the liability
could occur due to changes in estimated abandonment costs or well economic lives, or if federal or state regulators enact new
requirements regarding the abandonment of wells. ARO is valued utilizing Level 3 fair value measurement inputs (note 7).
The following table is a reconciliation
of ARO (in thousands).
|
|
For the period from Inception through December 31,
2017
|
|
|
|
|
|
Balance at beginning of period
|
|
$
|
-
|
|
Additions from acquisitions during period
|
|
|
4,591
|
|
Accretion expense
|
|
|
198
|
|
|
|
|
|
|
Balance at end of period
|
|
$
|
4,789
|
|
For the period from Inception through
December 31, 2017, the addition of approximately $4.6 million to ARO is primarily due to the acquisition of producing oil and
natural gas properties in the Appalachian Basin. See note 3 for further discussion on the acquisitions.
Lease Operating
Lease operating and gathering, compression,
and transportation expenses are costs incurred to bring oil and natural gas out of the ground and to market, together with costs
incurred to maintain our producing properties. Costs include maintenance, repairs, pipeline operations and workover expenses related
to our oil and gas properties, and pipeline facilities and equipment.
Production and Property Taxes
Production and property taxes consist
of severance and ad valorem taxes and are paid on oil and natural gas produced based on a percentage of market prices or at fixed
rates established by federal, state or local taxing authorities.
Financial Instruments
The Company’s financial instruments
include cash and cash equivalents, accounts receivables, accounts payables and accrued liabilities, due to related parties, commodity
derivative instruments and note payable. The carrying value of cash and cash equivalents, accounts receivables, accounts payables
and accrued liabilities and due to related parties are representative of their fair value, due to the short maturity of these
instruments. The Company’s commodity derivative instruments are recorded at fair value, as discussed below and in note 8.
The Revolver approximated fair value with a variable interest rate, which is representative of the Company’s credit adjusted
borrowing rate plus London Inter-Bank Offered Rate (“LIBOR”). As of December 31, 2017, the Revolver had an effective
interest rate of 5.34%.
Commodity Derivative Instruments
The Company enters into commodity derivative
contracts to manage its exposure to oil and natural gas price volatility with an objective to reduce its exposure to downward
price fluctuations. Commodity derivative contracts may take the form of futures contracts, swaps, collars or options. The Company
has elected not to designate its derivatives as cash flow hedges. All derivatives are initially and subsequently measured at estimated
fair value and recorded as assets or liabilities on the consolidated balance sheet and the changes in fair value are recognized
as gains or losses in revenues in the consolidated statement of operations.
Income Taxes
The Company has elected to be treated
as a partnership for income tax purposes. Accordingly, taxable income and losses are reported on the income tax returns of the
Company’s members and no provision for income taxes has been recorded on the accompanying financial statements. Interest
and penalties associated with tax positions are recorded in the period assessed as general and administrative expenses. The Company’s
tax returns are subject to examination by tax authorities through the current period for state and federal tax reporting purposes.
Pursuant to the Bipartisan Budget Act
of 2015 (the “Act”), as of January 1, 2018, the Act allows the adjustment resulting from IRS audits of partnerships
to be assessed at the partnership level.
Use of Estimates in the Preparation
of Financial Statements
The preparation of financial statements
in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions
that affect the reported amounts of assets, liabilities and expenses and disclosure of contingent assets and liabilities. Significant
items subject to such estimates and assumptions include the carrying value of oil and gas properties, estimates of proved oil
and gas reserve volumes and the related depletion and present value of estimated future net cash flows and the ceiling test applied
to capitalized oil and gas properties, determining the amounts recorded for fair value of commodity derivative instruments, fair
value of assets acquired and liabilities assumed qualifying as business combination or asset acquisition, estimated lives of other
property and equipment, asset retirement obligations and accrued liabilities and revenues.
Recently Issued Accounting Pronouncements
In May 2014, the Financial Accounting
Standards Board (“FASB”) issued Accounting Standard Update (“ASU”) No. 2014-09,
Revenue from Contracts
with Customers
(“ASU 2014-09”). The objective of ASU 2014-09 is to clarify the principles for recognizing revenue
and to develop a common revenue standard for Generally Accepted Accounting Principles in the United States (“GAAP”)
and International Financial Reporting Standards (“IFRS”). The FASB subsequently issued ASU 2015-14, ASU 2016-08, ASU
2016-10, ASU 2016-12 and ASU 2016-20, which deferred the effective date of ASU 2014-09 and provided additional implementation
guidance. These ASUs are effective for the Company for fiscal years, beginning after December 15, 2019. The standards permit retrospective
application using either of the following methodologies: (i) restatement of each prior reporting period presented (the “full
retrospective approach”) or (ii) recognition of a cumulative-effect adjustment as of the date of the initial application
(the “modified retrospective approach”). The Company plans to adopt these ASUs effective January 1, 2019, using the
modified retrospective approach. The Company is in the process of assessing its contracts with customers and evaluating the effect
of adopting these standards on its financial statements, accounting policies, internal controls and disclosures.
In February 2016, the FASB issued ASU
No. 2016-02,
Leases
(“ASU 2016-02”). The objective of this ASU, as amended, is to increase transparency and
comparability among organizations by recognizing lease assets and liabilities on the consolidated balance sheet and disclosing
key information about leasing arrangements. ASU 2016-02 is effective for fiscal years, beginning after December 15, 2020 and should
be applied using a modified retrospective approach. Early adoption is permitted. The Company is currently evaluating the impact
on its financial statements of adopting ASU 2016-02.
In June 2016, the FASB issued ASU 2016-13,
Financial Instruments-Credit Losses
(Topic 326):
Measurement of Credit Losses on Financial Instruments
. These amendments
change the measurement of credit losses for most financial assets and certain other instruments that are not measured at fair
value through results of operations. The amendments in this update affect investments in loans, investments in note securities,
trade receivables, net investments in leases, off balance sheet credit exposures, reinsurance receivables, and any other financial
assets not excluded from the scope that have the contractual right to receive cash. The amendments replace the incurred loss impairment
methodology in current GAAP with a methodology that reflects expected credit losses and requires consideration of a broader range
of reasonable and supportable information to inform credit loss estimates. ASU 2016-13 is effective for fiscal years, beginning
after December 15, 2021. The Company is currently evaluating the impact on its financial statements of adopting ASU 2016-13.
Recently Adopted Accounting Pronouncement
In January 2017, the FASB issued ASU 2017-01,
Clarifying the Definition of a Business
, which clarifies the definition of “a business” to assist entities
with evaluating whether transactions should be accounted for as acquisitions or disposals of assets or businesses. The standard
introduces a screen for determining when assets acquired are not a business and clarifies that a business must include, at a minimum,
an input and a substantive process that contribute to an output to be considered a business. The Company elected to adopt this
pronouncement effective April 3, 2017.
Note 3 – Acquisitions
Knox-Coalfield
On April 3, 2017, the Company acquired
natural gas producing properties and related facilities located predominantly in Tennessee for a purchase price of $20.0 million,
subject to normal purchase adjustments, with an effective date of February 1, 2017, for oil and gas assets and April 3, 2017 for
the corporate entity acquired (the “Knox-Coalfield Acquisition”). Consideration to fund the Knox-Coalfield Acquisition
was provided by contributions from the Company’s members of $12.0 million and $8.5 million in funds drawn from its Revolver
(note 5).
The Knox-Coalfield Acquisition qualified
as a business combination as defined by Accounting Standards Codification (“ASC”) 805,
Business Combinations
and, as such, the Company estimated the fair value of the assets acquired and liabilities assumed as of the closing date of April
3, 2017.
The Company, utilizing the assistance
of third-party valuation specialists, considered various factors in its estimate of fair value of the acquired assets including
(i) reserves, (ii) production rates, (iii) future operating and development costs, (iv) future commodity prices, including price
differentials, (v) future cash flows, (vi) a market participant-based weighted average cost of capital, and (vii) real estate
market conditions.
The Company expensed approximately $457,000
of transaction and due diligence costs related to the Knox-Coalfield Acquisition that were included in general and administrative
expenses in the accompanying consolidated statement of operations for the period ended December 31, 2017.
The allocation of the purchase price is
considered preliminary and is subject to change upon completion of the determination of the fair value of all assets acquired
and liabilities assumed. The Company continues to work with our third-party valuation specialists to finalize the fair value of
the pipeline and oil and gas assets and expects to finalize the valuation by April 3, 2018. The following table summarizes the
preliminary consideration paid and the estimated fair value of the assets acquired and liabilities assumed.
Consideration paid:
|
|
|
|
Cash consideration
|
|
$
|
19,055
|
|
|
|
|
|
|
Recognized amounts of identifiable assets acquired and liabilities assumed:
|
|
|
|
|
Proved oil and gas properties
|
|
$
|
12,228
|
|
Unproved oil and gas properties
|
|
|
1,774
|
|
Property, plant, and equipment
|
|
|
5,858
|
|
Asset retirement obligation
|
|
|
(772
|
)
|
Accounts payable and accrued liabilities
|
|
|
(33
|
)
|
Total net assets acquired
|
|
$
|
19,055
|
|
The Company commenced operations on April
3, 2017. The Knox-Coalfield Acquisition closed April 3, 2017, and accordingly, the Company’s consolidated statement of operations
for the period ended December 31, 2017 includes the results of operations from April 3, 2017 to December 31, 2017 of the properties
acquired, including approximately $4.0 million of revenue.
Enervest
On August 15, 2017, the Company acquired
natural gas producing properties and related facilities located predominantly in the state of West Virginia for a purchase price
of $21.5 million, subject to normal purchase adjustments, with an effective date of May 1, 2017 (the “Enervest Acquisition”).
Consideration to fund the Enervest Acquisition was provided by contributions from the Company’s members of $14.0 million
and $8.0 million in funds drawn from its Revolver (note 5).
The assets acquired consist of oil and
gas leases and the associated mineral interests, oil and gas wells, a field office building and associated land, vehicles and
other miscellaneous equipment. The Company also acquired various contracts. The Company, utilizing the assistance of third-party
valuation specialists to estimate fair value, has determined that substantially all of the fair value of the assets acquired are
related to the production assets and, as such the Enervest Acquisition does not meet the definition of a business. Therefore,
the Company has accounted for the transaction as an asset acquisition and has allocated the purchase price based on the relative
fair value of the assets acquired.
In determining the relative fair value,
the fair value of the production assets was determined using the income approach using Level 3 inputs according the ASC 820,
Fair
Value
, hierarchy. The fair value of the other assets was determined using the market approach using Level 3 inputs. The determination
of the fair value of the oil and gas and other property and equipment acquired and accrued liabilities assumed required significant
judgement, including estimates relating to the production assets and the other assets acquired. The Company assumed $1.8 million
in ARO, $162,000 in firm transportation contract obligation and $247,000 in accounts payable and accrued liabilities associated
with the acquired assets. Below is the detail of the assets acquired (in thousands):
Identifiable assets acquired:
|
|
|
|
Assets:
|
|
|
|
Proved (producing) oil and gas properties
|
|
$
|
20,948
|
|
Property, plant and equipment
|
|
|
150
|
|
Total identified assets
|
|
$
|
21,098
|
|
The Company commenced operations on April
3, 2017. The Enervest Acquisition closed August 15, 2017, and accordingly, the Company’s consolidated statements of operations
for the period ended December 31, 2017 includes the results of operations from August 15, 2017 to December 31, 2017 of the properties
acquired, including approximately $2.27 million of revenue.
The Company incurred transaction costs
related to the Enervest Acquisition in the amount of approximately $248,000. As the acquisition was accounted for as an asset
acquisition, these transaction costs were capitalized and are included in oil and gas properties- proved, net on the consolidated
balance sheet.
Cabot
On September 29, 2017, the Company acquired
natural gas producing properties and related facilities as well as transmission pipeline facilities and equipment located predominantly
in the state of West Virginia for a purchase price of $41.3 million, subject to normal purchase adjustments, with an effective
date of April 1, 2017 for oil and gas assets and September 29, 2017, for the corporate entity acquired (the “Cabot Acquisition”).
Consideration to fund the Cabot Acquisition was provided by contributions from the Company’s members of $11.0 million and
$20.4 million in funds drawn from its Revolver (note 5).
The Cabot Acquisition qualified as a business
combination as defined by ASC 805,
Business Combinations
and, as such, the Company estimated the fair value of the assets
acquired and liabilities assumed as of the closing date of September 29, 2017.
The Company, utilizing the assistance
of third-party valuation specialists, considered various factors in its estimate of fair value of the acquired assets and liabilities
including (i) reserves, (ii) production rates, (iii) future operating and development costs, (iv) future commodity prices, including
price differentials, (v) future cash flows, (vi) a market participant-based weighted average cost of capital, and (vii) real estate
market conditions.
The Company expensed approximately $660,000
of transaction and due diligence costs related to the Cabot Acquisition that were included in general and administrative expenses
in the accompanying consolidated statement of operations for the period ended December 31, 2017.
The allocation of the purchase price is
considered preliminary and is subject to change upon completion of the determination of the fair value of all assets acquired
and liabilities assumed. The Company continues to work with our third-party valuation specialists to finalize the fair value of
the buildings, pipeline facilities and equipment and oil and gas assets and expects to finalize the valuation by no later than
September 29, 2018. The following table summarizes the preliminary consideration paid and the estimated fair value of the assets
acquired, and liabilities assumed.
Consideration paid:
|
|
|
|
Cash consideration
|
|
$
|
34,383
|
|
|
|
|
|
|
Recognized amounts of identifiable assets acquired and liabilities assumed:
|
|
|
|
|
Proved oil and gas properties
|
|
$
|
49,920
|
|
Property, plant and equipment
|
|
|
7,744
|
|
Inventory
|
|
|
467
|
|
Accounts receivable – trade receivables
|
|
|
850
|
|
Furniture and fixtures, computer hardware and software, and other equipment
|
|
|
22
|
|
Firm transportation contract obligation
|
|
|
(18,966
|
)
|
Production and property taxes
|
|
|
(2,370
|
)
|
Asset retirement obligation
|
|
|
(2,020
|
)
|
Accounts payable and accrued liabilities
|
|
|
(1,264
|
)
|
Total net assets acquired
|
|
$
|
34,383
|
|
The Company commenced operations on April
3, 2017. The Cabot Acquisition closed September 29, 2017, and accordingly, the Company’s consolidated statement of operations
for the period ended December 31, 2017 includes the results of operations from September 29, 2017 to December 31, 2017 of the
properties acquired, including approximately $22.0 million of revenue.
Note 4 – Property and Equipment
Net property and equipment at December 31, 2017 consists of
the following (in thousands):
Oil and gas properties:
|
|
|
|
Proved oil and gas properties
|
|
$
|
84,255
|
|
Unproved properties not subject to depletion
|
|
|
1,780
|
|
Accumulated depreciation, depletion and amortization
|
|
|
(1,633
|
)
|
Net oil and gas properties
|
|
|
84,402
|
|
|
|
|
|
|
Pipeline facilities and equipment
|
|
|
9,339
|
|
Base gas
|
|
|
2,122
|
|
Buildings
|
|
|
1,247
|
|
Vehicles
|
|
|
550
|
|
Furniture and fixtures, computer hardware and software, and other equipment
|
|
|
225
|
|
Accumulated depreciation and amortization
|
|
|
(806
|
)
|
Net other property and equipment
|
|
|
10,555
|
|
|
|
|
|
|
Total property and equipment
|
|
$
|
97,079
|
|
The Company had approximately $1.8 million
at December 31, 2017, of unproved oil and gas properties not subject to depletion. At December 31, 2017, the Company’s unproved
properties consist principally of leasehold acquisition costs in Tennessee.
During the period from Inception through
December 31, 2017, no expiring leasehold costs were reclassified into proved property. The costs not subject to depletion relate
to unproved properties that are excluded from amortized capital costs until it is determined whether or not proved reserves can
be assigned to such properties. These costs do not relate to any individually significant projects. The excluded properties are
assessed for impairment at least annually.
Depletion expense related to oil and gas
properties for the period from Inception through December 31, 2017 was approximately $1.6 million, or $0.25 per Mcfe. Depreciation
and amortization expense related to buildings, furniture and fixtures, computer hardware and software, and other equipment for
the period from Inception through December 31, 2017 was approximately $806,000.
Note 5 – Revolver
On April 3, 2017, Carbon Appalachia Enterprises
entered into a 4-year $100.0 million senior secured asset-based revolving credit facility with LegacyTexas Bank (the “Revolver”)
with an initial borrowing base of $10.0 million.
On August 15, 2017, in connection with
and concurrently with the closing of the Enervest Acquisition, the borrowing base of the Revolver increased to $22.0 million and
Carbon Appalachia Enterprises borrowed $8.0 million from the Revolver to partially fund the Enervest Acquisition.
On September 29, Carbon Appalachia Enterprises
amended the Revolver, resulting in a borrowing base of $50.0 million with redeterminations as of April 1 and October 1 each year
and the addition of East West Bank as a participating lender. In connection with and concurrently with the closing of the Cabot
Acquisition, Carbon Appalachia Enterprises borrowed $20.4 million from the Revolver to partially fund the Cabot Acquisition.
On November 30, 2017, Carbon Appalachia
Enterprises amended the Revolver, resulting in the addition of Bank SNB as a participating lender. The borrowing base of $50.0
million and commitment of $100.0 million was unchanged.
The Revolver bears interest at an applicable
margin ranging from 3.00% to 4.00%, depending on utilization, plus the applicable 30, 60 or 90-day London interbank offered rate
(“LIBOR”), at the Company’s election. As of December 31, 2017, the Company’s effective borrowing rate
on the Revolver was 5.34%. In addition, the Revolver includes a 0.50% unused available line fee.
As of December 31, 2017, the Revolver
has an outstanding balance of $38.0 million and a borrowing base of $50.0 million. The maximum principal amount available under
the Revolver is based upon the borrowing base attributable to the Company’s proved oil and gas reserves which is determined
at least semi-annually.
The Revolver is secured by all of the
assets of the Company. The Revolver requires the Company, as of each quarter end, to hedge 75% of its anticipated production for
the next 30 months. Distributions to equity members are generally restricted.
In the event of default or deficiency
in borrowing base, an additional 2.0% interest rate would apply. In such event, a cure period exists allowing the Company to obtain
compliance.
The Company incurred fees directly associated
with the issuance of the Revolver and amortizes these fees over the life of the Revolver. The current portion of these fees are
recorded as prepaid expense and deposits and the non-current portion as other non-current assets for a combined value of $584,000
as of December 31, 2017. From Inception through December 31, 2017, the Company amortized approximately $79,000 associated with
these fees.
The Revolver agreement requires the Company
to maintain certain financial and non-financial covenants which include the following ratios: leverage ratio, current ratio, and
other qualitative covenants as defined in the Revolver agreement including commodity hedging requirements. As of December 31,
2017, the Company was compliant with its financial covenants. The Revolver is secured by all of the assets of the Company.
Interest Expense
For the period of Inception through December
31, 2017, the Company incurred interest expense of approximately $891,000 which approximately $79,000 was amortization of the
Revolver issuance costs.
Note 6 – Accounts Payable and Accrued Liabilities
Accounts payable and accrued liabilities
at December 31, 2017 consists of the following (in thousands):
Accounts payable
|
|
$
|
3,878
|
|
Marketing gas sales
|
|
|
2,467
|
|
Accrued ad valorem taxes
|
|
|
1,812
|
|
Accrued lease operating
|
|
|
1,135
|
|
Transportation, gathering and compression
|
|
|
699
|
|
Property and production taxes
|
|
|
674
|
|
Suspense payable
|
|
|
544
|
|
Accrued interest
|
|
|
106
|
|
Other
|
|
|
755
|
|
Total accounts payable and accrued liabilities
|
|
$
|
12,070
|
|
Note 7 – Fair Value Measurements
Authoritative guidance defines fair value
as the price that would be received to sell an asset or paid to transfer a liability (an exit price) in an orderly transaction
between market participants at the measurement date. The guidance establishes a hierarchy for inputs used in measuring fair value
that maximizes the use of observable inputs and minimizes the use of unobservable inputs by requiring that the most observable
inputs be used when available. Observable inputs are inputs that market participants would use in pricing the asset or liability
developed based on market data obtained from sources independent of the Company. Unobservable inputs are inputs that reflect the
Company’s assumptions of what market participants would use in pricing the asset or liability developed based on the best
information available in the circumstances. The hierarchy is broken down into three levels based on the reliability of the inputs
as follows:
|
Level
1:
|
Quoted
prices are available in active markets for identical assets or liabilities;
|
|
|
|
|
Level 2:
|
Quoted prices in
active markets for similar assets or liabilities that are observable for the asset or liability; or
|
|
|
|
|
Level 3:
|
Unobservable pricing
inputs that are generally less observable from objective sources, such as discounted cash flow models or valuations.
|
Financial assets and liabilities are classified
based on the lowest level of input that is significant to the fair value measurement. The Company’s policy is to recognize
transfers in and/or out of fair value hierarchy as of the end of the reporting period for which the event or change in circumstances
caused the transfer. The Company has consistently applied the valuation techniques discussed below throughout the period presented.
The following table presents the Company’s
financial assets that were accounted for at fair value on a recurring basis as of December 31, 2017 by level within the fair value
hierarchy (in thousands):
|
|
Fair
Value Measurements Using
|
|
|
|
Level
1
|
|
|
Level
2
|
|
|
Level
3
|
|
|
Total
|
|
Assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity
derivatives - current
|
|
$
|
-
|
|
|
$
|
1,884
|
|
|
$
|
-
|
|
|
$
|
1,884
|
|
Commodity derivatives
– other long-term assets
|
|
$
|
-
|
|
|
$
|
155
|
|
|
$
|
-
|
|
|
$
|
155
|
|
As of December 31, 2017, the Company’s
commodity derivative financial instruments are comprised of natural gas and oil swap and collar agreements. The fair values of
these agreements are determined under an income valuation technique. Swaps are valued using the income technique. Collars are
valued using the option model. The valuation model requires a variety of inputs, including contractual terms, published forward
prices, volatilities for options and discount rates, as appropriate. The Company’s estimates of the fair value of derivatives
include consideration of the counterparty’s credit worthiness, the Company’s credit worthiness and the time value
of money. The consideration of these factors results in an estimated exit-price for each derivative asset or liability under a
market place participant’s view. All the significant inputs are observable, either directly or indirectly; therefore, the
Company’s derivative instruments are included within the Level 2 fair value hierarchy. The counterparty for all the Company’s
outstanding commodity derivative financial instruments as of December 31, 2017 is BP Energy Company (“BPEC”).
Assets and Liabilities Measured and
Recorded at Fair Value on a Non-Recurring Basis
Acquired accounts receivable, accounts
payable, and other accrued liabilities were determined to be representative of fair value given their short-term nature. Acquired
base gas and gas inventory was valued based on prevailing market rates for natural gas on the closing date of September 29, 2017.
The fair values of each of the following
assets and liabilities measured and recorded at fair value on a non-recurring basis are based on unobservable pricing inputs and
therefore, are included within the Level 3 fair value hierarchy.
Asset Retirement Obligation
The fair value of the Company’s
asset retirement obligation liability is calculated as of the date of closing of each of the Company’s acquisitions, when
the liability was assumed, by estimating (i) the cost of abandoning oil and gas wells ranging from $15,000 to $30,000 based on
market participant expectations for similar work; (ii) the timing of reclamation ranging from 2-75 years based on economic lives
of its properties as estimated by reserve engineers; (iii) an inflation rate between 1.81% and 2.04%; and (iv) a credit adjusted
risk-free rate of 6.59%, which takes into account the Company’s credit risk and the time value of money (asset acquisitions)
or a range of 13.5% - 15.0% representing a market participant’s weighted average cost of capital (business combinations).
Given the unobservable nature of the inputs, the initial measurement of the asset retirement obligation liability is deemed to
use Level 3 inputs (see note 2). During the period from Inception through December 31, 2017, the Company recorded asset retirement
obligation assumed of approximately $4.6 million.
Firm Transportation Obligation
The Company assumed liabilities associated
with firm transportation contracts in connection with the Enervest Acquisition and Cabot Acquisition. The fair value of these
acquired firm transportation obligations was estimated based upon (i) the contractual obligations assumed by the Company (including
the length of contracts, committed volumes, and demand charges described in note 9), (ii) estimated usage from a market-participant
perspective, and (iii) a discount rate of 15.0% based upon a market participant’s estimated weighted average cost of capital.
Class B Units
The Company issued Class B units to Carbon
as part of entering into the Carbon Appalachia LLC Agreement. The $924,000 fair value of the Class B units was estimated by the
Company utilizing the assistance of third-party valuation specialists. The fair value was based upon enterprise values derived
from inputs including estimated future production rates, future commodity prices including price differentials as of the date
of closing, future operating and development costs and comparable market participants.
Acquired Assets
For assets accounted for as business combinations,
including the Knox-Coalfield Acquisition and Cabot Acquisition (see note 3), to determine the fair value of the assets acquired,
the Company primarily used the income approach and made market assumptions as to projections of estimated quantities of oil and
natural gas reserves, future production rates, future commodity prices including price differentials as of the date of closing,
future operating and development costs, a market participant weighted average cost of capital, and the condition of vehicles and
equipment.
For the assets acquired in the Enervest
Acquisition and accounted for as an asset acquisition, to determine the fair value of the assets acquired, the Company primarily
used the income approach and made market assumptions as to projections of estimated quantities of oil and natural gas reserves,
future production rates, future commodity prices including price differentials as of the date of closing, future operating and
development costs and its weighted average cost of capital.
Note 8 – Commodity Derivatives
The Company entered into commodity-based
derivative contracts at various times during 2017 to manage exposures to commodity price on certain of its oil and natural gas
production. The Company does not hold or issue derivative financial instruments for speculative or trading purposes.
Pursuant to the terms of the Company’s
Revolver, the Company has entered into derivative agreements to hedge certain of its oil and natural gas production for 2017 through
2020. As of December 31, 2017, these derivative agreements consisted of the following:
|
|
Natural
Gas Swaps
|
|
|
Natural
Gas Collars
|
|
|
Oil
Swaps
|
|
|
|
|
|
|
Weighted
|
|
|
|
|
|
Weighted
|
|
|
|
|
|
Weighted
|
|
|
|
|
|
|
Average
|
|
|
|
|
|
Average
Price
|
|
|
|
|
|
Average
|
|
Year
|
|
MMBtu
|
|
|
Price
(a)
|
|
|
MMBtu
|
|
|
Range (a)
|
|
|
Bbl
|
|
|
Price
(b)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2018
|
|
|
9,100,000
|
|
|
$
|
2.99
|
|
|
|
3,630,000
|
|
|
|
$2.85
- $3.85
|
|
|
|
15,000
|
|
|
$
|
51.74
|
|
2019
|
|
|
11,515,000
|
|
|
$
|
2.86
|
|
|
|
480,000
|
|
|
|
$2.85 - $3.19
|
|
|
|
12,000
|
|
|
$
|
50.35
|
|
2020
|
|
|
3,792,000
|
|
|
$
|
2.83
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
$
|
-
|
|
(a)
|
NYMEX
Henry Hub Natural Gas futures contract for the respective period.
|
(b)
|
NYMEX Light Sweet
Crude West Texas Intermediate futures contract for the respective period.
|
For its swap instruments, the Company
receives a fixed price for the hedged commodity and pays a floating price to the counterparty. The fixed-price payment and the
floating-price payment are netted, resulting in a net amount due to or from the counterparty. Collars are designed to establish
floor and ceiling prices on anticipated future oil and gas production. The ceiling establishes a maximum price that the Company
will receive for the volumes under contract, while the floor establishes a minimum price.
The following table summarizes the fair
value of the derivatives recorded in the consolidated balance sheet as of December 31, 2017. These derivative instruments are
not designated as cash flow hedging instruments for accounting purposes (in thousands):
Commodity derivative
contracts:
|
|
|
|
Current
assets
|
|
$
|
1,884
|
|
Other non-current
assets
|
|
$
|
155
|
|
The table below summarizes the commodity
settlements and unrealized gains and losses related to the Company’s derivative instruments for the period from Inception
through December 31, 2017 and are included in commodity derivative gain or loss in the accompanying consolidated statement of
operations.
Commodity derivative contracts:
|
|
|
|
Commodity derivative gain - realized
|
|
$
|
506
|
|
Commodity derivative gain - unrealized
|
|
|
2,039
|
|
|
|
|
|
|
Total commodity derivative gain
|
|
$
|
2,545
|
|
Commodity derivative gain, inclusive of
unrealized gain, is included in cash flows from operating activities in the consolidated statement of cash flows.
The counterparty in the Company’s
derivative instruments is BPEC. The Company has entered into an International Swaps and Derivative Association, Inc. (“ISDA”)
Master Agreement with BPEC that establishes standard terms for the derivative contracts and an inter-creditor agreement with Revolver
participating lenders and BPEC whereby any credit exposure related to the derivative contracts entered into by the Company and
BPEC is secured by the collateral and backed by the guarantees supporting the credit facility.
The Company nets its derivative instrument
fair value amounts executed with its counterparty pursuant to an ISDA master agreement, which provides for the net settlement
over the term of the contracts and in the event of default or termination of the contracts. The Company’s derivative instruments
are recorded as assets in the Balance Sheet as of December 31, 2017.
|
|
|
|
|
|
|
|
Net
|
|
|
|
Gross
|
|
|
|
|
|
Recognized
|
|
|
|
Recognized
|
|
|
Gross
|
|
|
Fair Value
|
|
|
|
Assets/
|
|
|
Amounts
|
|
|
Assets/
|
|
Consolidated Balance Sheet Classification
|
|
Liabilities
|
|
|
Offset
|
|
|
Liabilities
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivative assets:
|
|
|
|
|
|
|
|
|
|
Commodity derivative asset
|
|
$
|
2,288
|
|
|
$
|
(404
|
)
|
|
$
|
1,884
|
|
Other non-current assets
|
|
|
1,150
|
|
|
|
(995
|
)
|
|
|
155
|
|
Commodity derivative assets
|
|
$
|
3,438
|
|
|
$
|
(1,399
|
)
|
|
$
|
2,039
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivative liabilities
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivative liability
|
|
$
|
404
|
|
|
$
|
(404
|
)
|
|
$
|
-
|
|
Other non-current liabilities
|
|
|
995
|
|
|
|
(955
|
)
|
|
|
-
|
|
Total derivative liabilities
|
|
$
|
1,399
|
|
|
$
|
(1,399
|
)
|
|
$
|
-
|
|
Due to the volatility of oil and natural
gas prices, the estimated fair values of the Company’s derivatives are subject to large fluctuations from period to period.
Note 9 – Commitments and Contingencies
In connection with the Enervest Acquisition
and Cabot Acquisition, the Company acquired long-term firm transportation contracts that were entered into to ensure the transport
for certain gas production to purchasers. Firm transportation volumes and the related demand charges for the remaining term of
these contracts at December 31, 2017 are summarized in the table below.
Period
|
|
Dekatherms
per day
|
|
Demand
Charges
|
Jan 2018
– October 2020
|
|
6,300
|
|
$0.21
|
Jan 2018 –
May 2027
|
|
29,900
|
|
$0.21
|
Jan 2018 –
August 2022
|
|
19,441
|
|
$0.56
|
Liabilities of approximately $19.0 million
and $162,000 related to firm transportation contracts assumed in the Cabot Acquisition and Enervest Acquisition, respectively,
which represent the remaining commitments, are reflected on the Company’s consolidated balance sheet as of December 31,
2017. The fair values of these firm transportation obligations were determined based upon the contractual obligations assumed
by the Company and discounted based upon the Company’s effective borrowing rate. These contractual obligations are being
amortized monthly as the Company pays these firm transportation obligations in the future.
Legal and Environmental
We are not aware of any legal or environmental
material pending or threatened litigation or of any proceedings known to be contemplated by governmental authorities or regulators
which are, or would be, likely to have a material adverse effect upon the Company or our operations, taken as a whole.
Note 10 – Members’ Equity
On April 3, 2017, Carbon, Yorktown and
Old Ironsides entered in to a limited liability company agreement (the “Carbon Appalachia LLC Agreement”), with an
initial equity commitment of $100.0 million. The initial capital commitment percentages of Carbon, Yorktown and Old Ironsides
was 2.0%, 24.5% and 73.5%, respectively.
On April 3, 2017, the Company (i) issued
240; 2,940; and 8,820 Class A Units at a value of $1,000 per Class A Unit to Carbon, Yorktown and Old Ironsides, respectively,
for an aggregate cash consideration of $12.0 million, (ii) issued Class B Units to Carbon, and (iii) issued Class C Units to Carbon.
See additional information related to each class described below. The proceeds contributed to the Knox-Coalfield Acquisition.
On April 3, 2017, in connection with the
Carbon Appalachia LLC Agreement, Carbon issued to Yorktown a warrant to purchase shares of Carbon’s common stock at an exercise
price dictated by the warrant agreement (the “Appalachia Warrant”). The exercise price for the Appalachia Warrant
is payable exclusively with Class A Units of the Company held by Yorktown.
On August 15, 2017, the Carbon Appalachia
LLC Agreement was amended and, as a result, Carbon would contribute its initial commitment of future capital contributions as
well as Yorktown’s, and Yorktown would not participate in future capital contributions. The Company issued 3,710 and 10,290
Class A Units to Carbon and Old Ironsides, respectively, for an aggregate cash consideration of $14.0 million, the proceeds of
which contributed to the Enervest Acquisition purchase.
On September 29, 2017, the Company issued
2,915 and 8,085 Class A Units to Carbon and Old Ironsides, respectively, for an aggregate cash consideration of $11.0 million,
the proceeds of which contributed to the Cabot Acquisition purchase.
On November 1, 2017, Yorktown exercised
the Appalachia Warrant, resulting in Carbon acquiring all of Yorktown’s 2,940 Class A Units.
Class A Units
As of December 31, 2017, the Company had
37,000 Class A Units outstanding, of which 9,805 and 27,195 Class A Units were held by Carbon and Old Ironsides, respectively.
Holders of Class A units (i) can designate
person(s) to serve on the board of directors (currently three for Old Ironsides and one for Carbon), (ii) have the right to vote
equal to the number of outstanding Class A units held on each and every matter submitted to the members for approval, and (iii)
shall be required to make capital contributions to the Company as capital calls which are unanimously approved by the majority
of the members of the class. Failure to make the required capital contributions results in the member receiving a status of defaulting
member. The units are recorded as members’ contribution in the statement of members’ equity.
Class B Units
As of December 31, 2017, the Company had
1,000 Class B Units outstanding, of which Carbon held all such units.
Holders of Class B Units (i) have no obligation
to make capital contributions, (ii) have no voting rights, and (iii) have the ability to participate in profits interest after
certain return thresholds to holders of Class A Units are met (see “Distributions” below).
Class C Units
As of December 31, 2017, the Company had
121 Class C Units outstanding, of which Carbon held all such units. Carbon acquired its Class C Units in connection with its contribution
to the Company of a portion of its working interest in Carbon’s undeveloped properties in Tennessee. If the Company agrees
to drill wells on these properties, the Company will pay 100% of the cost of drilling and completion of the first 20 wells to
earn a 75% working interest in such properties. Carbon, through its subsidiary, Nytis LLC, will retain a 25% working interest
in the properties. No value was assigned to the Class C Units after consideration of all contemplated transactions and the entering
into of the Carbon Appalachia LLC Agreement. No activity was performed related to the undeveloped properties in Tennessee during
2017.
Holders of Class C Units (i) have no obligation
to make capital contributions, (ii) have no voting rights except in very limited circumstances where its interests may be adversely
affected, and (iii) participate in distributions as outlined below (see “Distributions” below).
Distributions
The Company’s board of directors
will determine, by unanimous approval, any distributions. Distributions will first be allocated to Class C members, then to Class
A and Class B members.
Class A Units are entitled to a priority
amount that requires that at the time of each distribution the Class A Unit receive an amount equal to an internal rate of return
of 10% of the aggregate capital contributed in exchange for the Class A Unit (the “Priority Amount”).
Until such time as the Priority Amount
of each Class A Unit has been reduced to zero, distributions are distributed (i) first to holders of Class C Units and (ii) then
to holders of Class A Units in proportion to their Class A Priority Amount.
After the Priority Amount has been reduced
to zero, (i) 80% of distributions are allocated between holders of Class A and Class C Units based on the proportionate share,
and (ii) 20% of distributions are allocated holders of Class B Units.
Sharing Percentage
The sharing percentage of each member
shall equal the aggregate number of units held by such member divided by the aggregate number of units then outstanding (“Sharing
Percentage”), as defined in the Carbon Appalachia Company, LLC Agreement, as amended, and is applicable to each class of
units.
The term “Aggregate Sharing Percentage”
refers to the aggregated sharing percentage when taking into consideration all classes of ownership.
Drag-along Rights
Old Ironsides may elect to execute a “Drag-Along”
sale which the parameters and specifics are disclosed in the limited liability company agreement.
Note 11 – Related Parties
During the period ended December 31, 2017, the Company was
engaged in the following transactions with related parties (in thousands):
On April 3, 2017, as part of entry into
the Carbon Appalachia LLC Agreement and the associated transactions, Carbon received 1,000 Class B Units and 121 Class C Units,
which each represent 100% of their respective class.
Nytis Exploration Company, Inc (“Nytis”)
is a wholly-owned subsidiary of Carbon and the operator of the Company’s properties through an operating agreement. The
operating agreement includes direct reimbursements and direct allocations made under the agreement. Approximately $1.2 million
in reimbursements was included in due to related parties as of December 31, 2017.
Management services
On April 3, 2017, the Company entered
into a management service agreement with Carbon whereby Carbon provides general management and administrative services to the
Company. The Company initially paid Carbon a quarterly fee of $75,000; however, subsequent to the Enervest Acquisition, the amount
of the reimbursement to Carbon now varies quarterly based upon the percentage of production of the Company as a percentage of
the total volume of production from Carbon and the Company. The Company reimburses Carbon for all management related expenses
such as travel, required third-party geological and/or accounting consulting, and other necessary expenses incurred by Carbon
in the normal course of managing the Company.
The Company incurred approximately $1.6
million in management reimbursements for the period Inception through December 31, 2017, of which $1.3 million was recorded as
management reimbursements, related party in the statement of operations. Approximately $679,000 was included in due to related
parties as of December 31, 2017.
Note 12 – Supplemental Cash
Flow Disclosure
Supplemental cash flow disclosures for
period from Inception through December 31, 2017 are presented below (in thousands):
Cash paid during the period for:
|
|
|
|
Interest payments
|
|
$
|
706
|
|
Non-cash transactions:
|
|
|
|
|
Increase in acquired asset retirement obligations
|
|
|
4,591
|
|
Increase in accounts payable and accrued liabilities
included in oil and gas properties
|
|
|
32
|
|
Accounts payable and accrued liabilities assumed
in oil and gas properties (Note 4)
|
|
|
3,667
|
|
Note 13 – Subsequent Events
The Company evaluated activities from
December 31, 2017, to the date of the independent registered public accountants report, the date these financial statements were
available for issuance, and there are no subsequent events requiring recognition or disclosure.
REPORT OF INDEPENDENT
REGISTERED PUBLIC ACCOUNTING FIRM
To the Members and Board of Directors
Carbon California Company, LLC
Denver, Colorado
OPINION ON THE FINANCIAL STATEMENTS
We have audited the accompanying balance
sheet of Carbon California Company, LLC (the “Company”) as of December 31, 2017, and the related statements of operations,
members’ equity, and cash flows, for the period from February 15, 2017 through December 31, 2017, and the related notes
(collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly,
in all material respects, the financial position of the Company as of December 31, 2017, and the results of its operations and
its cash flows for the period from February 15, 2017 through December 31, 2017, in conformity with accounting principles generally
accepted in the United States of America.
BASIS FOR OPINION
These financial statements are the responsibility
of the Company’s management. Our responsibility is to express an opinion on the Company’s financial statements based
on our audit. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (“PCAOB”)
and are required to be independent with respect to the Company in accordance with relevant ethical requirements related to our
audit.
We conducted our audit in accordance with
the auditing standards of the PCAOB and in accordance with auditing standards generally accepted in the United States of America.
Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements
are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to
perform, an audit of its internal control over financial reporting. As part of our audit we are required to obtain an understanding
of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company’s
internal control over financial reporting. Accordingly, we express no such opinion.
Our audit included performing procedures
to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures
that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures
in the financial statements. Our audit also included evaluating the accounting principles used and significant estimates made
by management, as well as evaluating the overall presentation of the financial statements. We believe that our audit provides
a reasonable basis for our opinion.
/s/
EKS&H LLLP
|
|
EKS&H LLLP
|
|
March 31, 2018
Denver, Colorado
We have served as the Company’s auditor since 2017.
CARBON CALIFORNIA COMPANY, LLC
Balance Sheet
(in thousands)
|
|
As of December 31,
|
|
|
|
2017
|
|
ASSETS
|
|
|
|
Current assets:
|
|
|
|
Cash and cash equivalents
|
|
$
|
1,092
|
|
Accounts receivable:
|
|
|
|
|
Other
|
|
|
801
|
|
Trade
|
|
|
238
|
|
Due from related parties (Note 11)
|
|
|
113
|
|
Prepaid expense and deposits
|
|
|
1,724
|
|
Total current assets
|
|
|
3,968
|
|
|
|
|
|
|
Property and equipment (Note 4)
|
|
|
|
|
Oil and gas properties, full cost method of accounting:
|
|
|
|
|
Proved, net
|
|
|
41,963
|
|
Unproved
|
|
|
1,495
|
|
Other property and equipment, net
|
|
|
816
|
|
Total property and equipment, net
|
|
|
44,274
|
|
Other long-term assets
|
|
|
485
|
|
Total assets
|
|
$
|
48,727
|
|
|
|
|
|
|
LIABILITIES AND MEMBERS’ EQUITY
|
|
|
|
|
Current liabilities:
|
|
|
|
|
Accounts payable and accrued liabilities
|
|
$
|
5,129
|
|
Due to related parties (Note 11)
|
|
|
470
|
|
Asset retirement obligations
|
|
|
384
|
|
Commodity derivative liability
|
|
|
916
|
|
Total current liabilities
|
|
|
6,899
|
|
Non-current liabilities:
|
|
|
|
|
Asset retirement obligations
|
|
|
2,520
|
|
Commodity derivative liability
|
|
|
809
|
|
Revolver, related party (Notes 5 and 11)
|
|
|
11,000
|
|
Notes payable
|
|
|
92
|
|
Notes, related party, net (Notes 5 and 11)
|
|
|
8,858
|
|
Total non-current liabilities
|
|
|
23,279
|
|
Commitments and contingencies (Notes 9 and 13)
|
|
|
|
|
Members’ equity:
|
|
|
|
|
Members’ contributions
|
|
|
25,101
|
|
Accumulated deficit
|
|
|
(6,552
|
)
|
Total members’ equity
|
|
|
18,549
|
|
Total liabilities and members’ equity
|
|
$
|
48,727
|
|
See accompanying notes to financial statements.
CARBON CALIFORNIA COMPANY, LLC
Statement of Operations
(In thousands)
|
|
For the
Period from
February 15,
2017
(inception)
through
December 31,
|
|
|
|
2017
|
|
Revenue:
|
|
|
|
Oil
|
|
$
|
7,024
|
|
Natural gas
|
|
|
1,036
|
|
Natural gas liquids
|
|
|
556
|
|
Commodity derivative loss
|
|
|
(1,381
|
)
|
Total revenue
|
|
|
7,235
|
|
|
|
|
|
|
Expenses:
|
|
|
|
|
Lease operating
|
|
|
3,726
|
|
Gathering and transportation
|
|
|
1,442
|
|
Production and property taxes
|
|
|
527
|
|
General and administrative
|
|
|
2,177
|
|
Depreciation, depletion, and amortization
|
|
|
1,304
|
|
Accretion of asset retirement obligations
|
|
|
192
|
|
Management reimbursements, related party (Note 11)
|
|
|
525
|
|
Total expenses
|
|
|
9,893
|
|
|
|
|
|
|
Operating loss
|
|
|
(2,658
|
)
|
|
|
|
|
|
Other expense:
|
|
|
|
|
Class B unit issuance (Note 7)
|
|
|
(1,854
|
)
|
Interest expense
|
|
|
(2,040
|
)
|
|
|
|
|
|
Net loss
|
|
$
|
(6,552
|
)
|
See accompanying notes to financial statements.
CARBON CALIFORNIA COMPANY, LLC
Statement of Members’ Equity
(In thousands, except unit amounts)
|
|
Members’ Contributions
|
|
|
|
|
|
|
|
|
Total
|
|
|
|
Class A
Units
|
|
|
Amount
|
|
|
Class B
Units
|
|
|
Amount
|
|
|
Accumulated
deficit
|
|
|
members’
equity
|
|
Inception-February 15, 2017
|
|
|
-
|
|
|
$
|
-
|
|
|
|
-
|
|
|
$
|
-
|
|
|
$
|
-
|
|
|
$
|
-
|
|
Initial capital members’ Unit contribution
(Note 10)
|
|
|
22,000
|
|
|
|
22,000
|
|
|
|
5,077
|
|
|
|
1,854
|
|
|
|
-
|
|
|
|
23,854
|
|
Units issued with Notes, related party (Notes 5 and
10)
|
|
|
1,425
|
|
|
|
1,247
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
1,247
|
|
Net loss
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
(6,552
|
)
|
|
|
(6,552
|
)
|
Balances at December 31, 2017
|
|
|
23,425
|
|
|
$
|
23,247
|
|
|
|
5,077
|
|
|
$
|
1,854
|
|
|
$
|
(6,552
|
)
|
|
$
|
18,549
|
|
See accompanying notes to financial statements.
CARBON CALIFORNIA COMPANY, LLC
Statement of Cash Flows
(in thousands)
|
|
For the
Period from
February 15,
2017
(inception)
through
December 31,
|
|
|
|
2017
|
|
Cash flows from operating activities:
|
|
|
|
Net loss
|
|
$
|
(6,552
|
)
|
Items not involving cash:
|
|
|
|
|
Depreciation, depletion, and amortization
|
|
|
1,304
|
|
Accretion of asset retirement obligations
|
|
|
192
|
|
Commodity derivative loss
|
|
|
1,725
|
|
Amortization of Notes and Revolver issuance costs
|
|
|
131
|
|
Amortization of notes discount
|
|
|
276
|
|
Class B Units issuance
|
|
|
1,854
|
|
Net change in:
|
|
|
|
|
Accounts receivable trade
|
|
|
(238
|
)
|
Accounts receivable other
|
|
|
(802
|
)
|
Due from/to related parties
|
|
|
358
|
|
Prepaid expense and deposits
|
|
|
(1,606
|
)
|
Accounts payable and accrued liabilities
|
|
|
4,519
|
|
Net cash provided by operating activities
|
|
|
1,161
|
|
|
|
|
|
|
Cash flows from investing activities:
|
|
|
|
|
Acquisition of oil and gas properties and other property and equipment
|
|
|
(39,582
|
)
|
Purchase of other property and equipment
|
|
|
(583
|
)
|
Development of oil and gas properties and other property
and equipment
|
|
|
(2,000
|
)
|
Net cash used in investing activities
|
|
|
(42,165
|
)
|
|
|
|
|
|
Cash flows from financing activities:
|
|
|
|
|
Member contributions
|
|
|
22,000
|
|
Proceeds from Notes, related party
|
|
|
10,000
|
|
Proceeds from Revolver, related party
|
|
|
11,000
|
|
Notes and Revolver issuance costs
|
|
|
(904
|
)
|
Net cash provided by financing activities
|
|
|
42,096
|
|
|
|
|
|
|
Net increase in cash and cash equivalents
|
|
|
1,092
|
|
|
|
|
|
|
Cash and cash equivalents, beginning of period
|
|
|
-
|
|
|
|
|
|
|
Cash and cash equivalents, end of period
|
|
$
|
1,092
|
|
See Note 12– Supplemental Cash Flow Disclosure
See accompanying notes to financial statements.
Notes to Financial
Statements
Note 1 – Organization
On December 20, 2016, Carbon California
Company, LLC (the “Company” or “CCC”) was formed, as a Delaware limited liability company, by Carbon Natural
Gas Company (“Carbon”) a Delaware Corporation, entities managed by Yorktown Energy Partners XI, L.P. (“
Yorktown
”)
and Prudential Capital Energy Partners, L.P. (“
Prudential
”) to acquire, own, operate and dispose of
oil and gas properties in the Ventura Basin in California. The Company began substantial operations on February 15, 2017 (“Inception”).
Equity and ownership
On February 15, 2017, the Company (i)
issued and sold Class A Units to Yorktown and Prudential for an aggregate cash consideration of $22.0 million, split equally between
Yorktown and Prudential, (ii) entered into a Note Purchase Agreement (the “Note Purchase Agreement”) with Prudential
Capital Energy Partners, L.P. for the issuance and sale of up to $25.0 million of Senior Secured Revolving Notes (the “Revolver”)
due February 15, 2022 and (iii) entered into a Securities Purchase Agreement (the “Securities Purchase Agreement”)
with Prudential for the issuance and sale of $10.0 million of Senior Notes (the “Notes”) due February 15, 2024. As
part of the issuance of the Notes, Prudential was granted an additional 5% ownership in the Company in the form of an additional
1,425 Class A Units. Prudential owns a total of 12,425 shares of Class A Units for a total ownership of 53.0% and with an aggregate
Sharing Percentage of 43.6% (defined below). The Company recorded the relative fair value of the 1,425 additional Class A Units
issued in connection with the Notes as a discount of $1.25 million which is amortized over the life of the Notes utilizing the
interest method (see Notes 5 and 11).
The closing of the Note Purchase Agreement
on February 15, 2017, resulted in the sale and issuance by the Company of (i) the Revolver in the principal amount of $10.0 million
and (ii) Notes in the original principal amount of $10.0 million. The maximum principal amount available under the Revolver is
based upon the borrowing base attributable to the Company’s proved oil and gas reserves which is to be determined at least
semi-annually. The current borrowing base is $15.0 million, of which $11.0 million is outstanding as of December 31, 2017.
As of December 31, 2017, Yorktown holds
11,000 Class A Units in the Company, which equates to 38.6% Aggregate Share ownership of the Company, Prudential holds 12,425
Class A Units of the Company, which equates to 43.6% aggregate share ownership of the Company and Carbon holds 5,077 Class B units,
which equates to aggregate share ownership of 17.8% of the Company.
In connection with Carbon entering into
the Carbon California LLC Agreement, and Carbon California engaging in the transactions described above, Carbon received 5,077
Class B units and issued to Yorktown a warrant to purchase approximately 1.5 million shares of Carbon’s common stock at
an exercise price dictated by the warrant agreement (the “California Warrant”). The California Warrant is payable
exclusively with Class A Units of Carbon California held by Yorktown. On February 5, 2018, Yorktown exercised the California Warrant,
resulting in Carbon acquiring 11,000 Class A Units from Yorktown.
Net proceeds from the February 15, 2017
transactions were used by the Company to complete the CRC Acquisition and Mirada Acquisition (defined below). The remainder of
the net proceeds were used to fund field development projects, future complementary acquisitions, and working capital.
On February 15, 2017, the Company acquired
oil and gas assets in the Ventura Basin of California from California Resources Petroleum Corporation and California Resources
Production Corporation for $34.0 million, subject to normal purchase adjustments, with an effective date of November 1, 2017 (the
“CRC Acquisition”). See Note 3.
On February 15, 2017, the Company closed
the purchase of oil, natural gas, and natural gas liquids assets in the Ventura Basin of California from Mirada Petroleum, Inc.
for $4.5 million, subject to certain adjustments, with an effective date of January 1, 2017 (the “Mirada Acquisition”).
See Note 3.
Liquidity and Management’s
Plans
The Company’s activities have focused
on the acquisition and development of its oil and gas wells in California which have incurred recurring losses. On December 4,
2017, the Company’s production in California was reduced to minimal amounts due to a wildfire that impacted several areas
of production. The Company expects production to return to operating levels experienced prior to the fire and does not anticipate
continued operating losses during 2018 and into the future.
The Company has received a waiver for
the measurement periods of December 31, 2017 and March 31, 2018 associated with its Revolver and Notes. Management has evaluated
its ability to continue as a going concern for the next twelve months from the issuance of these December 31, 2017, financial
statements and determined the Company will meet its covenants as of June 30, 2018 and on a go forward basis in anticipation of
production returning to normal levels after the effects of the fire and increased production based on planned operating activities.
The actual results of timing, amount, and payment of potential future commitments, liquidity, and management’s plan in regard
to continue to operate as a going concern could differ from those estimates and assumptions used.
The Company continues to evaluate additional
acquisitions and intends to finance any such acquisitions using a combination of debt and equity to be contributed by its members.
However, there can be no guarantee that financing will be available on acceptable terms.
Note 2 – Summary of Significant
Accounting Policies
Accounting policies used by the Company
reflect industry practices and conform to accounting principles generally accepted in the United States of America. The significant
accounting policies are briefly discussed below.
Cash and Cash Equivalents
Cash and cash equivalents have been generally
invested in money market accounts, certificates of deposits and other cash equivalents with maturities of three months or less.
Such investments are deemed to be cash equivalents for purposes of the financial statements. The carrying amount of cash equivalents
approximate fair value because of the short maturity and high credit quality of these investments. At times, the Company may have
cash and cash equivalent balances more than federal insured amounts within their accounts.
The Company continually monitors its position
with and the credit quality of the financial institutions in which it invests.
Accounts Receivable
Trade
The Company’s accounts receivable
trade include i) revenue receivables primarily comprised of oil and natural gas revenues from producing activities from other
large well-known exploration and production companies and recorded on a net basis to its interest; and ii) receivables from individuals
who own working interests in the properties that the Company operates which are subject to joint operating agreements. For receivables
from joint interest owners, the Company typically has the ability to withhold future revenue disbursements to recover non-payment
of joint interest billings.
The Company grants credit to all qualified
customers, which potentially subjects the Company to credit risk resulting from, among other factors, adverse changes in the oil,
natural gas, and natural gas liquids production in which the Company operates and the financial condition of its customers. The
Company continuously monitors collections and payments from its customers and maintains an allowance for doubtful accounts based
upon any specific customer collection issues that it has identified. At December 31, 2017, the Company had not identified any
collection issues related to its oil and gas operations and therefore no allowance for doubtful accounts was provided for.
Other
Accounts receivable other is comprised
of an insurance receivable for the loss of property as a result of wildfires in December 2017. The Company filed claims with its
insurance provider and was in receipt of partial funds associated with the claims after December 31, 2017. Therefore, the Company
has determined the receivable is collectible and included in accounts receivable other.
Due From Related Parties
Due from related parties is comprised
of amounts due to the Company from Scott Price, the owner of Mirada Petroleum, Inc. See Note 11.
Prepaid Expense and Deposits
The Company’s prepaid expense and
deposit account is comprised of prepaid insurance, the current portion of unamortized Revolver issuance costs and a deposit associated
with a potential acquisition. The remaining unamortized Revolver issuance costs is within other long-term assets. As of December
31, 2017, the total unamortized Revolver issuance costs is $602,000, of which $117,000 is included in prepaid expense and deposits
and $485,000 is in other long-term assets on the balance sheet.
Oil, Natural Gas, and Natural Gas Liquids
Sales
Oil, natural gas, and natural gas liquids
revenues are recognized when production volumes are sold to a purchaser at a fixed or determinable price, delivery has occurred,
title has transferred, and collectability is reasonably assured. Natural gas revenues are recognized based on the Company’s
net working revenue interest. Net deliveries more than entitled amounts are recorded as a liability, while net deliveries lower
than entitled amounts are recorded as a receivable.
The Company sells its oil, natural gas
liquids, natural gas production to various purchasers in the industry. The table below presents purchasers that account for 10%
or more of total oil, natural gas, and natural gas liquids sales for the period from Inception through December 31, 2017. While
there are limited significant purchasers in the areas where the Company sells its production, demand for the Company’s products
remains high. Management does not believe that changing its primary purchasers or a loss of any other single purchaser would materially
impact the Company’s business.
The Company’s producing properties
are in California and the oil production is sold to various purchasers based on market index prices. Natural gas and natural gas
liquids are sold to one purchaser. For the period from Inception through December 31, 2017, all oil, natural gas and natural gas
liquids sales (in aggregate) were made to four well-known large purchasers in the area, as shown in table below. As of December
31, 2017, all accounts receivable trade is associated with Purchaser B and Purchaser D.
Purchaser
|
|
2017
|
|
Purchaser A
|
|
|
51
|
%
|
Purchaser B
|
|
|
19
|
%
|
Purchaser C
|
|
|
19
|
%
|
Purchaser D
|
|
|
11
|
%
|
Accounting for Oil and Gas Operations
The Company uses the full cost method
of accounting for oil and gas properties. Accordingly, all costs related to the acquisition, exploration and development of oil
and gas properties, including costs of undeveloped leasehold, dry holes and leasehold equipment, are capitalized. Overhead costs
incurred that are directly identified with acquisition, exploration and development activities undertaken by the Company for its
own account, and which are not related to production, general corporate overhead or similar activities, are also capitalized.
Unproved properties are excluded from
amortized capitalized costs until it is determined whether or not proved reserves can be assigned to such properties. The Company
assesses its unproved properties for impairment at least annually. Significant unproved properties are assessed individually.
From Inception through December 31, 2017, the Company did not recognize an unproved property impairment.
Capitalized costs are depleted by an equivalent
unit-of-production method, converting gas to oil at the ratio of six thousand cubic feet of natural gas to one barrel of oil.
Depletion is calculated using capitalized costs, including estimated asset retirement costs, plus estimated future expenditures
(based on current costs) to be incurred in developing proved reserves, net of estimated salvage values.
No gain or loss is recognized upon disposal
of oil and gas properties unless such disposal significantly alters the relationship between capitalized costs and proved reserves.
All costs related to production activities, including work-over costs incurred solely to maintain or increase levels of production
from an existing completion interval, are charged to expense as incurred.
The Company performs a ceiling test on
a quarterly basis. The full cost ceiling test is a limitation on capitalized costs prescribed by SEC Regulation S-X Rule 4-10.
The ceiling test is not a fair value-based measurement, rather it is a standardized mathematical calculation. The ceiling test
provides that capitalized costs less related accumulated depletion and deferred income taxes may not exceed the sum of (1) the
present value of future net revenue from estimated production of proved oil and gas reserves using the unweighted arithmetic average
of the first-day-of-the month price for the previous twelve month period, excluding the future cash outflows associated with settling
asset retirement obligations that have been accrued on the balance sheet, at a discount factor of 10%; plus (2) the cost of properties
not being amortized, if any; plus (3) the lower of cost or estimated fair value of unproved properties included in the costs being
amortized, if any; less (4) income tax effects related to differences in the book and tax basis of oil and gas properties. Should
the net capitalized costs exceed the sum of the components noted above, a ceiling test write-down or impairment would be recognized
to the extent of the excess capitalized costs. Such impairments are permanent and cannot be recovered in future periods even if
the sum of the components noted above exceeds capitalized costs in future periods.
From Inception through December 31, 2017,
the Company did not recognize a ceiling test impairment. Future declines in oil and natural gas prices could result in impairments
of the Company’s oil and gas properties in future periods. The effect of price declines will impact the ceiling test value
until such time commodity prices stabilize or improve. Impairments are a non-cash charge and accordingly would not affect cash
flows but would adversely affect the Company’s results of operations and members’ equity.
We capitalize interest in accordance with
Financial Accounting Standards Board (“FASB”) ASC 932-835-25, Extractive Activities-Oil and Gas, Interest. Therefore,
interest is capitalized for any unusually significant investments in unproved properties or major development projects not currently
being depleted. We capitalize the portion of general and administrative costs that is attributable to our acquisition, exploration
and development activities.
Oil and Gas Reserves
Oil and gas reserves represent theoretical
quantities of crude oil, natural gas, and natural gas liquids (“NGL”) which geological and engineering data demonstrate
with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions.
There are numerous uncertainties inherent in estimating oil and gas reserves and their values, including many factors beyond the
Company’s control. Accordingly, reserve estimates and the projected economic value of the Company’s properties will
differ from the actual future quantities of oil and gas ultimately recovered and the corresponding value associated with the recovery
of these reserves.
Other Property and Equipment
Other property and equipment are recorded
at cost or fair value upon acquisition. Depreciation of other property and equipment is calculated over one to 27.5 years using
the straight-line method.
Long-Lived Assets
The Company reviews its long-lived assets
other than oil and gas properties for impairment whenever events or changes in circumstances indicate that the carrying amount
of the asset may not be recovered. The Company looks primarily to the estimated undiscounted future cash flows in its assessment
of whether long-lived assets have been impaired. During the period ended December 31, 2017, the Company did not recognize any
long-lived asset impairment.
Asset Retirement Obligations
The Company’s asset retirement obligations
(“ARO”) relate to future costs associated with the plugging and abandonment of oil and gas wells, removal of equipment
and facilities from leased acreage and returning such land to its original condition. The fair value of a liability for an ARO
is recorded in the period in which it is incurred or assumed, and the cost of such liability is recorded as an increase in the
carrying amount of the related long-lived asset by the same amount. The liability is accreted each period and the capitalized
cost is depleted on a units-of-production basis as part of the full cost pool. Revisions to estimated ARO result in adjustments
to the related capitalized asset and corresponding liability. During the period from Inception through December 31, 2017, the
Company acquired assets associated with the CRC Acquisition and Mirada Acquisition that resulted in an assumption of ARO liability
of $2.7 million.
The estimated ARO liability is based on
estimated economic lives, estimates as to the cost to abandon the wells in the future, and federal and state regulatory requirements.
The liability is discounted using a credit-adjusted risk-free rate estimated at the time the liability is incurred or increased
from a reassessment of expected cash flows and assumptions inherent in the estimation of the liability. Revisions to the liability
could occur due to changes in estimated abandonment costs or well economic lives, or if federal or state regulators enact new
requirements regarding the abandonment of wells. ARO is valued utilizing Level 3 fair value measurement inputs (Note 7).
The following table is a reconciliation
of the non-current portion of ARO (in thousands):
|
|
For the Period from Inception through December 31,
|
|
|
|
2017
|
|
|
|
|
|
Balance at beginning of period
|
|
$
|
-
|
|
Accretion expense
|
|
|
192
|
|
Additions from acquisitions during period
|
|
|
2,712
|
|
|
|
|
|
|
Less: ARO recognized as a current liability
|
|
|
(384
|
)
|
Balance at end of period
|
|
$
|
2,520
|
|
Lease Operating and Gathering and Transportation
Lease operating and gathering and transportation
expenses are costs incurred to bring oil and natural gas out of the ground and to market, together with costs incurred to maintain
the Company’s producing properties. Costs include maintenance, repairs and workover expenses related to the Company’s
oil and natural gas properties.
Production and Property Taxes
Production and property taxes consist
of severance and ad valorem taxes and are paid on oil and natural gas produced based on a percentage of market prices or at fixed
rates established by federal, state or local taxing authorities.
Financial Instruments
The Company’s financial instruments
include cash and cash equivalents, accounts receivables, accounts payables and accrued liabilities, due from related parties and
due to related parties, commodity derivative instruments and notes payable. The carrying value of cash and cash equivalents, accounts
receivables, accounts payables and accrued liabilities are representative of their fair value, due to the short maturity of these
instruments. The Company’s commodity derivative instruments are recorded at fair value, as discussed below and in Note 8.
The Revolver approximated fair value with a variable interest rate, which is representative of the Company’s credit adjusted
borrowing rate plus London Inter-Bank Offered Rate (“LIBOR”). As of December 31, 2017, the Revolver had an effective
interest rate of 6.56%.
Commodity Derivative Instruments
The Company enters into commodity derivative
contracts to manage its exposure to oil and natural gas price volatility with an objective to reduce its exposure to downward
price fluctuations. Commodity derivative contracts may take the form of futures contracts, swaps, collars or options. The Company
has elected not to designate its derivatives as cash flow hedges. All derivatives are initially and subsequently measured at estimated
fair value and recorded as assets or liabilities on the balance sheet and the changes in fair value are recognized as gains or
losses in revenues in the statement of operations.
Income Taxes
The Company has elected to be treated
as a partnership for income tax purposes. Accordingly, taxable income and losses are reported on the income tax returns of the
Company’s members and no provision for income taxes has been recorded on the accompanying financial statements. The Company
follows the guidance in Accounting Standards Codification (“ASC”) 740, Income Taxes. Interest and penalties associated
with tax positions are recorded in the period assessed as general and administrative expenses. The Company’s tax returns
are subject to examination by tax authorities through the current period for state and federal tax reporting purposes.
Pursuant to the Bipartisan Budget Act
of 2015 (the “Act”), as of January 1, 2018, the Act allows the adjustment resulting from IRS audits of partnerships
to be assessed at the partnership level.
Use of Estimates in the Preparation
of the Financial Statements
The preparation of financial statements
in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions
that affect the reported amounts of assets, liabilities and expenses and disclosure of contingent assets and liabilities. Significant
items subject to such estimates and assumptions include the carrying value of oil and gas properties, estimate of proved oil and
gas reserve volumes and the related depletion and present value of estimated future net cash flows and the ceiling test applied
to capitalized oil and gas properties, determining the amounts recorded for fair value of commodity derivative instruments, fair
value of assets acquired qualifying as business combination or asset acquisition, fair value of Class B issuance, assessment of
liquidity and our ability to continue as a going concern, asset retirement obligations, and accrued liabilities and revenues.
Recently Issued Accounting Pronouncements
In May 2014, the Financial Accounting
Standards Board (“FASB”) issued Accounting Standard Update (“ASU”) No. 2014-09,
Revenue from Contracts
with Customers
(“ASU 2014-09”). The objective of ASU 2014-09 is to clarify the principles for recognizing revenue
and to develop a common revenue standard for generally accepted accounting principles in the United States (“GAAP”)
and International Financial Reporting Standards. The FASB subsequently issued ASU 2015-14, ASU 2016-08, ASU 2016-10, ASU 2016-12
and ASU 2016-20, which deferred the effective date of ASU 2014-09 and provided additional implementation guidance. These ASUs
are effective for the Company for fiscal years, beginning after December 15, 2018. The standards permit retrospective application
using either of the following methodologies: (i) restatement of each prior reporting period presented (the “full retrospective
approach”) or (ii) recognition of a cumulative-effect adjustment as of the date of the initial application (the “modified
retrospective approach”). The Company plans to adopt these ASUs effective January 1, 2018, using the modified retrospective
approach. The Company is in the process of assessing its contracts with customers and evaluating the effect of adopting these
standards on its financial statements, accounting policies, internal controls and disclosures. The adoption is not expected to
have a significant impact on the Company’s results of operations or cash flows, however, the Company is currently evaluating
the proper classification of certain pipeline gathering, transportation and gas processing agreements to determine whether reclassifications
to total revenues and expenses will be necessary under the new standards.
In February 2016, the FASB issued ASU
No. 2016-02,
Leases
(“ASU 2016-02”). The objective of this ASU, as amended, is to increase transparency and
comparability among organizations by recognizing lease assets and liabilities on the balance sheet and disclosing key information
about leasing arrangements. ASU 2016-02 is effective for fiscal years beginning after December 15, 2019 and should be applied
using a modified retrospective approach. Early adoption is permitted. The Company is currently evaluating the impact on its financial
statements of adopting ASU 2016-02.
In June 2016, the FASB issued ASU 2016-13,
Financial Instruments-Credit Losses
(Topic 326):
Measurement of Credit Losses on Financial Instruments
. These amendments
change the measurement of credit losses for most financial assets and certain other instruments that are not measured at fair
value through results of operations. The amendments in this update affect investments in loans, investments in notes securities,
trade receivables, net investments in leases, off balance sheet credit exposures, reinsurance receivables, and any other financial
assets not excluded from the scope that have the contractual right to receive cash. The amendments replace the incurred loss impairment
methodology in current GAAP with a methodology that reflects expected credit losses and requires consideration of a broader range
of reasonable and supportable information to inform credit loss estimates. ASU 2016-13 is effective for fiscal years, beginning
after December 15, 2020. The Company is currently evaluating the impact on its financial statements of adopting ASU 2016-13.
Recently Adopted Accounting Pronouncement
In January 2017, the FASB issued ASU 2017-01,
Clarifying the Definition of a Business
, which clarifies the definition of “a business” to assist entities
with evaluating whether transactions should be accounted for as acquisitions or disposals of assets or businesses. The standard
introduces a screen for determining when assets acquired are not a business and clarifies that a business must include, at a minimum,
an input and a substantive process that contribute to an output to be considered a business. The Company elected to adopt this
pronouncement effective February 15, 2017.
Note 3 – Acquisitions
Consideration to fund both the CRC Acquisition
and Mirada Acquisition was provided by aggregate contributions from Yorktown and Prudential of $22.0 million in unit purchases,
$10.0 million drawn from the Revolver, related party, and $10.0 million funding from the Notes, related party, discussed in Note
5.
CRC Acquisition
On February 15, 2017, the Company acquired
oil and gas assets in the Ventura Basin of California from California Resources Petroleum Corporation and California Resources
Production Corporation for $34.0 million, subject to normal purchase adjustments, with an effective date of November 1, 2016 (the
“CRC Acquisition”).
The assets acquired consist of oil and
gas leases and the associated mineral interests, oil and gas wells, a field office building and associated land, vehicles and
other miscellaneous equipment. The Company also acquired various contracts. The Company, utilizing the assistance of third-party
valuation specialists, considered various factors in its estimate of fair value of the acquired assets including (i) reserves,
(ii) production rates, (iii) future operating and development costs, (iv) future commodity prices, including price differentials,
(v) future cash flows, (vi) working conditions and expected lives of vehicles and equipment, and (vii) real estate market conditions.
The Company determined that substantially
all of the fair value of the assets acquired related to the proved oil and gas assets and, as such the CRC Acquisition does not
meet the definition of a business. Therefore, the Company has accounted for the transaction as an asset acquisition and has allocated
the purchase price based on the relative fair value of the assets acquired.
In determining the relative fair value,
the fair value of the production assets was determined using the income approach using Level 3 inputs according the ASC 820,
Fair
Value
, hierarchy. The fair value of the other assets was determined using the market approach using Level 3 inputs. The determination
of the fair value of the oil and gas and other property and equipment acquired, and accounts payable and accrued liabilities assumed
required significant judgement, including estimates relating to the production assets and the other assets acquired. The Company
assumed $2.3 million in ARO and $1.3 million in assumed liabilities in connection with the CRC Acquisition. Below is the detail
of the assets acquired (in thousands):
Identifiable assets acquired:
|
|
|
|
Assets:
|
|
|
|
Proved oil and gas properties
|
|
|
32,151
|
|
Unproved oil and gas properties
|
|
|
1,495
|
|
Other property and equipment
|
|
|
143
|
|
Total identified assets
|
|
$
|
33,789
|
|
Mirada Acquisition
On February 15, 2017, the Company closed
the purchase of oil, natural gas, and natural gas liquids assets in the Ventura Basin of California from Mirada Petroleum, Inc.
for $4.5 million, subject to certain adjustments, with an effective date of January 1, 2017 (the “Mirada Acquisition”).
The assets acquired consist of oil and
gas leases and the associated mineral interests, oil and gas wells, vehicles and equipment. The Company also acquired various
contracts. The Company, utilizing the assistance of third-party valuation specialists, considered various factors in its estimate
of fair value of the acquired assets including (i) reserves, (ii) production rates, (iii) future operating and development costs,
(iv) future commodity prices, including price differentials, (v) future cash flows, and (vi) working conditions and expected lives
of vehicles and equipment.
The Company determined that substantially
all of the fair value of the assets acquired related to proved oil and gas properties and, as such the Mirada Acquisition does
not meet the definition of a business. Therefore, the Company has accounted for the transaction as an asset acquisition and has
allocated the purchase price based on the relative fair value of the assets acquired.
In determining the relative fair value,
the fair value of the production assets was determined using the income approach using Level 3 inputs according the ASC 820,
Fair
Value
, hierarchy. The fair value of the other assets was determined using the market approach using Level 3 inputs. The determination
of the fair value of the oil and gas and other property and equipment, net acquired, and accounts payable and accrued liability
assumed required significant judgement, including estimates relating to the production assets and the other assets acquired. The
Company assumed $468,000 in ARO and $19,000 in assumed liabilities in connection with the Mirada Acquisition. Below is the detail
of the assets acquired and liabilities assumed (in thousands):
Identifiable assets acquired:
|
|
|
|
Assets:
|
|
|
|
Proved oil and gas properties
|
|
|
4,536
|
|
Furniture and fixtures, computer hardware and software,
vehicles and other equipment
|
|
|
158
|
|
|
|
|
|
|
Total identified assets
|
|
$
|
4,694
|
|
Transaction costs
The Company incurred transaction costs
related to the CRC Acquisition and the Mirada Acquisition in the amount of $706,000 and $282,000, respectively. As these acquisitions
were determined to be asset acquisitions, these transaction costs were capitalized to oil and gas properties- proved, net on the
balance sheet.
Additional Acquisitions
The Company purchased additional interests
in oil and gas assets totaling approximately $1.1 million, subject to normal purchase price adjustments. These purchases are recorded
as asset acquisition.
Note 4 – Property and Equipment
Total property and equipment consists of the following (in
thousands):
|
|
As of December 31,
|
|
|
|
2017
|
|
Oil and gas properties, full cost method of accounting:
|
|
|
|
Proved oil and gas properties
|
|
$
|
43,131
|
|
Unproved properties not subject to depletion
|
|
|
1,495
|
|
Accumulated depreciation, depletion, and amortization
|
|
|
(1,168
|
)
|
Net oil and gas properties
|
|
|
43,458
|
|
|
|
|
|
|
Furniture and fixtures, computer hardware and software, vehicles and other equipment
|
|
|
952
|
|
Accumulated depreciation and amortization
|
|
|
(136
|
)
|
Other property and equipment, net
|
|
|
816
|
|
|
|
|
|
|
Total property and equipment, net
|
|
$
|
44,274
|
|
During the period from Inception through
December 31, 2017, the Company did not have any expiring leasehold costs which were reclassified into proved property.
The Company capitalized no overhead applicable
to acquisition, development and exploration activities for the period from Inception through December 31, 2017.
Depletion related to oil and gas properties
for the period from Inception through December 31, 2017 was approximately $1.2 million or $5.30 per BOE. Depreciation and amortization
related to furniture and fixtures, computer hardware and software, vehicle and other equipment for the period from Inception through
December 31, 2017 was approximately $136,000.
Note 5 – Notes Payable, Related Parties
The table below details the notes payable
outstanding for the Company as of December 31, 2017 (in thousands):
Revolver, related party, due February 15, 2022
|
|
$
|
11,000
|
|
Notes, related party, due February 15, 2024
|
|
$
|
10,000
|
|
Total gross notes payable
|
|
|
21,000
|
|
Less: Deferred Notes costs
|
|
|
(171
|
)
|
Less: Notes discount
|
|
|
(971
|
)
|
Total net notes payable
|
|
$
|
19,858
|
|
Revolver
On February 15, 2017, the Company entered
into an agreement with Prudential Capital Energy Partners, L.P. for the issuance and sale of up to $25.0 million due February
15, 2022. The Company may elect to incur interest at either i) 5.0% plus the London interbank offered rate (“LIBOR”)
or ii) 4.00% plus Prime Rate (which is defined as the interest rate published daily by JPMorgan Chase Bank, N.A.). As of December
31, 2017, the Company’s effective borrowing rate on the Revolver was 6.35%. In addition, the Revolver includes a 0.50% unused
available line fee as well as an annual administrative fee of $75,000, payable on February 15 each year.
The maximum principal amount available
under the Revolver is based upon the borrowing base attributable to the Company’s proved oil and gas reserves which is to
be determined at least semi-annually. As of December 31, 2017, the Revolver has a borrowing base of $15.0 million, of which $11.0
million is outstanding.
The Company incurred fees directly associated
with the issuance of the Revolver and amortizes these fees over the life of the Revolver. The current portion of these fees are
included in prepaid expense and deposits and the long-term portion is included in other long-term assets for a combined value
of $602,000. From Inception through December 31, 2017, the Company incurred $102,000 amortization associated with these fees.
The Revolver is secured by all of the
assets of the Company. The Revolver requires the Company, as of January 1 and July of each year, to hedge its anticipated production
at such time for year one, two and three at a rate of 75%, 65% and 50%, respectively. The Company may make principal payments
in minimum installments of $500,000. Distributions to equity members are generally restricted.
The Revolver agreement requires the Company
to maintain certain financial and non-financial covenants which include the following ratios: total leverage ratio, senior leverage
ratio, interest coverage ratio, current ratio, and other qualitative covenants as defined in the Revolver agreement. As of December
31, 2017, the Company was in breach of its covenants; however, the Company obtained a waiver for the December 31, 2017, and March
31, 2018 covenants.
Notes
On February 15, 2017, the Company entered
into an agreement with Prudential for the issuance and sale of $10.0 million of unsecured Notes due February 15, 2024, bearing
interest of 12% per annum.
The Company incurred total issuance costs
of $200,000 in connection with the Notes. These costs are recorded as a discount to the Notes and amortized over the life of the
notes. During the period from Inception through December 31, 2017, the Company amortized $29,000 to interest expense in the statement
of operations associated with the Notes.
Prudential received an additional 1,425
Class A unit, representing 5% of total Aggregate Value outstanding, for the issuance of the Notes. The Company valued this unit
issuance based on the relative fair value by valuing the units at $1,000 and aggregating the amount with the outstanding Notes
of $10.0 million. The Company then allocated the non-cash value of the units of approximately $1.25 million which was recorded
as a discount to the Notes. As of December 31, 2017, the Company had an outstanding discount of $971,000, which is presented net
with the Notes within non-current liabilities on the Balance Sheet.
The Notes requires the Company, as of
January 1 and July of each year, to hedge its anticipated production at such time for year one, two and three at a rate of 67.5%,
58.5% and 45%, respectively.
Prepayment of the Notes is currently not
available. After February 15, 2019, prepayment is allowed at 100%, subject to a 3.0% fee of outstanding principal. Prepayment
is not subject to such fee after February 17, 2020. Distributions to equity members are generally restricted.
The Note agreement requires the Company
to maintain certain financial and non-financial covenants which include the following ratios: total leverage ratio, senior leverage
ratio, interest coverage ratio, asset coverage ratio, current ratio, and other qualitative covenants as defined in the Revolver
agreement. As of December 31, 2017, the Company was in breach of financial covenants; however, the Company obtained a waiver for
the December 31, 2017, and March 31, 2018 financial covenants.
Interest Expense
From Inception through December 31, 2017,
the Company incurred interest expense of approximately $2.0 million which approximately $130,000 was through amortization of the
deferred financing costs. From Inception through December 31, 2017, the Company amortized $276,000 of notes payable discount associated
with the Notes, into interest expense.
Note 6 – Accounts Payable and Accrued Liabilities
Accounts payable and accrued liabilities
at December 31, 2017 consist of the following (in thousands):
Accounts payable
|
|
$
|
2,256
|
|
Accrued environmental liability
|
|
|
732
|
|
Accrued liabilities
|
|
|
569
|
|
Accrued drilling costs
|
|
|
541
|
|
Accrued ad valorem taxes
|
|
|
286
|
|
Gathering and transportation payables
|
|
|
223
|
|
Accrued lease operating costs
|
|
|
200
|
|
Production taxes payable
|
|
|
140
|
|
Accrued audit and tax fees
|
|
|
110
|
|
Other
|
|
|
72
|
|
Total accounts payable and accrued liabilities
|
|
$
|
5,129
|
|
Note 7 – Fair Value Measurements
Authoritative guidance defines fair value
as the price that would be received to sell an asset or paid to transfer a liability (an exit price) in an orderly transaction
between market participants at the measurement date. The guidance establishes a hierarchy for inputs used in measuring fair value
that maximizes the use of observable inputs and minimizes the use of unobservable inputs by requiring that the most observable
inputs be used when available. Observable inputs are inputs that market participants would use in pricing the asset or liability
developed based on market data obtained from sources independent of the Company. Unobservable inputs are inputs that reflect the
Company’s assumptions of what market participants would use in pricing the asset or liability developed based on the best
information available in the circumstances. The hierarchy is broken down into three levels based on the reliability of the inputs
as follows:
|
Level
1:
|
Quoted
prices are available in active markets for identical assets or liabilities;
|
|
|
|
|
Level 2:
|
Quoted prices in
active markets for similar assets or liabilities that are observable for the asset or liability; or
|
|
|
|
|
Level 3:
|
Unobservable pricing
inputs that are generally less observable from objective sources, such as discounted cash flow models or valuations.
|
Financial assets and liabilities are classified
based on the lowest level of input that is significant to the fair value measurement. The Company’s policy is to recognize
transfers in and/or out of fair value hierarchy as of the end of the reporting period for which the event or change in circumstances
caused the transfer. The Company has consistently applied the valuation techniques discussed below throughout the period presented.
The following table presents the Company’s
financial assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2017 by level within
the fair value hierarchy (in thousands):
|
|
Fair Value Measurements Using
|
|
|
|
Level 1
|
|
|
Level 2
|
|
|
Level 3
|
|
|
Total
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivatives - current
|
|
$
|
-
|
|
|
$
|
916
|
|
|
$
|
-
|
|
|
$
|
916
|
|
Commodity derivatives – non-current
|
|
$
|
-
|
|
|
$
|
809
|
|
|
$
|
-
|
|
|
$
|
809
|
|
As of December 31, 2017, the Company’s
commodity derivative financial instruments are comprised of natural gas and oil swap and collar agreements. The fair values of
these agreements are determined under an income valuation technique. Swaps are valued using the income technique. Collars are
valued using the option model. The valuation model requires a variety of inputs, including contractual terms, published forward
prices, volatilities for options and discount rates, as appropriate. The Company’s estimates of the fair value of derivatives
include consideration of the counterparty’s credit worthiness, the Company’s credit worthiness and the time value
of money. The consideration of these factors results in an estimated exit-price for each derivative asset or liability under a
market place participant’s view. All the significant inputs are observable, either directly or indirectly; therefore, the
Company’s derivative instruments are included within the Level 2 fair value hierarchy. The counterparty for all the Company’s
outstanding commodity derivative financial instruments as of December 31, 2017 is BP Energy Company (“BPEC”).
Assets and Liabilities Measured and
Recorded at Fair Value on a Non-Recurring Basis
The fair value of each of the following
assets and liabilities measured and recorded at fair value on a non-recurring basis are based on unobservable pricing inputs and
therefore, are included within the Level 3 fair value hierarchy.
Asset Retirement Obligation
The fair value of the Company’s
asset retirement obligation liability is calculated at the point of inception by taking into account, the cost of abandoning oil
and gas wells of approximately $45,000, which is based on the Company’s and/or industry’s historical experience for
similar work, or estimates from independent third-parties; the economic lives of its properties between 1-49 years, which are
based on estimates from reserve engineers ; the inflation rate of 2.03%; and the credit adjusted risk-free rate of 8.09%, which
takes into account the Company’s credit risk and the time value of money. Given the unobservable nature of the inputs, the
initial measurement of the asset retirement obligation liability is deemed to use Level 3 inputs (see note 2). During the period
from Inception through December 31, 2017, the Company recorded asset retirement obligations for additions of approximately $2.7
million. The Company uses the income valuation technique to estimate the fair value of asset retirement obligations using the
amounts and timing of expected future dismantlement costs, credit-adjusted risk-free rates and time value of money.
Debt Discount
The fair value of the Company’s
debt discount from the 1,425 additional Class units issued in connection with the Notes as a discount of $1.3 million, a Level
3 fair value assessment, was based on the relative fair value of Class A Units. Class A Units were issued contemporaneously at
$1,000 per Class A Units.
Class B Units
The Company issued Class B units to Carbon
as part of the February transactions and for entering into the Carbon California LLC Agreement. The fair value of the Class B
units of approximately $1.9 million, a Level 3 fair value measurement, was estimated by the Company utilizing the assistance of
third-party valuation specialists. The fair value was based upon enterprise values derived from inputs including estimated future
production rates, future commodity prices including price differentials as of the date of closing, future operating and development
costs and comparable market participants.
Note 8 – Commodity Derivatives
The Company entered into commodity-based
derivative contracts in April 2017, September 2017, and November 2017 to manage exposures to commodity price on certain of its
oil and natural gas production. The Company does not hold or issue derivative financial instruments for speculative or trading
purposes.
Pursuant to the terms of the Company’s
Revolver and Notes agreements, the Company has entered into derivative agreements to hedge certain of its oil and natural gas
production for 2017 through 2020. As of December 31, 2017, these derivative agreements consisted of the following:
|
|
Natural
Gas Swaps
|
|
|
Natural
Gas Collars
|
|
|
Oil
Swaps
|
|
|
|
|
|
|
Weighted
|
|
|
|
|
|
Weighted
|
|
|
|
|
|
Weighted
|
|
|
|
|
|
|
Average
|
|
|
|
|
|
Average
Price
|
|
|
|
|
|
Average
|
|
Year
|
|
|
MMBtu
|
|
|
|
Price
(a)
|
|
|
|
MMBtu
|
|
|
|
Range (a)
|
|
|
|
Bbl
|
|
|
|
Price
(b)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2018
|
|
|
360,000
|
|
|
$
|
3.03
|
|
|
|
-
|
|
|
|
-
|
|
|
|
149,247
|
|
|
$
|
53.12
|
|
2019
|
|
|
-
|
|
|
|
-
|
|
|
|
360,000
|
|
|
|
$2.60-$3.03
|
|
|
|
139,797
|
|
|
$
|
51.96
|
|
2020
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
73,147
|
|
|
$
|
50.12
|
|
(a)
|
NYMEX
Henry Hub Natural Gas futures contract for the respective period.
|
(b)
|
NYMEX Light Sweet
Crude West Texas Intermediate futures contract for the respective period.
|
For its swap instruments, the Company
receives a fixed price for the hedged commodity and pays a floating price to the counterparty. The fixed-price payment and the
floating-price payment are netted, resulting in a net amount due to or from the counterparty. Costless collars are designed to
establish floor and ceiling prices on anticipated future oil and gas production. The ceiling establishes a maximum price that
the Company will receive for the volumes under contract, while the floor establishes a minimum price.
The following table summarizes the fair
value of the derivatives recorded in the balance sheet. These derivative instruments are not designated as cash flow hedging instruments
for accounting purposes (in thousands):
|
|
As of December 31,
|
|
|
|
2017
|
|
Commodity derivative contracts:
|
|
|
|
Current liabilities
|
|
$
|
916
|
|
Non-current liabilities
|
|
$
|
809
|
|
The table below summarizes the commodity
realized and unrealized gains and losses related to the Company’s derivative instruments for the period from Inception through
December 31, 2017. These commodity realized and unrealized gains and losses are recorded and included in commodity derivative
loss in the accompanying statement of operations.
|
|
For period from Inception through December 31,
|
|
|
|
2017
|
|
Commodity derivative contracts:
|
|
|
|
Commodity derivative gain - realized
|
|
$
|
344
|
|
Commodity derivative loss - unrealized
|
|
|
(1,725
|
)
|
|
|
|
|
|
Total commodity derivative loss
|
|
$
|
1,381
|
|
Commodity derivative loss, inclusive of
net of unrealized loss, is included in cash flows from operating activities in the statement of cash flows.
The counterparty in the Company’s
derivative instruments is BPEC. The Company has entered into an International Swaps and Derivatives Association (“ISDA”)
Master Agreement with BPEC that establishes standard terms for the derivative contracts and an inter-creditor agreement with Prudential
and BPEC whereby any credit exposure related to the derivative contracts entered into by the Company and BPEC is secured by the
collateral and backed by the guarantees supporting the credit facility.
The Company nets its derivative instrument
fair value amounts executed with its counterparty pursuant to an ISDA master agreement, which provides for the net settlement
over the term of the contracts and in the event of default or termination of the contracts. The Company’s derivative instruments
are recorded as liabilities in the balance sheet as of December 31, 2017.
|
|
|
|
|
|
|
|
Net
|
|
|
|
Gross
|
|
|
|
|
|
Recognized
|
|
|
|
Recognized
|
|
|
Gross
|
|
|
Fair Value
|
|
|
|
Assets/
|
|
|
Amounts
|
|
|
Assets/
|
|
Balance Sheet Classification
|
|
Liabilities
|
|
|
Offset
|
|
|
Liabilities
|
|
Commodity derivative assets:
|
|
|
|
|
|
|
|
|
|
Current assets
|
|
$
|
72
|
|
|
$
|
(72
|
)
|
|
$
|
-
|
|
Other long-term assets
|
|
|
66
|
|
|
|
(66
|
)
|
|
|
-
|
|
Total derivative assets
|
|
$
|
138
|
|
|
$
|
(138
|
)
|
|
$
|
-
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivative liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Current liability
|
|
$
|
(988
|
)
|
|
$
|
72
|
|
|
$
|
(916
|
)
|
Non-current liabilities
|
|
|
(875
|
)
|
|
|
66
|
|
|
|
(809
|
)
|
Total derivative liabilities
|
|
$
|
(1,863
|
)
|
|
$
|
138
|
|
|
$
|
(1,725
|
)
|
Due to the volatility of oil and natural
gas prices, the estimated fair values of the Company’s derivatives are subject to large fluctuations from period to period.
Note 9 – Commitments and Contingencies
Natural gas processing agreement
The Company has entered into an initial
five-year gas processing agreement. The Company has an option to extend the term of the agreement by another five years. The related
demand charges for volume commitments over the remaining term of the agreement at December 31, 2017 are approximately $1.8 million
per year. The Company will pay a processing fee of $2.50 per MCF for the term of the agreement, with a minimum annual volume commitment
of 720,000 MCF.
Operating leases
The Company leases, under an operating
lease arrangement, approximately 9,500 square feet of administrative office space in Santa Paula, which expires in 2020. For the
years ended December 31, 2017, the Company incurred rental expenses of $19,000. The Company has minimum lease payments for its
office space and equipment of approximately $114,000 for 2018, $117,000 for 2019, and $121,000 for 2020.
Environmental
In connection with the CRC Acquisition,
the Company identified environmental defects of $1.0 million and recoded an accrued liability associated with the mitigation of
such defects. As of December 31, 2017, the balance of the environmental liability was $732,000 recognized in accounts payables
and accrued liabilities.
Litigation
In November 2017, the Ventura County Superior
Court directed the county to nullify its June 23, 2016 approval of certain projects and prepare a revised Subsequent Environmental
Impact Report (SEIR) as a conclusion of Court Case No.: 56-2016-00484423-CU -WM-VTA Citizens for Responsible Oil and Gas (CFROG)
v. County of Ventura. The Company is estimating the settlement to be approximately $175,000.
Note 10 – Members’ Equity
On February 15, 2017, the Company issued
22,000 Class A Units to Yorktown and Prudential for an aggregate cash consideration of $22.0 million, split equal between Yorktown
and Prudential. In addition to the Class A Units issued, the Company also issued 1,425 of Class A Units to Prudential (5% Aggregate
Sharing units) as part of the issuance of Notes.
Class A Units
As of December 31, 2017, the Company had
23,425 of Class A Units outstanding. The Company issued 22,000 shares, split equally between Yorktown and Prudential, to raise
capital for the acquisition of proved properties, unproved properties, and working capital. Holders of Class A Units, i) can designate
persons to serve on the board of directors, ii) have the right to vote equal to the number of outstanding Class A Units it holds
on each and every matter submitted to the members for approval, and iii) shall be required to make capital contributions to the
Company as capital calls which are unanimously approved by the majority of the members of the class. Failure to make the required
capital contributions results in the member receiving a status of defaulting member. The units are recorded as members’
contributions in the statement of members’ equity.
Prudential received an additional 1,425
Class A Units, representing 5% of total Aggregate Sharing outstanding, for the issuance of the Notes. The Company valued this
unit issuance based on the relative fair value by valuing the units at $1,000 each and aggregating the amount with the outstanding
Notes of $10.0 million. The Company then allocated the non-cash relative fair value of the units of approximately $1.25 million
which was recorded as a discount to the Notes. As of December 31, 2017, the Company had an outstanding unamortized discount of
$971,000, which is presented net with the Notes within non-current liabilities on the balance sheet.
In connection with the Carbon California
Company, LLC Agreement, Carbon issued to Yorktown a warrant to purchase shares of Carbon’s common stock at an exercise price
dictated by the warrant agreement (the “California Warrant”). The exercise price for the California Warrant is payable
exclusively with Class A Units of the Company held by Yorktown. The California Warrant has a term of seven years. On February
1, 2018, Yorktown exercised the California Warrant (see Note 13).
Class B units
As of December 31, 2017, the Company had
5,077 Class B units issued and outstanding, resulting in an aggregate Sharing Percentage of 17.8%. The Class B units are considered
profit interests. Carbon holds all outstanding Class B units. Class B unit holders have the right to i) vote equal to the number
of Class B units they hold; and ii) participate in distributions in proportion to their Class B Sharing Percentage. Holders of
Class B units are not required to make capital contributions.
Distributions
The Company’s board of directors
will determine, by unanimous approval, any distributions. Distributions are first allocated to Class B members and then to Class
A members in proportion to their Sharing Percentage, as defined below. Distributions are generally restricted by the Revolver
and Notes agreements.
Sharing Percentage
The sharing percentage of each member
shall equal the aggregate number of units held by such member divided by the aggregate number of units then outstanding (“Sharing
Percentage”), as defined in the Carbon California Company, LLC Agreement, as amended, and is applicable to each class of
units.
The term “Aggregate Sharing Percentage”
refers to the aggregated sharing percentage when taking into consideration both Class A and Class B ownership.
Drag-along Rights
In a qualifying event for a sale of the
Company or member(s) holding more than 60% of the Class A Units prepare to transfer all of their interests, may elect to execute
a “Drag-Along” sale which the parameters and specifics are disclosed in the limited liability company agreement the
members who are affiliates of the members of the board of directors.
Board Composition
Old Ironsides and Yorktown designate two
persons each to serve on the board of directors. Carbon designates one person. Yorktown will continue to designate two persons
to the Carbon California board of directors until such time as they are no longer a majority owner in Carbon.
Note 11 – Related Parties
During the period ended December 31, 2017,
the Company was engaged in the following transactions with related parties:
As of December 31, 2017, Prudential held
a Class A Sharing Percentage of 53.041% and an Aggregate Sharing Percentage of 43.6%. Prudential is the original issuer and current
holder of the Revolver and Notes. As of December 31, 2017, approximately $170,000 in interest expense is due Prudential and included
in due to related parties on the balance sheet.
On February 15, 2017, as part of entry
into the Carbon California LLC Agreement and the associated transactions, Carbon received 5,077 Class B units, which represent
100% of the class.
Carbon California Operating Company (“CCOC”)
is a wholly-owned subsidiary of Carbon and the operator of the Company through an operating agreement. The operating agreement
includes direct reimbursements and direct allocations made under the agreement. As of December 31, 2017, approximately $300,000
is due Carbon and included in due to related parties on the balance sheet.
Scott Price is the owner of Mirada Petroleum,
Inc., the counterparty to the Mirada Acquisition, and is currently an employee of Carbon California Operating Company. Mr. Price
holds revenue interests in certain wells the Company operates and owns. The Company has an outstanding receivable from Mirada
Petroleum, Inc. in the amount of $113,000 included in due from related parties on the balance sheet as of December 31, 2017.
Management services
On February 15, 2017, the Company entered
into a management service agreement with Carbon whereby Carbon provides general management and administrative services to Carbon
California. Carbon receives $600,000 annually, payable in four equal quarterly installments. The Company reimburses Carbon for
all management related expenses such as travel, required third-party geological and/or accounting consulting, and other necessary
expenses incurred by Carbon in the normal course of managing the Company.
The Company incurred approximately $1.0
million in management reimbursements for the period Inception through December 31, 2017, of which $525,000 was recorded as management
reimbursements, related party in the statement of operations. A one-time reimbursement of $500,000 in connection with the CRC
Acquisition and Mirada Acquisition was capitalized as an acquisition cost in proved oil and gas properties. There were no outstanding
management reimbursements unpaid as of December 31, 2017.
Note 12 – Supplemental Cash
Flow Disclosure
Supplemental cash flow disclosures for
period from Inception through December 31, 2017 are presented below (in thousands):
Cash paid during the period for:
|
|
|
|
Interest expense
|
|
$
|
1,463
|
|
Non-cash transactions:
|
|
|
|
|
Increase in asset retirement obligations
|
|
$
|
2,711
|
|
Accounts payable and accrued liabilities assumed in oil and gas properties
|
|
$
|
1,540
|
|
Members’ equity units issued for Notes
|
|
$
|
1,247
|
|
Other property and equipment financed
|
|
$
|
92
|
|
Note 13 – Subsequent Events
Acquisition
On October 20
th
, 2017, the
Company entered into an agreement to purchase certain oil and gas assets in the Ventura Basin of California. This acquisition
is expected to close in the second quarter of 2018. The Company plans to fund the acquisition from a combination of contributed
capital from equity members and debt.
California Warrant conversion
On February 1, 2018, Yorktown exercised
the California Warrant. As a result of the warrant exercise, Carbon holds 11,000 Class A Units of the Company and all of the Class
B units, resulting in an aggregate Sharing Percentage of 56.403%.
The Company evaluated activities from
December 31, 2017, to the date of the independent registered public accountants report, the date these financial statements were
available for issuance, and their are no additional events requiring recognition or disclosure.
INDEPENDENT AUDITORS’ REPORT
The Board of Directors
Carbon Natural Gas Company
Denver, Colorado
We have audited the accompanying statements
of revenues and direct operating expenses of certain properties acquired by Carbon Appalachian Company, LLC, an affiliate of Carbon
Natural Gas Company, from Cabot Oil & Gas Corporation (the “Acquired Operating Assets”) for the period from January
1, 2017 through September 29, 2017, and for the year ended December 31, 2016, and the related notes to the statements of revenues
and direct operating expenses.
MANAGEMENT’S RESPONSIBILITY FOR THE FINANCIAL STATEMENTS
Management is responsible for the preparation
and fair presentation of these financial statements in accordance with accounting principles generally accepted in the United
States of America; this includes the design, implementation, and maintenance of internal control relevant to the preparation and
fair presentation of the financial statements that are free from material misstatement, whether due to fraud or error.
AUDITORS’ RESPONSIBILITY
Our responsibility is to express an opinion
on the financial statements based on our audits. We conducted our audits in accordance with auditing standards generally accepted
in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about
whether the financial statements are free from material misstatement.
An audit involves performing procedures
to obtain audit evidence about the amounts and disclosures in the financial statements. The procedures selected depend on the
auditors’ judgment, including the assessment of the risks of material misstatement of the financial statements, whether
due to fraud or error. In making those risk assessments, the auditor considers internal control relevant to the entity’s
preparation and fair presentation of the financial statements in order to design audit procedures that are appropriate in the
circumstances, but not for the purpose of expressing an opinion on the effectiveness of the entity’s internal control. Accordingly,
we express no such opinion. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness
of significant accounting estimates made by management, as well as evaluating the overall presentation of the financial statements.
We believe that the audit evidence we
have obtained is sufficient and appropriate to provide a basis for our audit opinion.
OPINION
In our opinion, the financial statements
referred to above present fairly, in all material respects, the revenues and direct operating expenses of the Acquired Operating
Assets for the period from January 1, 2017 through September 29, 2017, and for the year ended December 31, 2016, in accordance
with accounting principles generally accepted in the United States of America.
EMPHASIS OF MATTER
As described in Note 1,
the accompanying statements of revenues and direct operating expenses were prepared for the purpose of complying with rules and
regulations of the Securities and Exchange Commission and are not intended to be a complete presentation of the results of operations
of the Acquisition Operating Assets. Our opinion is not modified with respect to this matter.
/s/
EKS&H LLLP
|
|
EKS&H LLLP
|
|
April 16, 2018
Denver, Colorado
CABOT ACQUISITION
PROPERTIES
STATEMENTS OF REVENUES AND DIRECT OPERATING
EXPENSES
|
|
Period from
January 1, 2017
through
September 29,
|
|
|
Year Ended
December 31,
|
|
(In thousands)
|
|
2017
|
|
|
2016
|
|
|
|
|
|
|
|
|
Revenues:
|
|
|
|
|
|
|
Natural gas sales
|
|
$
|
27,042
|
|
|
$
|
33,056
|
|
Oil sales
|
|
|
454
|
|
|
|
279
|
|
Marketing gas sales
|
|
|
12,070
|
|
|
|
12,593
|
|
Storage and other
|
|
|
363
|
|
|
|
6
|
|
Total revenues
|
|
|
39,929
|
|
|
|
45,934
|
|
Direct operating expenses:
|
|
|
|
|
|
|
|
|
Lease operating
|
|
|
8,982
|
|
|
|
13,272
|
|
Transportation, gathering, and compression
|
|
|
9,179
|
|
|
|
12,685
|
|
Marketing gas purchases
|
|
|
10,389
|
|
|
|
9,733
|
|
Production and property taxes
|
|
|
4,183
|
|
|
|
5,461
|
|
Total direct operating expenses
|
|
|
32,733
|
|
|
|
41,151
|
|
Revenues in excess of direct operating expenses
|
|
$
|
7,196
|
|
|
$
|
4,783
|
|
See accompanying notes to the Statements
of Revenues and Direct Operating Expenses.
CABOT ACQUISITION
PROPERTIES
NOTES TO STATEMENTS OF REVENUES AND
DIRECT OPERATING EXPENSES
Note 1 — Organization
Acquisition
On June 30, 2017, Carbon Appalachian Company,
LLC (“Company”, “we” or “us”), an affiliate of Carbon Natural Gas Company, entered into a
definitive purchase and sale agreement (“PSA”) to acquire approximately 701,700 net acres of oil and natural gas mineral
interests, 3,000 natural gas wells and 3,100 miles of natural gas pipelines and related compression facilities located predominantly
in West Virginia. We refer to the acquisition of these properties as the “Cabot acquisition” and the properties acquired
in the Cabot acquisition as the “Cabot properties.” The purchase price was $41.3 million, subject to customary post-closing
purchase price adjustments, and closed on September 29, 2017 with effective dates of April 1, 2017 for the oil and gas assets
acquired and September 29, 2017 for the corporate entity acquired.
Basis of Presentation
The accompanying historical statements
include revenues and direct operating expenses associated with the Cabot properties. The statements were prepared by us based
on carved out financial information and data from historical accounting records relating to the Cabot properties. These statements
are not intended to be a complete presentation of the results of operations of the Cabot properties as they do not include general
and administrative expenses, interest income or expense, depreciation, depletion, and amortization, any provision for income tax
expenses and other income and expense items not directly associated with revenues from oil and gas activities. Historical financial
statements reflecting financial position, results of operations, and cash flows required by accounting principles generally accepted
in the United States (“GAAP”) are not presented as such information is not readily available on an individual property
basis and not meaningful to the acquired properties. Accordingly, the accompanying statements are presented in lieu of the financial
statements required under Rule 8–04 of Securities and Exchange Commission’s Regulation S–X.
Certain indirect expenses, as further
described in Note 2, were not allocated to the Cabot properties and have been excluded from the accompanying statements. Any attempt
to allocate these expenses would require significant judgmental allocations, which would be arbitrary and would likely not be
indicative of the performance of the properties on a stand-alone basis.
Note 2 — Summary of Significant Accounting Policies
Use of Estimates in the Preparation of Statements of Revenues
and Direct Operating Expenses
The preparation of the statements of revenues
and direct operating expenses in conformity with GAAP requires management to make estimates and assumptions that affect the reported
amounts of revenues and direct operating expenses during the respective reporting periods. Actual results may differ from the
estimates and assumptions used in the preparation of the statements of revenues and direct operating expenses.
Oil and Gas Reserves
Oil and gas reserves represent theoretical
quantities of crude oil and natural gas which geological and engineering data demonstrate with reasonable certainty to be recoverable
in future years from known reservoirs under existing economic and operating conditions. There are numerous uncertainties inherent
in estimating oil and gas reserves and their values, including many factors beyond the Company’s control. Accordingly, reserve
estimates and the projected economic value of the Cabot properties will differ from the actual future quantities of oil and gas
ultimately recovered and the corresponding value associated with the recovery of these reserves.
Revenue
The Company recognizes revenues for sales
and services when persuasive evidence of an arrangement exists, when custody is transferred, or services are rendered, fees are
fixed or determinable and collectability is reasonably assured.
Natural Gas and Oil Sales
Oil and natural gas revenues are recognized
when production volumes are sold to a purchaser at a fixed or determinable price, delivery has occurred, title has transferred,
and collectability is reasonably assured. Natural gas and oil revenues are recognized based on the Company’s net revenue
interest.
Marketing Gas Sales
The Company purchases and sells natural
gas from third party producers under various gas purchase and sale agreements including percent-of-proceeds arrangements. Under
percent-of-proceeds arrangements, the Company will remit to the producers either an agreed-upon percentage of the actual proceeds
that we receive from our sales of natural gas or an agreed-upon percentage of the proceeds based on index related prices for the
natural gas, regardless of the actual amount of the sales proceeds we receive. The Company’s revenues under percent-of-proceeds/index
arrangements generally correlates with the price of natural gas.
CABOT ACQUISITION
PROPERTIES
NOTES TO STATEMENTS OF REVENUES AND
DIRECT OPERATING EXPENSES—(Continued)
Storage
Under fee-based arrangements, the Company
receives a fee for storing natural gas. The revenues earned are directly related to the volume of natural gas that flows through
the Company’s systems and are not directly dependent on commodity prices.
Lease Operating Expenses
Lease operating expenses include lifting
costs, well repair expenses, surface repair expenses, well workover costs, plug and abandonment costs, and other field expenses.
Lease operating expenses also include expenses directly associated with support personnel, support services, equipment and facilities
directly related to oil and natural gas production activities.
Transportation, Gathering, and Compression Expenses
Transportation, gathering, and compression
expenses primarily consist of direct costs associated with operating the in-field gathering systems, natural gas transportation
pipelines, and compressor stations. Transportation, gathering, and compression expense includes compressor maintenance and fuel
expense, pipeline repairs and maintenance expense, and other midstream and pipeline expenses.
Production and Property Taxes
Production and property taxes consist
of severance and ad valorem taxes and are paid on oil and natural gas produced based on a percentage of market prices or at fixed
rates established by federal, state or local taxing authorities.
Contingencies and Commitments
The Company is party to certain long-term
transportation contracts that were entered into to ensure the transport for certain gas production to purchasers. Firm transportation
volumes and the related demand charges for the remaining term of these contracts at September 29, 2017 are summarized in the table
below.
Period
|
|
Dekatherms per day
|
|
Demand Charges
|
Sep 2017 – May 2027
|
|
29,900
|
|
$0.21
|
Sep 2017 – May 2022
|
|
19,441
|
|
$0.56
|
Legal and Environmental
Pursuant to the terms of the PSA, the
Company believes that there are no claims, litigation or disputes pending as of the Effective Date, or any matters arising in
connection with indemnifications, and the parties to the PSA are not aware of any legal, environmental or other commitments or
contingencies not previously disclosed that would have a material adverse effect on the accompanying statements.
Excluded Expenses
The Cabot properties were part of a much
larger enterprise prior to the date of the sale. Indirect general and administrative expenses, income taxes, interest expense,
and other indirect expenses were not allocated to the Cabot properties and have been excluded from the accompanying statements.
In addition, any allocation of such indirect expenses may not be indicative of costs which would have been incurred by the Cabot
properties on a stand-alone basis. Also, depreciation, depletion, and amortization have been excluded from the accompanying statements
of revenues and direct expenses as such amounts would not be indicative of the depletion calculated on the Cabot properties on
a stand-alone basis.
Note 3 — Subsequent Events
The Company has evaluated subsequent events
through the date of the independent auditors’ report, the date the accompanying statements were available to be issued.
There were no material subsequent events that required recognition or additional disclosure in the accompanying statements.
CABOT ACQUISITION
PROPERTIES
NOTES TO STATEMENTS OF REVENUES AND
DIRECT OPERATING EXPENSES—(Continued)
Note 4 — Supplemental Financial Data - Oil and Gas
Producing Activities (Unaudited)
Estimated Proved Oil and Gas Reserves
The Company’s estimates of its net
proved, net proved developed, and net proved undeveloped oil and natural gas reserves and changes in its net proved oil and natural
gas reserves for the period from December 31, 2015 through September 29, 2017 are presented in the table below. As no prior year
reserve studies were available for the Cabot properties, prior year reserve balances were derived from an internal reserve study
dated September 29, 2017 that was prepared by us, adjusting for actual production during the intervening periods. As such, the
December 31, 2015 and December 31, 2016 reserves estimates do not include the impact, if any, of timing, pricing, and revisions
of prior estimates. Estimates of proved reserves are inherently imprecise and are continually subject to revision based on production
history, results of additional exploration and development, price changes and other factors.
Reserve information for the Cabot properties
was prepared in accordance with guidelines established by the Securities and Exchange Commission. Proved oil and natural gas reserves
are those quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable
certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions,
operating methods, and government regulation before the time at which contracts providing the right to operate expire, unless
evidence indicates that renewal is reasonably certain. Proved oil and natural gas reserves were calculated based on the prices
for oil and gas during the 12-month period before the reporting date, determined as the unweighted arithmetic average of the first
day of the month price for each month within such period, adjusted for basis differentials, hydrocarbon quality and contract terms.
A summary of the Company’s changes
in quantities of proved oil and natural gas reserves for the period from December 31, 2015 through September 29, 2017 are as follows:
|
|
Oil
|
|
|
Natural Gas
|
|
|
Total
|
|
|
|
(MBbls
1
)
|
|
|
(MMcf
2
)
|
|
|
(MMcfe
3
)
|
|
Proved reserves:
|
|
|
|
|
|
|
|
|
|
Balance December 31, 2015
|
|
|
130
|
|
|
|
306,489
|
|
|
|
307,270
|
|
Production
|
|
|
(7
|
)
|
|
|
(14,061
|
)
|
|
|
(14,103
|
)
|
Balance December 31, 2016
|
|
|
123
|
|
|
|
292,428
|
|
|
|
293,167
|
|
Production
|
|
|
(10
|
)
|
|
|
(10,252
|
)
|
|
|
(10,312
|
)
|
Balance September 29, 2017
|
|
|
113
|
|
|
|
282,176
|
|
|
|
282,855
|
|
Proved developed reserves
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2016
|
|
|
123
|
|
|
|
292,428
|
|
|
|
293,167
|
|
September 29, 2017
|
|
|
113
|
|
|
|
282,176
|
|
|
|
282,855
|
|
1
|
“MBbl” refers to one thousand barrels
of crude oil or other liquid hydrocarbons.
|
2
|
“MMcf” refers to one million cubic
feet of natural gas.
|
3
|
“MMcfe”
refers to one million cubic feet equivalent determined using the ratio of six Mcf of natural gas to one bbl of crude oil,
condensate, or natural gas liquids.
|
CABOT ACQUISITION PROPERTIES
NOTES TO STATEMENTS OF REVENUES AND
DIRECT OPERATING EXPENSES—(Continued)
Standardized Measure of Discounted
Future Net Cash Flows
As noted above, proved oil and natural
gas reserves were calculated based on the prices for oil and gas during the 12-month period before the reporting date, determined
as the unweighted arithmetic average of the first day of the month price for each month within such period, adjusted for basis
differentials, hydrocarbon quality and contract terms. This average price is also used in calculating the aggregate amount and
changes in future cash inflows related to the standardized measure of discounted future cash flows. As these reserves are prepared
on a historical and standalone basis, these reserves may not be indicative of the reserves presented in future filings. Future
production costs consist of costs incurred producing and transporting oil and gas reserves to third party customers, which include
lease operating expenses, production and property taxes, and transportation, gathering and compression expenses (described in
Note 2). Future development costs consist of costs related to drilling and completing wells, plugging of wells, removal of facilities
and equipment, and site restoration. Future production and future development costs are calculated by estimating the expenditures
to be incurred in producing and developing the proved reserves at the end of each year, based on year-end costs and assuming continuation
of existing economic conditions. As described in Note 1, these statements do not include income tax expense therefore income tax
estimates were omitted from the Standardized Measure of Discounted Future Net Cash Flows calculation. All cash flow amounts are
discounted at 10%.
Changes in the demand for oil and natural
gas, inflation, and other factors make such estimates inherently imprecise and subject to substantial revision. This table should
not be construed to be an estimate of the current market value of the Company’s proved reserves. Management does not rely
upon the information that follows in making investment decisions.
The following summary sets forth the future
net cash flows relating to proved oil and natural gas reserves of the Cabot properties based on the standardized measure described
earlier. The disclosure excludes the impact, if any, of timing, pricing or revisions of prior estimates. As discussed above, December
31, 2016 amounts were based on the reserves as of September 30, 2017, actual sales and production costs during the intervening
period and no adjustments were made to the annual discount rate:
|
|
September 29,
2017
|
|
|
December 31,
2016
|
|
|
|
|
|
|
|
|
Future cash inflows
|
|
$
|
849,073
|
|
|
$
|
876,569
|
|
Future production costs
|
|
|
(488,914
|
)
|
|
|
(511,258
|
)
|
Future development costs
|
|
|
-
|
|
|
|
-
|
|
|
|
|
|
|
|
|
|
|
Future net cash flows
|
|
|
360,159
|
|
|
|
365,311
|
|
10% annual discount
|
|
|
(230,550
|
)
|
|
|
(242,801
|
)
|
|
|
|
|
|
|
|
|
|
Standardized measure of discounted
future net cash flows
|
|
$
|
129,609
|
|
|
$
|
122,510
|
|
Changes in the Standardized Measure of Discounted Future
Net Cash Flows Relating to Proved Oil and Gas Reserves
An analysis of the changes in the standardized
measure of discounted future net cash flows for the nine months ended September 29, 2017 and the year ended December 31, 2016
are as follows and excludes the impact, if any, of timing, pricing or revisions of prior estimates as discussed earlier:
|
|
Period
from
January 1,
2017
through
September 29,
|
|
|
Year ended
December 31,
|
|
(In thousands)
|
|
2017
|
|
|
2016
|
|
|
|
|
|
|
|
|
Standardized measure of discounted future
net cash flows, beginning of period
|
|
$
|
122,510
|
|
|
$
|
113,115
|
|
Sales of oil and gas, net of production costs and taxes
|
|
|
(5,152
|
)
|
|
|
(1,917
|
)
|
Accretion of discount
|
|
|
12,251
|
|
|
|
11,312
|
|
|
|
|
|
|
|
|
|
|
Standardized measure of discounted
future net cash flows, end of period
|
|
$
|
129,609
|
|
|
$
|
122,510
|
|
INDEPENDENT AUDITORS’ REPORT
The Board of Directors
Carbon Natural Gas Company
Denver, Colorado
We have audited the accompanying statements
of revenues and direct operating expenses of certain properties that Carbon California Company, LLC, an affiliate of Carbon Natural
Gas Company, plans to purchase from Seneca Resources Corporation (the “Pending Acquisition Operating Assets”) for
the years ended December 31, 2017 and 2016, and the related notes to the statements of revenues and direct operating expenses.
MANAGEMENT’S RESPONSIBILITY FOR THE FINANCIAL STATEMENTS
Management is responsible for the preparation
and fair presentation of these financial statements in accordance with accounting principles generally accepted in the United
States of America; this includes the design, implementation, and maintenance of internal control relevant to the preparation and
fair presentation of the financial statements that are free from material misstatement, whether due to fraud or error.
AUDITORS’ RESPONSIBILITY
Our responsibility is to express an opinion
on the financial statements based on our audits. We conducted our audits in accordance with auditing standards generally accepted
in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about
whether the financial statements are free from material misstatement.
An audit involves performing procedures
to obtain audit evidence about the amounts and disclosures in the financial statements. The procedures selected depend on the
auditors’ judgment, including the assessment of the risks of material misstatement of the financial statements, whether
due to fraud or error. In making those risk assessments, the auditor considers internal control relevant to the entity’s
preparation and fair presentation of the financial statements in order to design audit procedures that are appropriate in the
circumstances, but not for the purpose of expressing an opinion on the effectiveness of the entity’s internal control. Accordingly,
we express no such opinion. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness
of significant accounting estimates made by management, as well as evaluating the overall presentation of the financial statements.
We believe that the audit evidence we
have obtained is sufficient and appropriate to provide a basis for our audit opinion.
OPINION
In our opinion, the financial statements
referred to above present fairly, in all material respects, the revenues and direct operating expenses of the Pending Acquisition
Operating Assets for the years ended December 31, 2017 and 2016, in accordance with accounting principles generally accepted in
the United States of America.
EMPHASIS OF MATTER
As described in Note 1, the accompanying
statements of revenues and direct operating expenses were prepared for the purpose of complying with rules and regulations of
the Securities and Exchange Commission and are not intended to be a complete presentation of the results of operations of the
Pending Acquisition Operating Assets. Our opinion is not modified with respect to this matter.
/s/
EKS&H LLLP
|
|
EKS&H LLLP
|
|
April 16, 2018
Denver, Colorado
SENECA ACQUISITION
PROPERTIES
STATEMENTS OF REVENUES AND DIRECT OPERATING
EXPENSES
(Unaudited)
|
|
Three
Months Ended
March 31,
|
|
(In thousands)
|
|
2018
|
|
|
2017
|
|
|
|
|
|
Revenues
|
|
|
|
|
|
|
Natural
gas sales
|
|
$
|
127
|
|
|
$
|
22
|
|
Oil sales
|
|
|
4,036
|
|
|
|
3,423
|
|
Total revenues
|
|
|
4,163
|
|
|
|
3,445
|
|
Direct operating expenses
|
|
|
|
|
|
|
|
|
Lease operating
|
|
|
1,227
|
|
|
|
1,412
|
|
Production and property
taxes
|
|
|
135
|
|
|
|
106
|
|
Total direct operating
expenses
|
|
|
1,362
|
|
|
|
1,518
|
|
|
|
|
|
|
|
|
|
|
Revenues in excess of direct operating expenses
|
|
$
|
2,801
|
|
|
$
|
1,927
|
|
See accompanying notes to the Statements
of Revenues and Direct Operating Expenses.
SENECA ACQUISITION
PROPERTIES
NOTES TO STATEMENTS OF REVENUES AND
DIRECT OPERATING EXPENSES
(Unaudited)
Note 1 — Organization and Basis of Presentation
Acquisition
On October 20, 2017, Carbon California
Company, LLC (“Company”, “we” or “us”), an affiliate of Carbon Natural Gas Company, entered
into a definitive purchase and sale agreement (“PSA”) to acquire 310 operated and one non-operated oil and gas leases
covering approximately 5,500 acres, and fee interests in and to certain lands, situated in the Ventura Basin in California. We
refer to the acquisition of these properties as the “Seneca acquisition” and the properties acquired in the Seneca
acquisition as the “Seneca properties.” The purchase price was $43.0 million, subject to customary post-closing purchase
price adjustments, and closed on May 1, 2018 with an effective date of October 1, 2017.
Basis of Presentation
The accompanying historical statements
include revenues from oil and natural gas and direct operating expenses associated with the Seneca properties. The statements
were prepared by us based on carved out financial information and data from historical accounting records relating to the Seneca
properties. These statements are not intended to be a complete presentation of the results of operations of the Seneca properties
as they do not include general and administrative expenses, interest income or expense, depreciation, depletion, and amortization,
any provision for income tax expenses and other income and expense items not directly associated with revenues from oil and gas.
Historical financial statements reflecting financial position, results of operations, and cash flows required by accounting principles
generally accepted in the United States (“GAAP”) are not presented as such information is not readily available on
an individual property basis and not meaningful to the acquired properties. Accordingly, the accompanying statements are presented
in lieu of the financial statements required under Rule 8–04 of Securities and Exchange Commission’s Regulation S–X.
Certain indirect expenses, as further
described in Note 2, were not allocated to the Seneca properties and have been excluded from the accompanying statements. Any
attempt to allocate these expenses would require significant judgmental allocations, which would be arbitrary and would likely
not be indicative of the performance of the properties on a stand-alone basis.
Note 2 — Summary of Significant Accounting Policies
Use of Estimates in the Preparation of Statements of Revenues
and Direct Operating Expenses
The preparation of the statements of revenues
and direct operating expenses in conformity with GAAP requires management to make estimates and assumptions that affect the reported
amounts of operating revenues and direct operating expenses during the respective reporting periods. Actual results may differ
from the estimates and assumptions used in the preparation of the statements of operating revenues and direct operating expenses.
Revenue Recognition
Oil and natural gas revenues are recognized
when production volumes are sold to a purchaser at a fixed or determinable price, delivery has occurred, title has transferred,
and collectability is reasonably assured. Natural gas and oil revenues are recognized based on the Company’s net revenue
interest.
Lease Operating Expense
Lease operating expenses include lifting
costs, well repair expenses, surface repair expenses, well workover costs, plug and abandonment costs, and other field expenses.
Lease operating expenses also include expenses directly associated with support personnel, support services, equipment and facilities
directly related to oil and natural gas production activities.
Production and Property Taxes
Production and property taxes consist
of severance and ad valorem taxes and are paid on oil and natural gas produced based on a percentage of market prices or at fixed
rates established by federal, state or local taxing authorities.
Contingencies
Pursuant to the terms of the PSA, the
Company believes that there are no claims, litigation or disputes pending as of the Effective Date, or any matters arising in
connection with indemnifications, and the parties to the PSA are not aware of any legal, environmental or other commitments or
contingencies that would have a material adverse effect on the accompanying statements.
SENECA ACQUISITION PROPERTIES
NOTES TO STATEMENTS OF REVENUES AND
DIRECT OPERATING EXPENSES—(Continued)
(Unaudited)
Excluded Expenses
The Seneca properties were part of a much
larger enterprise prior to the date of the sale. Indirect general and administrative expenses, income taxes, interest expense,
asset retirement obligations and related expenses, and other indirect expenses were not allocated to the Seneca properties and
have been excluded from the accompanying statements. In addition, any allocation of such indirect expenses may not be indicative
of costs which would have been incurred by the Seneca properties on a stand-alone basis. Also, depreciation, depletion, and amortization
have been excluded from the accompanying statements of revenues and direct expenses as such amounts would not be indicative of
the depletion calculated on the Seneca properties on a stand-alone basis.
Note 3 — Subsequent Events
The Company has evaluated subsequent events
through the date that the accompanying statements were available to be issued. There were no material subsequent events that required
recognition or additional disclosure in the accompanying statements.
SENECA ACQUISITION
PROPERTIES
STATEMENTS OF REVENUES AND DIRECT OPERATING
EXPENSES
|
|
Year Ended
December 31,
|
|
(In thousands)
|
|
2017
|
|
|
2016
|
|
|
|
|
|
Revenues
|
|
|
|
|
|
|
Natural gas sales
|
|
$
|
130
|
|
|
$
|
768
|
|
Oil sales
|
|
|
13,143
|
|
|
|
12,046
|
|
Total revenues
|
|
|
13,273
|
|
|
|
12,814
|
|
Direct operating expenses
|
|
|
|
|
|
|
|
|
Lease operating
|
|
|
5,690
|
|
|
|
7,132
|
|
Production and property taxes
|
|
|
516
|
|
|
|
588
|
|
Total direct operating expenses
|
|
|
6,206
|
|
|
|
7,720
|
|
|
|
|
|
|
|
|
|
|
Revenues in excess of direct operating expenses
|
|
$
|
7,067
|
|
|
$
|
5,094
|
|
See accompanying notes to the Statements
of Revenues and Direct Operating Expenses.
SENECA ACQUISITION
PROPERTIES
NOTES TO STATEMENTS OF REVENUES AND
DIRECT OPERATING EXPENSES
Note 1 — Organization and Basis of Presentation
Acquisition
On October 20, 2017, Carbon California
Company, LLC (“Company”, “we” or “us”), an affiliate of Carbon Natural Gas Company, entered
into a definitive purchase and sale agreement (“PSA”) to acquire 315 operated and one non-operated oil and gas leases
covering approximately 5,729 acres, and fee interests in and to certain lands, situated in the Ventura Basin in California. We
refer to the acquisition of these properties as the “Seneca acquisition” and the properties acquired in the Seneca
acquisition as the “Seneca properties.” The purchase price is expected to be $43.0 million, subject to customary post-closing
purchase price adjustments, and is expected to close in May 2018 with an effective date of October 1, 2017.
Basis of Presentation
The accompanying historical statements
include revenues from oil and natural gas and direct operating expenses associated with the Seneca properties. The statements
were prepared by us based on carved out financial information and data from historical accounting records relating to the Seneca
properties. These statements are not intended to be a complete presentation of the results of operations of the Seneca properties
as they do not include general and administrative expenses, interest income or expense, depreciation, depletion, and amortization,
any provision for income tax expenses and other income and expense items not directly associated with revenues from oil and gas.
Historical financial statements reflecting financial position, results of operations, and cash flows required by accounting principles
generally accepted in the United States (“GAAP”) are not presented as such information is not readily available on
an individual property basis and not meaningful to the acquired properties. Accordingly, the accompanying statements are presented
in lieu of the financial statements required under Rule 8–04 of Securities and Exchange Commission’s Regulation S–X.
Certain indirect expenses, as further
described in Note 2, were not allocated to the Seneca properties and have been excluded from the accompanying statements. Any
attempt to allocate these expenses would require significant judgmental allocations, which would be arbitrary and would likely
not be indicative of the performance of the properties on a stand-alone basis.
Note 2 — Summary of Significant Accounting Policies
Use of Estimates in the Preparation of Statements of Revenues
and Direct Operating Expenses
The preparation of the statements of revenues
and direct operating expenses in conformity with GAAP requires management to make estimates and assumptions that affect the reported
amounts of operating revenues and direct operating expenses during the respective reporting periods. Actual results may differ
from the estimates and assumptions used in the preparation of the statements of operating revenues and direct operating expenses.
Oil and Gas Reserves
Oil and gas reserves represent theoretical
quantities of crude oil, natural gas, and natural gas liquids (“NGL”) which geological and engineering data demonstrate
with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions.
There are numerous uncertainties inherent in estimating oil, natural gas, and NGL reserves and their values, including many factors
beyond the Company’s control. Accordingly, reserve estimates and the projected economic value of the Seneca properties will
differ from the actual future quantities of oil, natural gas, and NGL ultimately recovered and the corresponding value associated
with the recovery of these reserves.
Revenue Recognition
Oil and natural gas revenues are recognized
when production volumes are sold to a purchaser at a fixed or determinable price, delivery has occurred, title has transferred,
and collectability is reasonably assured. Natural gas and oil revenues are recognized based on the Company’s net revenue
interest.
Lease Operating Expense
Lease operating expenses include lifting
costs, well repair expenses, surface repair expenses, well workover costs, plug and abandonment costs, and other field expenses.
Lease operating expenses also include expenses directly associated with support personnel, support services, equipment and facilities
directly related to oil and natural gas production activities.
Production and Property Taxes
Production and property taxes consist
of severance and ad valorem taxes and are paid on oil and natural gas produced based on a percentage of market prices or at fixed
rates established by federal, state or local taxing authorities.
SENECA ACQUISITION PROPERTIES
NOTES TO STATEMENTS OF REVENUES AND
DIRECT OPERATING EXPENSES—(Continued)
Contingencies
Pursuant to the terms of the PSA, the
Company believes that there are no claims, litigation or disputes pending as of the Effective Date, or any matters arising in
connection with indemnifications, and the parties to the PSA are not aware of any legal, environmental or other commitments or
contingencies that would have a material adverse effect on the accompanying statements.
Excluded Expenses
The Seneca properties were part of a much
larger enterprise prior to the date of the sale. Indirect general and administrative expenses, income taxes, interest expense,
asset retirement obligations and related expenses, and other indirect expenses were not allocated to the Seneca properties and
have been excluded from the accompanying statements. In addition, any allocation of such indirect expenses may not be indicative
of costs which would have been incurred by the Seneca properties on a stand-alone basis. Also, depreciation, depletion, and amortization
have been excluded from the accompanying statements of revenues and direct expenses as such amounts would not be indicative of
the depletion calculated on the Seneca properties on a stand-alone basis.
Note 3 — Subsequent Events
The Company has evaluated subsequent events
through the date of the independent auditors’ report, the date the accompanying statements were available to be issued.
There were no material subsequent events that required recognition or additional disclosure in the accompanying statements.
Note 4 — Supplemental Financial Data - Oil and Gas
Producing Activities (Unaudited)
Estimated Proved Oil and Gas Reserves
The Company’s estimates of its net
proved, net proved developed, and net proved undeveloped oil, natural gas, and NGL reserves and changes in its net proved oil,
natural gas, and NGL reserves for the period from December 31, 2015 through December 31, 2017 are presented in the table below.
As no prior year reserve studies were available for the Seneca properties, prior year reserve balances were derived from an internal
reserve study dated December 31, 2017 that was prepared by us, adjusting for actual production during the intervening periods.
As such, the December 31, 2015 and December 31, 2016 reserves estimates do not include the impact, if any, of timing, pricing,
and revisions of prior estimates. Estimates of proved reserves are inherently imprecise and are continually subject to revision
based on production history, results of additional exploration and development, price changes and other factors.
Reserve information for the Seneca properties
was prepared in accordance with guidelines established by the Securities and Exchange Commission. Proved oil, natural gas, and
NGL reserves are those quantities of oil, natural gas, and NGL, which, by analysis of geoscience and engineering data, can be
estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under
existing economic conditions, operating methods, and government regulation before the time at which contracts providing the right
to operate expire, unless evidence indicates that renewal is reasonably certain. Proved oil, gas, and NGL reserves were calculated
based on the prices for oil and gas during the 12-month period before the reporting date, determined as the unweighted arithmetic
average of the first day of the month price for each month within such period, adjusted for basis differentials, hydrocarbon quality
and contract terms.
SENECA ACQUISITION PROPERTIES
NOTES TO STATEMENTS OF REVENUES AND
DIRECT OPERATING EXPENSES—(Continued)
A Summary of the Company’s changes
in quantities of proved oil, natural gas, and NGL reserves for the period from December 31, 2015 through December 31, 2017 are
as follows:
|
|
Oil
(MBbls
1
)
|
|
|
Natural
Gas (MMcf
2
)
|
|
|
NGL
(MBbls
1
)
|
|
|
Total
(MMcfe
3
)
|
|
Proved reserves:
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance December 31, 2015
|
|
|
12,159
|
|
|
|
24,750
|
|
|
|
1,894
|
|
|
|
109,059
|
|
Production
|
|
|
(302
|
)
|
|
|
(631
|
)
|
|
|
(39
|
)
|
|
|
(2,672
|
)
|
Balance December 31, 2016
|
|
|
11,857
|
|
|
|
24,119
|
|
|
|
1,855
|
|
|
|
106,387
|
|
Production
|
|
|
(259
|
)
|
|
|
(609
|
)
|
|
|
(33
|
)
|
|
|
(2,360
|
)
|
Balance December 31, 2017
|
|
|
11,598
|
|
|
|
23,510
|
|
|
|
1,822
|
|
|
|
104,027
|
|
Proved developed reserves
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2016
|
|
|
8,028
|
|
|
|
15,881
|
|
|
|
1,215
|
|
|
|
71,345
|
|
December 31, 2017
|
|
|
7,769
|
|
|
|
15,272
|
|
|
|
1,184
|
|
|
|
68,985
|
|
Proved undeveloped reserves
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2016
|
|
|
3,829
|
|
|
|
8,238
|
|
|
|
638
|
|
|
|
35,042
|
|
December 31, 2017
|
|
|
3,829
|
|
|
|
8,238
|
|
|
|
638
|
|
|
|
35,042
|
|
1
|
“MBbl” refers to one thousand barrels
of crude oil or other liquid hydrocarbons.
|
2
|
“MMcf” refers to one million cubic
feet of natural gas.
|
3
|
“MMcfe”
refers to one million cubic feet equivalent determined using the ratio of six Mcf of natural gas to one bbl of crude oil,
condensate, or natural gas liquids.
|
Standardized Measure of Discounted
Future Net Cash Flows
As noted above, proved oil, natural gas,
and NGL reserves were calculated based on the prices for oil and gas during the 12-month period before the reporting date, determined
as the unweighted arithmetic average of the first day of the month price for each month within such period, adjusted for basis
differentials, hydrocarbon quality and contract terms. This average price is also used in calculating the aggregate amount and
changes in future cash inflows related to the standardized measure of discounted future cash flows. As these reserves are prepared
on a historical and standalone basis, these reserves may not be indicative of the reserves presented in future filings. Future
production and development costs, which include costs related to plugging of wells, removal of facilities and equipment, and site
restoration, are calculated by estimating the expenditures to be incurred in producing and developing the proved reserves at the
end of each year, based on year-end costs and assuming continuation of existing economic conditions. As described in Note 1, these
statements do not include income tax expense therefore income tax estimates were omitted from the Standardized Measure of Discounted
Future Net Cash Flows calculation. All cash flow amounts are discounted at 10%.
Changes in the demand for oil, natural
gas, and NGLs, inflation, and other factors make such estimates inherently imprecise and subject to substantial revision. This
table should not be construed to be an estimate of the current market value of the Company’s proved reserves. Management
does not rely upon the information that follows in making investment decisions.
The following summary sets forth the future
net cash flows relating to proved oil, natural gas, and NGL reserves of the Seneca properties based on the standardized measure
described earlier. The disclosure excludes the impact, if any, of timing, pricing or revisions of prior estimates. As discussed
above, December 31, 2016 amounts were based on the reserves as of December 31, 2017, actual sales and production costs during
the intervening period and no adjustments were made to the annual discount rate:
|
|
December 31,
|
|
(In thousands)
|
|
2017
|
|
|
2016
|
|
|
|
|
|
|
|
|
Future cash inflows
|
|
$
|
722,934
|
|
|
$
|
736,207
|
|
Future production costs
|
|
|
(469,422
|
)
|
|
|
(475,628
|
)
|
Future development costs
|
|
|
(49,919
|
)
|
|
|
(49,939
|
)
|
|
|
|
|
|
|
|
|
|
Future net cash flows
|
|
|
203,593
|
|
|
|
210,640
|
|
10% annual discount
|
|
|
(107,358
|
)
|
|
|
(116,747
|
)
|
|
|
|
|
|
|
|
|
|
Standardized measure of discounted future net cash
flows
|
|
$
|
96,235
|
|
|
$
|
93,893
|
|
SENECA ACQUISITION PROPERTIES
NOTES TO STATEMENTS OF REVENUES AND
DIRECT OPERATING EXPENSES—(Continued)
Changes in the Standardized Measure of Discounted Future
Net Cash Flows Relating to Proved Oil and Gas Reserves
An analysis of the changes in the standardized
measure of discounted future net cash flows for the years ended December 31, 2017 and 2016 are as follows and excludes the impact,
if any, of timing, pricing or revisions of prior estimates as discussed earlier:
|
|
Year ended December 31,
|
|
(In thousands)
|
|
2017
|
|
|
2016
|
|
|
|
|
|
|
|
|
Standardized measure of discounted future net cash flows, beginning of year
|
|
$
|
93,893
|
|
|
$
|
89,743
|
|
Sales of oil and gas, net of production costs and production taxes
|
|
|
(7,067
|
)
|
|
|
(5,094
|
)
|
Previously estimated development costs incurred during the period
|
|
|
20
|
|
|
|
270
|
|
Accretion of discount
|
|
|
9,389
|
|
|
|
8,974
|
|
|
|
|
|
|
|
|
|
|
Standardized measure of discounted future net cash flows, end of year
|
|
$
|
96,235
|
|
|
$
|
93,893
|
|
APPENDIX
A
GLOSSARY OF OIL AND GAS TERMS
The following includes a description of
the meanings of some of the oil and natural gas industry terms used in this prospectus.
The
definitions of proved developed reserves, proved reserves, and proved undeveloped reserves have been abbreviated from the applicable
definitions contained in Rule 4-10(a) of Regulation S-X adopted by the SEC. The entire definitions of those terms can be
viewed on the SEC’s website at http://ww.sec.gov.
Bbl
means one stock tank barrel, or 42 U.S. gallons liquid volume, of crude oil or liquid hydrocarbons.
Bcf
means one billion cubic feet of natural gas.
Bcfe
means one billion cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one bbl of crude oil,
condensate, or natural gas liquids.
Boe
means one barrel of
oil equivalent, calculated by converting natural gas to oil equivalent barrels at a ratio of six Mcf of natural gas to one Bbl
of oil.
Btu
means a British Thermal Unit, or the amount of heat necessary to raise the temperature of one pound of water one degree
Fahrenheit.
Condensate
means liquid hydrocarbons associated with the production of a primarily natural gas reserve.
Dekatherm
means one million British Thermal Units.
Developed
acreage
means the number of acres which are allocated or held by producing wells or wells capable of production.
Development
wells
means a well drilled within the proved area of an oil or natural gas reservoir to the depth of a stratigraphic horizon
known to be productive.
Exploitation
means ordinarily considered to be a form of development within a known reservoir.
Exploratory
well
means a well drilled to find a new field or to find a new reservoir in a field previously found to be productive
of oil or natural gas in another reservoir. Generally, an exploratory well is any well that is not a development well or a service
well.
Field
means an area consisting of either a single reservoir or multiple reservoirs, all grouped on or related to the same individual
geological structural feature and/or stratigraphic condition.
Full
cost pool
means the full cost pool consisting of all costs associated with property acquisition, exploration, and development
activities for a company using the full cost method of accounting. Additionally, any internal costs that can be directly identified
with acquisition, exploration, and development activities are included. Any costs related to production, general and administrative
expense, or similar activities are not included.
Gross
acres or gross wells
means the total acres or wells, as the case may be, in which a working interest is owned.
Henry
Hub
means the natural gas pipeline located in Erath, Louisiana that serves as the official delivery location for futures
contracts on the NYMEX.
Lease
operating expenses
means the expenses of lifting oil or natural gas from a producing formation to the surface, constituting
part of the current operating expenses of a working interest, and also including labor, superintendence, supplies, repairs, short-lived
assets, maintenance, allocated overhead costs, and other expenses incidental to production, but not including lease acquisition
or drilling or completion expenses.
Liquids
describes oil, condensate, and natural gas liquids.
MBbls
means one thousand barrels of crude oil or other liquid hydrocarbons.
Mcf
means one thousand cubic feet of natural gas.
Mcfe
means one thousand cubic feet equivalent determined using the ratio of six Mcf of natural gas to one bbl of crude
oil, condensate, or natural gas liquids.
MMBbl
means one million
barrels of crude oil or other liquid hydrocarbons.
MMBoe
means one million barrels of oil equivalent.
MMBtu
means one million British Thermal Units, a common energy measurement.
MMcf
means one million cubic feet of natural gas.
MMcfe
means one million cubic feet equivalent determined using the ratio of six Mcf of natural gas to one bbl of crude oil,
condensate, or natural gas liquids.
NGL
means natural gas liquids.
Net
acres or net wells
is the sum of the fractional working interest owned in gross acres or gross wells expressed in whole
numbers and fractions of whole numbers.
Non-productive
well
means a well found to be incapable of producing either oil or natural gas in sufficient quantities to justify completion
as an oil or natural gas well.
NYMEX
means New York Mercantile Exchange.
Productive
wells
means producing wells and wells that are capable of production, and wells that are shut-in.
Proved
developed reserves
means estimated proved reserves that can be expected to be recovered through existing wells with existing
equipment and operating methods.
Proved
reserves
means quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated
with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing
economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right
to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic
methods are used for the estimation. Existing economic conditions include prices that are the average price during the twelve-month
period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month
price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon
future conditions.
Proved
undeveloped reserves
means estimated proved reserves that are expected to be recovered from new wells on undrilled acreage
or from existing wells where a relatively major expenditure is required for recovery to occur.
PV-10
means the estimated future gross revenue to be generated from the production of proved reserves, net of estimated production
and future development costs, using prices and costs in effect at the determination date, without giving effect to non-property
related expenses such as general and administrative expenses, debt service and future income tax expense or to depreciation, depletion
and amortization, discounted using an annual discount rate of 10%. PV-10 is not a financial measure accepted under GAAP.
Reservoir
means a porous and permeable underground formation containing a natural accumulation of producible natural gas and/or
oil that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.
Royalty
means an interest in an oil or natural gas lease that gives the owner of the interest the right to receive a portion of
the production from the leased acreage (or of the proceeds of the sale thereof), but generally does not require the owner to pay
any portion of the costs of drilling or operating the wells on the leased acreage. Royalties may be either landowner’s royalties,
which are reserved by the owner of the leased acreage at the time the lease is granted, or overriding royalties, which are usually
reserved by an owner of the leasehold in connection with a transfer to a subsequent owner.
Standardized
measure
means the standardized measure of present value of estimated future net revenues, which means an estimate of the
present value of the estimated future net revenues from proved oil or natural gas reserves at a date indicated after deducting
estimated production and ad valorem taxes, future capital costs, operating expenses and income taxes computed by applying year
end statutory tax rates, with consideration of future tax rates already legislated. The estimated future net revenues are discounted
at an annual rate of 10%, in accordance with the SEC’s practice, to determine their “present value.” The present
value is shown to indicate the effect of time on the value of the revenue stream and should not be construed as being the fair
market value of the properties. Estimates of future net revenues are made using oil and natural gas prices and operating costs
at the estimation date and held constant for the life of the reserves.
Undeveloped
acreage
means acreage on which wells have not been drilled or completed to a point that would permit the production of
economic quantities of oil or natural gas, regardless of whether such acreage contains proved reserves.
Working
interest
means an operating interest which gives the owner the right to drill, produce, and conduct operating activities
on the property, and to receive a share of production.
Shares
Carbon
Energy Corporation
Common Stock
PROSPECTUS
,
2018
RBC CAPITAL MARKETS
Part II
Information
Not Required in Prospectus
Item 13. Other Expenses of Issuance and Distribution
The following table sets forth an itemized
statement of the amounts of all expenses (excluding underwriting discount) payable by us in connection with the registration of
the common stock offered hereby. With the exception of the SEC registration fee and the FINRA filing fee, the amounts set forth
below are estimates.
SEC registration fee
|
|
$
|
14,317.50
|
|
FINRA filing fee
|
|
|
9,200.00
|
|
NASDAQ listing fee
|
|
|
*
|
|
Accounting fees and expenses
|
|
|
*
|
|
Legal fees and expenses
|
|
|
*
|
|
Printing and engraving expenses
|
|
|
*
|
|
Transfer agent and registrar fees
|
|
|
*
|
|
Miscellaneous
|
|
|
*
|
|
Total
|
|
$
|
*
|
|
*
|
To be completed by amendment.
|
Item 14. Indemnification of Directors and Officers
Section 145 of the DGCL permits a Delaware
corporation to indemnify its officers, directors and other corporate agents to the extent and under the circumstances set forth
therein. Our amended and restated certificate of incorporation and bylaws provide that we will indemnify any person who was or
is a party or is threatened to be made a party to any threatened, pending or completed action, suit or proceeding, whether civil,
criminal, administrative or investigative (other than an action by or in the right of the Company), by reason of the fact that
he or she is or was our director, officer, employee or member, or is or was serving at our request as a director, officer, employee
or agent of another corporation, partnership, joint venture, trust or other enterprise, in accordance with provisions corresponding
to Section 145 of the DGCL. These indemnification provisions may be sufficiently broad to permit indemnification of the registrant’s
executive officers and directors for liabilities, including reimbursement of expenses incurred, arising under the Securities Act.
Pursuant to Section 102(b)(7) of the DGCL,
our amended and restated certificate of incorporation eliminates the personal liability of a director to us or our stockholders
for monetary damages for a breach of fiduciary duty as a director, except for liabilities arising:
|
●
|
from any breach of the director’s duty
of loyalty to us or our stockholders;
|
|
●
|
from acts or omissions not in good faith or
which involve intentional misconduct or a knowing violation of law;
|
|
●
|
under Section 174 of the DGCL; and
|
|
●
|
from any transaction from which the director
derived an improper personal benefit.
|
The above discussion of Section 145
of the DGCL and of our amended and restated certificate of incorporation and bylaws is not intended to be exhaustive and is respectively
qualified in its entirety by Section 145 of the DGCL, our amended and restated certificate of incorporation and bylaws.
As permitted by Section 145 of the
DGCL, we will carry primary and excess insurance policies insuring our directors and officers against certain liabilities they
may incur in their capacity as directors and officers. Under the policies, the insurer, on our behalf, may also pay amounts for
which we granted indemnification to our directors and officers.
In addition, the form of underwriting
agreement filed as Exhibit 1.1 to this Registration Statement provides that the underwriters will indemnify us and our executive
officers and directors for certain liabilities related to this offering, including liabilities arising under the Securities Act.
Item 15. Recent Sales of Unregistered Securities
On March 16, 2016, pursuant to the Carbon
2011 Stock Incentive Plan and the Carbon 2015 Stock Incentive Plan, the Company granted 420,000 restricted shares to its non-employee
directors, 800,000 restricted shares to its officer employees and 520,000 restricted shares to its non-officer employees. To the
extent these stock grants constituted a sale of equity securities, the Company relied on Sections 4(a)(2) of the Securities Act
of 1933 for these stock grants. No commissions or other remuneration were paid in connection with these stock grants.
On August 9, 2016, pursuant to the Carbon
2011 Stock Incentive Plan and the Carbon 2015 Stock Incentive Plan, the Company granted 900,000 restricted shares to certain of
its employees. To the extent these stock grants constitute a sale of equity securities, the Company relied on Sections 4(a)(2)
of the Securities Act of 1933 for these stock grants. No commissions or other remuneration were paid in connection with these
stock grants.
On February 15, 2017, in connection with
the commencement of operations of Carbon California, the Company issued to Yorktown a warrant to purchase shares of the Company’s
common stock at an exercise price of $0.36 per share (the “
California Warrant
”). The exercise price
for the California Warrant is payable exclusively with Class A Units of Carbon California and the number of shares of the Company
common stock for which the California Warrant is exercisable is determined, as of the time of exercise, by dividing (a) the
aggregate unreturned capital of Yorktown’s Class A Units of Carbon California by (b) the exercise price. The California
Warrant has a term of seven years and includes certain standard registration rights with respect to the shares of the Company’s
common stock issuable upon exercise of the California Warrant. On February 1, 2018, Yorktown exercised the California Warrant
and received 1,527,778 shares of common stock in the Company. The California Warrant and the shares of common stock issued when
it was exercised were issued pursuant to an exemption from the registration requirements of the Securities Act of 1933, as amended,
provided by Section 4(a)(2) thereof and/or Rule 506 of Regulation D promulgated thereunder.
On March 16, 2017, pursuant to the Carbon
2011 Stock Incentive Plan and the Carbon 2015 Stock Incentive Plan, the Company granted 21,000 restricted shares to its non-employee
directors, 40,000 restricted shares to its officer employees and 20,050 restricted shares to its non-officer employees. To the
extent these stock grants constituted a sale of equity securities, the Company relied on Sections 4(a)(2) of the Securities Act
of 1933 for these stock grants. No commissions or other remuneration were paid in connection with these stock grants.
On April 3, 2017, in connection with the
commencement of operations of Carbon Appalachia, the Company issued to Yorktown a warrant to purchase shares of the Company’s
common stock at an exercise price of $7.20 per share (the “
Appalachia Warrant
”). The exercise price
for the Appalachia Warrant is payable exclusively with Class A Units of Carbon Appalachia and the number of shares of the Company
common stock for which the Appalachia Warrant is exercisable is determined, as of the time of exercise, by dividing (a) the
aggregate unreturned capital plus an internal rate of return on such capital of Yorktown’s Class A Units of Carbon Appalachia
by (b) the exercise price. The Appalachia Warrant has a term of seven years and includes certain standard registration rights
with respect to the shares of the Company’s common stock issuable upon exercise of the Appalachia Warrant. On November 1,
2017, Yorktown exercised the Appalachia Warrant and received 432,051 shares of common stock in the Company. The Appalachia Warrant
and the shares of common stock issued when it was exercised were issued pursuant to an exemption from the registration requirements
of the Securities Act of 1933, as amended, provided by Section 4(a)(2) thereof and/or Rule 506 of Regulation D promulgated thereunder.
On
April 6, 2018, we raised $5.0 million through the issuance of 50,000 shares of Series B Convertible Preferred Stock, par value
$0.01 per share (the “
Preferred Stock
”), to Yorktown. We used the proceeds from the sale of the Preferred
Stock to fund our portion of the purchase price for the Seneca Acquisition. Upon the completion of this offering, the Preferred
Stock will automatically convert into shares of common stock. The conversion ratio at which the Preferred Stock will convert into
common stock is equal to an amount per share of $100 plus all accrued but unpaid dividends payable in respect thereof (together,
the “
Liquidation Preference
”) divided by the greater of (i) $8.00 per share or (ii) the price that is
15% less than the price per share of shares sold to the public in this offering.
See “
Description of Capital
Stock—Preferred Stock
” for more information on the terms of our preferred stock.
The
Preferred Stock was issued pursuant to an exemption from the registration requirements of the Securities Act of 1933, as amended,
provided by Section 4(a)(2) thereof and/or Rule 506 of Regulation D promulgated thereunder.
Item 16. Exhibits
See the Exhibit Index on the page immediately
preceding the exhibits for a list of exhibits filed as part of this registration statement on Form S-1, which Exhibit Index is
incorporated herein by reference.
Item 17. Undertakings
Insofar as indemnification for liabilities
arising under the Securities Act may be permitted to directors, officers and controlling persons of the registrant pursuant to
the foregoing provisions, or otherwise, the registrant has been advised that in the opinion of the Securities and Exchange Commission
such indemnification is against public policy as expressed in the Securities Act and is, therefore, unenforceable. In the event
that a claim for indemnification against such liabilities (other than the payment by the registrant of expenses incurred or paid
by a director, officer or controlling person of the registrant in the successful defense of any action, suit or proceeding) is
asserted by such director, officer or controlling person in connection with the securities being registered, the registrant will,
unless in the opinion of its counsel the matter has been settled by controlling precedent, submit to a court of appropriate jurisdiction
the question whether such indemnification by it is against public policy as expressed in the Securities Act and will be governed
by the final adjudication of such issue.
The undersigned registrant hereby undertakes that:
|
(1)
|
For purposes of
determining any liability under the Securities Act, the information omitted from the form of prospectus filed as part of this
registration statement in reliance upon Rule 430A and contained in a form of prospectus filed by the registrant pursuant to
Rule 424(b)(1) or (4) or 497(h) under the Securities Act shall be deemed to be part of this registration statement as of the
time it was declared effective.
|
|
(2)
|
For the purpose
of determining any liability under the Securities Act, each post-effective amendment that contains a form of prospectus shall
be deemed to be a new registration statement relating to the securities offered therein, and the offering of such securities
at that time shall be deemed to be the initial bona fide offering thereof.
|
INDEX TO EXHIBITS
Exhibit No.
|
|
D
escription
|
1.1**
|
|
Form
of Underwriting Agreement
|
2.1
|
|
Participation
Agreement by and between the Company, Nytis Exploration Company LLC and Liberty Energy LLC, dated February 25, 2014, incorporated
by reference to Exhibit 2.3 to Form 10-Q filed on November 14, 2014.
|
2.2
|
|
Addendum
to Participation Agreement by and between the Company, Nytis Exploration Company LLC and Liberty Energy LLC, dated February
26, 2014, incorporated by reference to Exhibit 2.4 to Form 10-Q filed on November 14, 2014.
|
2.3
|
|
Purchase
and Sale Agreement by and among Nytis Exploration Company LLC, Liberty Energy, LLC and Continental Resources, Inc., dated
October 15, 2014, incorporated by reference to Exhibit 2.5 to Form 10-K filed on March 31, 2015. Portions of the Purchase
and Sale Agreement have been omitted pursuant to a request for confidential treatment.
|
2.4
|
|
Purchase
and Sale Agreement by and among Nytis Exploration Company LLC, EXCO Production Company (WV), LLC, BG Production Company (WV),
LLC and EXCO Resources (PA), dated October 1, 2016, incorporated by reference to Exhibit 2.4 to Form 10-K filed on March 31,
2017.
|
3.1
|
|
Amended
and Restated Certificate of Incorporation of Carbon Natural Gas Company, dated as of April 27, 2011, incorporated by reference
to Exhibit 3(i)(a) to Form 10-K filed on March 31, 2017.
|
3.2
|
|
Certificate
of Amendment to the Certificate of Incorporation of Carbon Natural Gas Company, dated as of July 14, 2011, incorporated by
reference to Exhibit 3(i) to Form 8-K filed on July 19, 2011.
|
3.3
|
|
Certificate
of Amendment to the Amended and Restated Certificate of Incorporation of Carbon Natural Gas Company, dated as of March 15,
2017, incorporated by reference to Exhibit 3.1 to Form 8-K filed on March 16, 2017.
|
3.4
|
|
Certificate
of Correction to the Certificate of Amendment to the Amended and Restated Certificate of Incorporation of Carbon Natural Gas
Company, dated as of March 23, 2018, incorporated by reference to Exhibit 3.1 to Form 8-K filed on March 28, 2018.
|
3.5
|
|
Certificate
of Amendment to the Amended and Restated Certificate of Incorporation of Carbon Natural Gas Company, dated as of May 1, 2018,
incorporated by reference to Exhibit 3(i) to Form 8-K filed on June 4, 2018.
|
3.6
|
|
Amended
and Restated Bylaws, incorporated by reference to Exhibit 3(i) to Form 8-K filed on May 5, 2015.
|
3.7
|
|
Amendment
No. 1 to Amended and Restated Bylaws, incorporated by reference to Exhibit 3(ii) to Form 8-K filed on June 4, 2018.
|
3.8
|
|
Certificate
of Designation with respect to Series B Convertible Preferred Stock, incorporated by reference to Exhibit 3(i) to Form 8-K
filed on April 6, 2018.
|
5.1*
|
|
Form
of Opinion of Baker Botts L.L.P. as to the legality of the securities being registered
|
10.1
|
|
Credit
Agreement, by and between the Company, Nytis Exploration Company LLC, Nytis Exploration (USA) Inc. and LegacyTexas Bank, dated
October 3, 2016, incorporated by reference to Exhibit 10.1 to Form 10-K filed on March 31, 2017.
|
10.2
|
|
Unconditional
Guaranty from Nytis Exploration Company, LLC and Nytis Exploration Company (USA) Inc. to LegacyTexas Bank, dated October 3,
2016, incorporated by reference to Exhibit 10.1(a) to Form 10-K filed on March 31, 2017.
|
10.3
|
|
Security
Agreement from Carbon Natural Gas Company, Nytis Exploration Company LLC and Nytis Exploration Company (USA) Inc. to LegacyTexas
Bank, dated October 3, 2016, incorporated by reference to Exhibit 10.1(b) to Form 10-K filed on March 31, 2017.
|
10.4
|
|
Third
Amendment to Credit Agreement, among Carbon Natural Gas Company and LegacyTexas Bank, dated March 27, 2018, incorporated by
reference to Exhibit 10.4 to Form 10-K filed on April 2, 2018.
|
10.5***
|
|
Form
of Amended and Restated Credit Agreement, among the Company and LegacyTexas Bank.
|
10.6
|
|
Employment
Agreement between the Company and Patrick McDonald, incorporated by reference to Exhibit 10.2 to Form 8-K filed on April 5,
2013.
|
10.7
|
|
Employment
Agreement between the Company and Mark Pierce, incorporated by reference to Exhibit 10.3 to Form 8-K filed on April 5, 2013.
|
10.8
|
|
Employment
Agreement between the Company and Kevin Struzeski, incorporated by reference to Exhibit 10.4 to Form 8-K filed on April 5,
2013.
|
10.9
|
|
Carbon
Natural Gas Company 2015 Annual Incentive Plan, incorporated by reference to Exhibit 10.2 to Form 10-Q filed on May 14, 2015.
|
10.10
|
|
Carbon
Natural Gas Company 2015 Stock Incentive Plan incorporated by reference to Exhibit 10.12 to Form 10-K filed on March 28, 2016.
|
10.11
|
|
Carbon
Natural Gas Company 2016 Annual Incentive Plan, incorporated by reference to Exhibit 10.1 to Form 10-Q filed on May 23, 2016.
|
10.12
|
|
Carbon
Natural Gas Company 2017 Annual Incentive Plan, incorporated by reference to Exhibit 10.3 to Form 10-Q filed on May 19, 2017.
|
10.13
|
|
Purchase
and Sale Agreement, dated as of October 20, 2017, between Seneca Resources Corporation and Carbon California Company, LLC,
as amended, incorporated by reference to Exhibits 2.1, 2.2, 2.3 and 2.4 to Form 10-Q/A filed on June 19, 2018.
|
10.14
|
|
Form
of Purchase Agreement, dated April 6, 2018, incorporated by reference to Exhibit 10.1 to Form 8-K filed on April 9, 2018.
|
10.15
|
|
Membership
Interest Purchase Agreement, dated as of May 4, 2018, by and among Old Ironsides Fund
II-A Portfolio Holding Company, LLC, Old Ironsides Fund II-B Portfolio Holding Company,
LLC, and Carbon Natural Gas Company, incorporated by reference to Exhibit 10.1 to Form
10-Q filed on August 14, 2018.
|
10.16
|
|
Letter
Amendment, dated July 20, 2018, to Membership Interest Purchase Agreement, dated as of
May 4, 2018, by and among Old Ironsides Fund II-A Portfolio Holding Company, LLC, Old
Ironsides Fund II-B Portfolio Holding Company, LLC, and Carbon Natural Gas Company, incorporated
by reference to Exhibit 10.2 to Form 10-Q filed on August 14, 2018.
|
Exhibit No.
|
|
Description
|
21.1**
|
|
Subsidiaries
of the Company.
|
23.1*
|
|
Consent
of EKS&H LLLP.
|
23.2*
|
|
Consent
of EKS&H LLLP.
|
23.3*
|
|
Consent
of EKS&H LLLP.
|
23.4*
|
|
Consent
of EKS&H LLLP.
|
23.5*
|
|
Consent
of EKS&H LLLP.
|
23.6*
|
|
Consent
of Cawley, Gillespie & Associates, Inc.
|
23.7*
|
|
Consent
of Baker Botts L.L.P. (contained in Exhibit 5.1)
|
24.2***
|
|
Power of Attorney (contained on signature page)
|
99.1
|
|
Report
of Cawley, Gillespie & Associates, Inc., Independent Petroleum Engineers, incorporated by reference to Exhibit 99.3 to
Form 10-K filed on April 2, 2018.
|
99.2
|
|
Report
of Cawley, Gillespie & Associates, Inc., Independent Petroleum Engineers, incorporated by reference to Exhibit 99.4 to
Form 10-K filed on April 2, 2018.
|
99.3
|
|
Report
of Cawley, Gillespie & Associates, Inc., Independent Petroleum Engineers, incorporated by reference to Exhibit 99.5 to
Form 10-K filed on April 2, 2018.
|
99.4**
|
|
Consent
of Director Nominee
|
101**
|
|
Interactive
data files pursuant to Rule 405 of Regulation S-T.
|
**
|
To be provided by amendment.
|
SIGNATURES
Pursuant to the requirements of the
Securities Act of 1933, as amended, the registrant has duly caused this Registration Statement to be signed on its behalf by the
undersigned, thereunto duly authorized, in the City of Denver, State of Colorado, on September 6, 2018.
|
Carbon Energy Corporation
|
|
|
|
|
|
By:
|
/s/
Patrick R. McDonald
|
|
|
Name:
|
Patrick R. McDonald
|
|
|
Title:
|
Chief Executive Officer
|
Name
|
|
Title
|
|
Date
|
|
|
|
|
|
/s/
Patrick R. McDonald
|
|
Chief Executive
Officer and Director
|
|
September 6, 2018
|
Patrick R. McDonald
|
|
(Principal Executive
Officer)
|
|
|
|
|
|
|
|
*
|
|
Chief Financial
Officer, Treasurer and Secretary
|
|
September 6, 2018
|
Kevin D. Struzeski
|
|
(Principal Financial
and Accounting Officer)
|
|
|
|
|
|
|
|
*
|
|
Chairman and Director
|
|
September 6, 2018
|
James H. Brandi
|
|
|
|
|
|
|
|
|
|
*
|
|
Director
|
|
September 6, 2018
|
Peter A. Leidel
|
|
|
|
|
|
|
|
|
|
*
|
|
Director
|
|
September 6, 2018
|
Bryan H. Lawrence
|
|
|
|
|
|
|
|
|
|
*
|
|
Director
|
|
September 6, 2018
|
Edwin H. Morgens
|
|
|
|
|
|
|
|
|
|
*
|
|
Director
|
|
September 6, 2018
|
David H. Kennedy
|
|
|
|
|
* Kevin D. Struzeski hereby signs this
Amendment No. 3 to the Registration Statement on behalf of the indicated person for whom he is attorney-in-fact on September 6,
2018, pursuant to powers of attorney previously included with the Registration Statement on Form S-1 of Carbon Energy Corporation
filed on May 25, 2018 and July 25, 2018 with the Securities and Exchange Commission.
By:
|
/s/
Kevin D. Struzeski
|
|
|
Kevin D. Struzeski
Attorney-in-fact
|
|
II-5
Carbon Energy (CE) (USOTC:CRBO)
Historical Stock Chart
From Feb 2024 to Mar 2024
Carbon Energy (CE) (USOTC:CRBO)
Historical Stock Chart
From Mar 2023 to Mar 2024