CARBON ENERGY CORPORATION
Consolidated Statements of Stockholders’
Equity
(In thousands)
|
|
Common Stock
|
|
|
Preferred Stock
|
|
|
Additional
paid
|
|
|
Non- controlling
|
|
|
Accumulated
|
|
|
Total Stockholders’
|
|
|
|
Shares
|
|
|
Amount
|
|
|
Shares
|
|
|
Amount
|
|
|
in capital
|
|
|
interest
|
|
|
Deficit
|
|
|
Equity
|
|
Balances, December 31, 2016
|
|
|
5,482
|
|
|
$
|
55
|
|
|
|
-
|
|
|
|
-
|
|
|
$
|
57,588
|
|
|
$
|
1,865
|
|
|
$
|
(50,536
|
)
|
|
$
|
8,973
|
|
Stock-based compensation
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
1,106
|
|
|
|
-
|
|
|
|
-
|
|
|
|
1,106
|
|
Vested restricted stock
|
|
|
67
|
|
|
|
1
|
|
|
|
-
|
|
|
|
-
|
|
|
|
(1
|
)
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
Vested performance units
|
|
|
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
|
|
Stock based compensation
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
1,133
|
|
|
|
-
|
|
|
|
-
|
|
|
|
1,133
|
|
Vested restricted stock
|
|
|
60
|
|
|
|
1
|
|
|
|
-
|
|
|
|
-
|
|
|
|
(1
|
)
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
Vested performance units
|
|
|
108
|
|
|
|
1
|
|
|
|
-
|
|
|
|
-
|
|
|
|
(1
|
)
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
Restricted stock and performance units exchanged for tax withholding
|
|
|
(46
|
)
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
(197
|
)
|
|
|
-
|
|
|
|
-
|
|
|
|
(197
|
)
|
Preferred share issuance
|
|
|
-
|
|
|
|
-
|
|
|
|
50
|
|
|
|
1
|
|
|
|
4,999
|
|
|
|
-
|
|
|
|
-
|
|
|
|
5,000
|
|
Beneficial conversion feature
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
1,125
|
|
|
|
-
|
|
|
|
(1,125
|
)
|
|
|
-
|
|
CCC warrant exercise - share issuance
|
|
|
1,528
|
|
|
|
15
|
|
|
|
-
|
|
|
|
-
|
|
|
|
8,312
|
|
|
|
16,465
|
|
|
|
-
|
|
|
|
24,792
|
|
Majority control of CCC (Note 4)
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
10,429
|
|
|
|
-
|
|
|
|
-
|
|
|
|
10,429
|
|
Units issued with 2018 Subordinated Notes, related party (Note 7)
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
489
|
|
|
|
|
|
|
|
489
|
|
Non-controlling interest contributions, net
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
5,114
|
|
|
|
-
|
|
|
|
5,114
|
|
Net income
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
4,375
|
|
|
|
8,404
|
|
|
|
12,779
|
|
Balances, December 31, 2018
|
|
|
7,656
|
|
|
$
|
77
|
|
|
|
50
|
|
|
$
|
1
|
|
|
$
|
84,612
|
|
|
$
|
28,284
|
|
|
$
|
(36,939
|
)
|
|
$
|
76,035
|
|
See accompanying notes to Consolidated
Financial Statements.
CARBON ENERGY CORPORATION
Consolidated Statements of Cash Flows
(In thousands)
|
|
Twelve months ended
December 31,
|
|
|
|
2018
|
|
|
2017
|
|
|
|
|
|
|
|
|
Cash flows from operating activities:
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
$
|
12,779
|
|
|
$
|
6,399
|
|
Items not involving cash:
|
|
|
|
|
|
|
|
|
Depreciation, depletion and amortization
|
|
|
8,108
|
|
|
|
2,544
|
|
Accretion of asset retirement obligations
|
|
|
868
|
|
|
|
307
|
|
Unrealized commodity derivative gain
|
|
|
(8,742
|
)
|
|
|
(2,158
|
)
|
Warrant derivative gain
|
|
|
(225
|
)
|
|
|
(3,133
|
)
|
Stock-based compensation expense
|
|
|
1,133
|
|
|
|
1,106
|
|
Investment in affiliates gain
|
|
|
(7,734
|
)
|
|
|
(1,128
|
)
|
Amortization of debt issuance costs
|
|
|
966
|
|
|
|
176
|
|
Other
|
|
|
-
|
|
|
|
(109
|
)
|
Net change in:
|
|
|
|
|
|
|
|
|
Accounts receivable
|
|
|
545
|
|
|
|
(812
|
)
|
Prepaid expenses, deposits and other current assets
|
|
|
1,067
|
|
|
|
(477
|
)
|
Accounts payable, accrued liabilities and firm transportation contracts
|
|
|
2,472
|
|
|
|
1,205
|
|
Other non-current assets
|
|
|
(392
|
)
|
|
|
-
|
|
Net cash provided by operating activities
|
|
|
10,845
|
|
|
|
3,920
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash flows from investing activities:
|
|
|
|
|
|
|
|
|
Development and acquisition of properties and equipment
|
|
|
(2,995
|
)
|
|
|
(1,591
|
)
|
Acquisition of oil and gas properties, asset acquisitions (Note 3)
|
|
|
(46,980
|
)
|
|
|
-
|
|
Acquisition of oil and gas properties, business combinations, net of cash received (Note 3)
|
|
|
(20,461
|
)
|
|
|
-
|
|
Other non-current assets
|
|
|
-
|
|
|
|
(145
|
)
|
Investment in affiliates
|
|
|
-
|
|
|
|
(6,797
|
)
|
Net cash used in investing activities
|
|
|
(70,436
|
)
|
|
|
(8,533
|
)
|
|
|
|
|
|
|
|
|
|
Cash flows from financing activities:
|
|
|
|
|
|
|
|
|
Vested restricted stock and performance units exchanged for tax withholding
|
|
|
(197
|
)
|
|
|
(399
|
)
|
Proceeds from credit facilities and notes payable
|
|
|
118,628
|
|
|
|
7,210
|
|
Proceeds from preferred shares
|
|
|
5,000
|
|
|
|
-
|
|
Payments on credit facilities and notes payable
|
|
|
(64,150
|
)
|
|
|
(1,300
|
)
|
Payments of debt issuance costs
|
|
|
(718
|
)
|
|
|
-
|
|
Contributions from non-controlling interests
|
|
|
5,164
|
|
|
|
-
|
|
Distributions to non-controlling interests
|
|
|
(50
|
)
|
|
|
(106
|
)
|
Net cash provided by financing activities
|
|
|
63,677
|
|
|
|
5,405
|
|
|
|
|
|
|
|
|
|
|
Net increase in cash and cash equivalents
|
|
|
4,086
|
|
|
|
792
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents, beginning of period
|
|
|
1,650
|
|
|
|
858
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents, end of period
|
|
$
|
5,736
|
|
|
$
|
1,650
|
|
See Note 16 - Supplemental Cash Flow Disclosure
See accompanying notes to Consolidated Financial
Statements.
Note 1 - Organization
Carbon Energy Corporation’s and its
subsidiaries’ (formerly known as Carbon Natural Gas Company and referred to herein as “we”, “us”,
or “Carbon”) business is comprised of the assets and properties of us and our subsidiaries.
Appalachian and Illinois Basin Operations
In the Appalachian and Illinois Basins,
operations are conducted by Nytis Exploration Company, LLC (“Nytis LLC”). The following organizational chart illustrates
this relationship as of December 31, 2018.
In December 2018, we completed the acquisition
of all of the Class A Units of Carbon Appalachian Company, LLC, a Delaware limited liability company (“Carbon Appalachia”),
owned by Old Ironside Fund II-A Portfolio Holding Company, LLC, a Delaware limited liability company (“OIE II-A”),
and Old Ironside Fund II-B Portfolio Holding Company, LLC, a Delaware limited liability company (“OIE II-B”), collectively
(“Old Ironsides”) for a purchase price of $58.1 million subject to purchase price adjustments (“OIE Membership
Acquisition”). As a result of the OIE Membership Acquisition, we now hold all of the issued and outstanding ownership interests
of Carbon Appalachia, along with its direct and indirect subsidiaries (Carbon Appalachia Group, LLC, Carbon Tennessee Mining Company,
LLC, Carbon Appalachia Enterprises, LLC, Carbon West Virginia Company, LLC, Cranberry Pipeline Corporation, Knox Energy, LLC, Coalfield
Pipeline Company and Appalachia Gas Services Company, LLC).
Ventura Basin Operations
In California, Carbon California Operating
Company, LLC (“CCOC”), conducts operations on behalf of Carbon California’s operations. 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%. 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 Legacy Insurance Company
of New Jersey and Prudential Insurance Company of America or its affiliates (“Prudential”) owns 46.08% of the voting
and profits interest in Carbon California. As of February 1, 2018, we consolidate Carbon California for financial reporting purposes. The
following organizational chart illustrates this relationship as of December 31, 2018.
Collectively, references to “us”
include Carbon California, CCOC, Nytis Exploration (USA) Inc. (“Nytis USA”), Nytis LLC, and Carbon Appalachia.
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. Upon the closing of the OIE Membership Acquisition on December 31, 2018,
we own 100% of Carbon Appalachia. In addition, we own 100% of Nytis USA. Nytis USA owns approximately 98.1% of Nytis LLC. Nytis
LLC holds interests in various oil and gas partnerships.
Partnerships and subsidiaries in which
we have a controlling interest are consolidated. We are currently consolidating 46 partnerships, Carbon Appalachia, and Carbon
California, and we reflect the non-controlling ownership interest in partnerships and subsidiaries as non-controlling interests
on our consolidated statements of operations and also reflect 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,
if necessary, maintain an allowance for doubtful accounts based upon our historical experience and any specific customer collection
issues that we have identified.
At December 31, 2018 and 2017, 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.
Revenue
Our Accounts receivable - Revenue is comprised
of oil and natural gas revenues from producing activities.
Marketing Gas Revenue
We sell production purchased from third parties
as well as production from our own oil and gas producing properties. Gas revenues are recognized on a gross basis as we purchase
and take control of the gas prior to sale and are the principal in the transaction.
Storage
Under fee-based arrangements, we receive
a fee for storing natural gas. The revenues earned are directly related to the volume of natural gas that flows through our storage
systems and are not directly dependent on commodity prices.
Transportation, gathering, and compression
We generally purchase natural gas from
producers at the wellhead or other receipt points, gather the natural gas through our gathering system, and then sell the natural
gas based on published index market prices. We 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. Our revenues under percent-of-proceeds or index arrangements
generally correlate with the price of natural gas.
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 revenues associated
with over-deliveries or under-deliveries of natural gas to purchasers as an asset or a liability, whichever is appropriate. As
of December 31, 2018, and 2017, there was an imbalance due to us in the amount of approximately $551,000 and $193,000, respectively.
Insurance Receivable
Insurance receivable is comprised of insurance
claims 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 a portion of funds associated with the claims as of December 31, 2018. The Company
has determined the receivable is collectible and is included in insurance receivable on the consolidated balance sheets. As of
December 31, 2018, the Company has an insurance receivable of $522,000 and collected $3.1 million from previously submitted claims.
In January 2019, the Company received a settlement of $800,000 for all remaining claims with the insurance company (see Note 18).
Inventory
Inventory, which consist primarily of natural
gas, is recorded at the lower of weighted average cost or market value. Gas that is available for immediate use, referred to as
working gas, is recorded within current assets. Inventory also consists of material and supplies used in connection with the Company’s
maintenance, storage and handling. Inventory is stated at the lower of cost or net realizable value.
Prepaid Expense, Deposits and Other
Current Assets
Our prepaid expense, deposit and other
current assets are comprised of prepaid insurance, the current portion of unamortized debt issuance costs and deposits.
Oil and Natural Gas Sales
We sell our oil, natural gas and natural
gas liquids 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 years ended December 31, 2018 and 2017. 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
|
|
2018
|
|
|
2017
|
|
Purchaser A
|
|
|
17
|
%
|
|
|
23
|
%
|
Purchaser E
|
|
|
16
|
%
|
|
|
-
|
%
|
Purchaser B
|
|
|
12
|
%
|
|
|
17
|
%
|
Purchaser C
|
|
|
9
|
%
|
|
|
12
|
%
|
Purchaser D
|
|
|
8
|
%
|
|
|
11
|
%
|
As of December 31, 2018, none of the above
purchasers comprised more than 10% of total accounts receivable. One purchaser’s receivable acquired with the closing of
the OIE Membership Acquisition accounts for approximately 10% of accounts receivable as of December 31, 2018.
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, 2018, and 2017, we had a purchaser imbalance
receivable of $551,000 and $193,000, respectively, within account receivables-joint interest billings and other. As of December
31, 2018 and 2017, we had a purchaser imbalance payable of approximately $0 and $25,000 within accounts payable and accrued expenses,
respectively.
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 years ended December 31, 2018 and
2017, we did not recognize a ceiling test impairment as our full cost pool did not exceed the 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, Plant and Equipment
Other property, plant and equipment are
recorded at cost upon acquisition. 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 base gas, is recorded other property, plant and equipment on the consolidated balance
sheets. 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.
Non-current Assets
We review our non-current assets, consisting
of property, plant and equipment, 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 non-current assets have been impaired.
Other Non-current Assets
Our other non-current assets are comprised
of bonds and the non-current portion of deferred debt issue and financing costs.
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. Prior to their consolidation on February 1, 2018 and December 31, 2018 for our investments in Carbon California
and Carbon Appalachia, respectively, we used 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 (prior to completion of the OIE Membership Acquisition on December 31, 2018), we receive reimbursements for
management services. These reimbursements are included in general and administrative – related party reimbursement on our
consolidated statements 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 –
due from related parties on our consolidated balance sheets and are therefore not included in our operating expenses on our consolidated
statements of operations (see Note 17).
Due from Related parties
As of December 31, 2017, and prior to consolidation
of Carbon California and Carbon Appalachia as of February 1, 2018 and December 31, 2018, respectively, our receivables - due from
related parties are comprised of receivables from Carbon California and Carbon Appalachia in our role as manager and operator of
these entities (see Note 17).
General and Administrative –
Deferred Fees Writedown
Approximately $2.0 million in financing costs were expensed in the preparation of an equity raise that
we do not believe is likely to occur in the short term.
Warrant Liability
We issued warrants related to investments
in Carbon California and Carbon Appalachia. We accounted 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 were 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 statements of operations.
For the years ended December 31, 2018 and 2017, changes in the fair value of warrants accounted for gains of approximately $225,000
and $3.1 million, respectively. As of December 31, 2018, all warrants were exercised (see Note 4).
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 non-current
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 12).
The following table is a reconciliation of the ARO for the years
ended December 31, 2018 and 2017.
|
|
Year Ended December 31,
|
|
(in thousands)
|
|
2018
|
|
|
2017
|
|
|
|
|
|
|
|
|
Balance at beginning of year
|
|
$
|
7,357
|
|
|
$
|
5,120
|
|
Accretion expense
|
|
|
868
|
|
|
|
307
|
|
Change in estimate of cash outflow
|
|
|
361
|
|
|
|
2,402
|
|
Additions from Carbon California (Note 4)
|
|
|
2,921
|
|
|
|
-
|
|
Additions from Seneca Acquisition (Note 4)
|
|
|
5,132
|
|
|
|
-
|
|
Additions from Liberty Acquisition (Note 4)
|
|
|
45
|
|
|
|
-
|
|
Additions from OIE Membership Acquisition
|
|
|
5,626
|
|
|
|
-
|
|
Less: sale of wells
|
|
|
-
|
|
|
|
(92
|
)
|
|
|
|
22,310
|
|
|
|
7,737
|
|
Less: ARO recognized as accounts payable and accrued liabilities
|
|
|
(3,099
|
)
|
|
|
(380
|
)
|
Balance at end of year
|
|
$
|
19,211
|
|
|
$
|
7,357
|
|
For the year ended December 31, 2017, we did
not have any additions of ARO compared to $14.1 million of additions to ARO in 2018, primarily due to the acquisition of producing
oil and gas properties in both the Ventura and Appalachian Basins. Upon the closing of the OIE Membership Acquisition on December
31, 2018 and the closing of the Carbon California Acquisition on February 1, 2018, the asset retirement obligations associated
with Carbon Appalachia and Carbon California assets were required to be remeasured at fair value, resulting in the change noted
above. 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 $45,000 per well in the Appalachian Basin. 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; prepaid expense, deposits and other current assets; accounts payable and accrued liabilities;
commodity derivative assets and liabilities, warrant liability, notes payable and our credit facilities. The carrying value of
cash and cash equivalents, accounts receivable, and accounts payables and accrued liabilities are representative of their fair
value, due to the short maturity of these instruments. Our commodity derivative assets and liabilities and warrant liability are
recorded at fair value, as discussed below and in Note 12. The carrying amount of our credit facilities approximate 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 were 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 became 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
For restricted stock, 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, once it becomes probable that the performance measure(s) will
be achieved, expense is recognized over the remainder of the performance period.
Revenue Recognition
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 on the basis of our net revenue
interest (see Note 10).
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 per share:
|
|
For the Year Ended
December 31,
|
|
(in thousands except per share amounts)
|
|
2018
|
|
|
2017
|
|
|
|
|
|
|
|
|
Net income attributable to common shareholders
|
|
$
|
7,055
|
|
|
$
|
6,318
|
|
Less: warrant derivative gain
|
|
|
(225
|
)
|
|
|
(3,133
|
)
|
Diluted net income
|
|
|
6,830
|
|
|
|
3,185
|
|
|
|
|
|
|
|
|
|
|
Basic weighted-average common shares outstanding during the period
|
|
|
7,525
|
|
|
|
5,662
|
|
|
|
|
|
|
|
|
|
|
Add dilutive effects of warrants and non-vested shares of restricted stock
|
|
|
314
|
|
|
|
790
|
|
|
|
|
|
|
|
|
|
|
Diluted weighted-average common shares outstanding during the period
|
|
|
7,839
|
|
|
|
6,452
|
|
|
|
|
|
|
|
|
|
|
Basic net income per common share
|
|
$
|
0.94
|
|
|
$
|
1.12
|
|
Diluted net income per common share
|
|
$
|
0.87
|
|
|
$
|
0.49
|
|
For the year ended December 31, 2018, we had net income and the diluted income per common share calculation
includes the anti-dilutive effects of approximately 314,000 non-vested shares of restricted stock. In addition, approximately 280,000
restricted performance units subject to future contingencies were excluded in the basic and diluted income per share calculations.
For the year ended December 31, 2017, we had net income and the diluted income 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 income 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 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.
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. ASU 2016-02 is effective for public companies for fiscal years, and interim
periods within those fiscal years, beginning after December 15, 2018. The Company adopted this guidance on January 1, 2019, using
the modified retrospective approach.
As part of the assessment process, the
Company utilized external consultants to evaluate agreements under this guidance as well as assess the completeness of the lease
population. The Company continues to evaluate the effect of adopting ASU 2016-02 on the financial statements, accounting policies,
and internal controls. The adoption is expected to result in an increase in the assets and liabilities recorded on its consolidated
balance sheet and additional disclosures. The Company does not expect a material impact on its consolidated statement of operations.
In January 2018, the FASB issued Update
2018-01,
Leases
(Topic 842):
Land Easement Practical Expedient for Transition to Topic 842
, which permits an entity
to elect an optional transition practical expedient to not evaluate land easements existing or expiring before the entity’s
adoption of Update 2016-02 and not previously accounted for as leases. An entity that elects this practical expedient should evaluate
new or modified land easements under this guidance beginning at the date Update 2016-02 is adopted. The Company plans to elect
this practical expedient option at the same time it adopts Update 2016-02.
In July 2018, the FASB issued Update No.
2018-11,
Leases
(Topic 842):
Targeted Improvements
, which provides for an additional transition method that allows
an entity to initially apply the new lease standard at the adoption date and recognize a cumulative-effect adjustment to the opening
balance of retained earnings (deficit) in the period of adoption. The Company plans to elect this transition method, which will
eliminate the need for adjusting prior period comparable financial statements prepared under current lease accounting guidance.
The Company will adopt this guidance at the same time it adopts Update 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 4 - Acquisitions and Divestitures
Acquisitions
Majority Control of Carbon California
Carbon California was formed in 2016 by
us and entities managed by Yorktown and Prudential to acquire oil and gas 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 (Note 6), 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 non-current warrant liability with an associated offset to Additional Paid in Capital (“APIC”). Future
changes to the fair value of the California Warrant were 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 Additional Paid In Capital (“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 53.92% of the voting and profits interests, and Prudential owns
46.08% voting and profits 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% profits 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”) as follows:
|
|
Amount
(in thousands)
|
|
Fair value of Carbon common shares transferred as consideration
|
|
$
|
8,327
|
|
Fair value of NCI
|
|
|
16,466
|
|
Fair value of previously held interest
|
|
|
7,243
|
|
Fair value of contribution associated with acquisition of Yorktown’s interest in CCC
|
|
|
8,637
|
|
Fair value of business acquired
|
|
$
|
40,673
|
|
Assets acquired and liabilities assumed are as follows:
|
|
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
|
|
|
65,114
|
|
Unproved
|
|
|
1,495
|
|
Other property, plant, and equipment, net
|
|
|
877
|
|
Other non-current assets
|
|
|
475
|
|
Accounts payable and accrued liabilities
|
|
|
(6,054
|
)
|
Commodity derivative liability - current
|
|
|
(916
|
)
|
Commodity derivative liability - non-current
|
|
|
(1,729
|
)
|
Asset retirement obligations - current
|
|
|
(384
|
)
|
Asset retirement obligations - non-current
|
|
|
(2,537
|
)
|
Subordinated Notes, related party, net
|
|
|
(8,874
|
)
|
Senior Revolving Notes, related party
|
|
|
(11,000
|
)
|
Notes payable
|
|
|
(92
|
)
|
Total net assets acquired
|
|
$
|
40,673
|
|
During the 4
th
Quarter of 2018,
the Company finalized the determination of fair value and purchase price allocation related to the Carbon California Acquisition.
Based on the final valuation received, the allocation of fair value exceeded the consideration by $8.6 million, which has been
reflected in equity as a capital contribution from Yorktown who held a significant membership interest in CCC and is the Company’s
largest shareholder (see Note 17).
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
On May 1, 2018, Carbon California acquired
approximately 309 oil wells and approximately 6,800 gross acres (6,600 net) of oil and gas leases, and fee interests in and to
certain lands, situated in the Ventura Basin, together with associated pipelines, facilities, equipment and other property rights
from Seneca Resources Corporation (“
Seneca Acquisition
”). The transaction closed on May 1, 2018 for a purchase
price of $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. We raised our $5.0 million through the issuance of 50,000 shares
of Preferred Stock to Yorktown. Prudential also contributed $5.0 million to fund its share of the equity portion of the purchase
price. 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.
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 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 and other property, plant and equipment acquired, and accounts payable and liabilities assumed, required significant
judgement, including estimates relating to the production assets and the other transaction costs. We recorded $5.1 million in
Asset Retirement Obligation (“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 proved oil and gas properties, net on the balance sheet. Below
is the summary of the identifiable assets acquired (in thousands):
|
|
Amount
(in thousands)
|
|
Identifiable assets acquired:
|
|
|
|
Proved oil and gas properties
|
|
$
|
38,021
|
|
Unproved oil and gas properties
|
|
|
100
|
|
Other property, plant and equipment
|
|
|
588
|
|
Other assets
|
|
|
167
|
|
Total identified assets
|
|
$
|
38,876
|
|
Consolidation of Carbon California and
Seneca Acquisition Unaudited Pro Forma Results of Operations
Below are unaudited consolidated results
of operations for the twelve months ended December 31, 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 year ended December
31, 2018, includes the Carbon California Acquisition results of operations for the period February 1, 2018 through December 31,
2018, inclusive of the Seneca Acquisition results of operations for the period May 1, 2018 through December 31, 2018.
|
|
Unaudited Pro Forma
Consolidated Results
For Year Ended
December 31,
|
|
(in thousands, except per share amounts)
|
|
2018
|
|
|
2017
|
|
Revenue
|
|
$
|
33,256
|
|
|
$
|
35,122
|
|
Net (loss) income before non-controlling interests
|
|
|
5,232
|
|
|
|
13,969
|
|
Net (loss) income attributable to non-controlling interests
|
|
|
(2,334
|
)
|
|
|
92
|
|
Net (loss) income attributable to controlling interests
|
|
$
|
7,566
|
|
|
$
|
13,877
|
|
Net income per share (basic)
|
|
$
|
1.00
|
|
|
$
|
2.49
|
|
Net income per share (diluted)
|
|
$
|
0.96
|
|
|
$
|
2.14
|
|
Liberty Acquisition
On July 11, 2018, we completed an acquisition
of 54 operated oil and gas wells covering approximately 55,000 gross acres (22,000 net) and the associated mineral interests in
the Appalachian Basin for a purchase price of $3.0 million, subject to customary and standard purchase price adjustments (the “
Liberty
Acquisition
”). The Liberty Acquisition increased our working interest in the acquired wells from 60% to 100%. The
Liberty Acquisition was funded through borrowings under our previous credit facility. The Liberty Acquisition is accounted for
as a non-significant asset acquisition.
Majority Control of Carbon Appalachia
On December 16, 2016, Carbon Appalachia
was formed by us, entities managed by Yorktown and entities managed by Old Ironsides to acquire producing assets in the Appalachian
Basin in Kentucky, Tennessee, Virginia and West Virginia. Carbon Appalachia began substantial operations on April 3, 2017 and is
engaged primarily in acquiring, developing, exploiting, producing, processing, marketing, and transporting oil and natural gas
in the Appalachia Basin.
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, 2018. Carbon Appalachia
(i) issued Class A Units to us, Yorktown and Old Ironsides for an aggregate cash consideration of $12.0 million, (ii) issued Class
B Units to us, and (iii) issued Class C Units to us. 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.
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 our 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 us
acquiring 2,940 Class A Units from Yorktown.
On August 15, 2017, the Carbon Appalachia
LLC Agreement was amended and, as a result, we agreed to contribute an initial commitment of future capital contributions as well
as Yorktown’s, and Yorktown will not participate in future capital contributions. Carbon Appalachia issued Class A Units
to us 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 September 29, 2017, Carbon Appalachia
issued Class A Units to us and Old Ironsides for an aggregate cash consideration of $11.0 million.
Prior to the closing of the OIE Membership
Acquisition, Old Ironsides held 27,195 Class A Units, which equated to a 72.76% aggregate share ownership of Carbon Appalachia
and we held (i) 9,805 Class A Units, (ii) 1,000 Class B Units and (iii) 121 Class C Units, which equated to a 27.24% aggregate
share ownership of Carbon Appalachia.
On December 31, 2018, we acquired all of
Old Ironsides Class A Units of Carbon Appalachia for approximately $58.1 million, subject to certain closing adjustments. We paid
$33.0 million in cash and delivered promissory notes in the aggregate original principal amount of approximately $25.1 million
to Old Ironsides (the “Old Ironsides Notes”). The Old Ironsides Notes bear interest at 10% per annum and have a term
of five years, the first three of which require interest-only payments at the end of each calendar quarter beginning with the quarter
ending March 31, 2019. At the end of the three-year interest-only period, the then current outstanding principal balance and interest
is to be paid in 24 equal monthly payments. The Old Ironsides Notes also provide for mandatory prepayments upon the occurrence
of certain subsequent liquidity events and a one-time principal reduction payment in the aggregate amount of $2.0 million on or
before February 1, 2019. The $2.0 million payment was made to Old Ironsides on February 1, 2019.
The Old Ironsides Acquisition is accounted
for as a business combination in accordance with ASC 805,
Business Combinations
(“ASC 805”). We recognized 100%
of the identifiable assets acquired and liabilities assumed at their respective fair value as of the date of the acquisition. The
$58.1 million purchase price was paid for OIE’s outstanding interest, representing approximately 72.76% interest in Carbon
Appalachia.
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.
We followed the fair value method to allocate
the consideration transferred to the identifiable net assets acquired on a preliminary basis as follows:
|
|
Amount
(in thousands)
|
|
Cash consideration
|
|
$
|
33,000
|
|
Old Ironsides Notes
|
|
|
25,065
|
|
Fair value of previously held equity interest
|
|
|
14,158
|
|
Fair value of business acquired
|
|
$
|
72,223
|
|
Assets acquired and liabilities assumed are as follows:
|
|
Amount
(in thousands)
|
|
Cash
|
|
$
|
12,283
|
|
Accounts receivable:
|
|
|
|
|
Revenue
|
|
|
12,834
|
|
Trade receivable
|
|
|
1,941
|
|
Commodity derivative asset
|
|
|
198
|
|
Inventory
|
|
|
900
|
|
Prepaid expenses, deposits, and other current assets
|
|
|
456
|
|
Oil and gas properties:
|
|
|
|
|
Proved
|
|
|
107,499
|
|
Unproved
|
|
|
1,869
|
|
Other property, plant and equipment, net
|
|
|
15,626
|
|
Other non-current assets
|
|
|
514
|
|
Accounts payable and accrued liabilities
|
|
|
(19,114
|
)
|
Due to related parties
|
|
|
(458
|
)
|
Firm transportation contract obligations
|
|
|
(18,724
|
)
|
Asset retirement obligations
|
|
|
(5,626
|
)
|
Notes payable
|
|
|
(37,975
|
)
|
Total net assets acquired
|
|
$
|
72,223
|
|
The preliminary fair value of the assets
acquired and liabilities assumed were determined using various valuation techniques, including an income approach.
On the date of the acquisition, we derecognized
our equity investment in Carbon Appalachia and recognized a gain of approximately $1.3 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 Appalachia 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 Company used the income approach and made market assumptions as to
projections of utilization, future operating costs and a market participant weighted average costs of capital to determine the
fair value of the firm transportation obligations as well as the plant facilities. The determination of the fair value of accounts
payable and accrued liabilities assumed required significant judgement, including estimates relating to production assets.
Consolidation of Carbon Appalachia and
OIE Membership Acquisition Unaudited Pro Forma Results of Operations
Below are unaudited consolidated results
of operations for the twelve months ended December 31, 2018 and for the period of April 3, 2017 (inception) through December 31,
2017, as though the OIE Membership Acquisition had been completed as of April 3, 2017.
|
|
For Year Ended December 31,
|
|
|
For the period of April 3, 2017 (inception) through December 31,
|
|
(in thousands, except per share amounts)
|
|
2018
|
|
|
2017
|
|
Revenue
|
|
$
|
136,592
|
|
|
$
|
54,058
|
|
Net (loss) income before non-controlling interests
|
|
|
11,320
|
|
|
|
7,208
|
|
Net (loss) income attributable to non-controlling interests
|
|
|
4,375
|
|
|
|
81
|
|
Net (loss) income attributable to controlling interests
|
|
$
|
5,596
|
|
|
|
7,127
|
|
Net income per share (basic)
|
|
$
|
0.74
|
|
|
|
1.26
|
|
Net income per share (diluted)
|
|
$
|
0.69
|
|
|
|
0.62
|
|
Note 5 – Property, Plant and
Equipment
Net property, plant and equipment at December 31, 2018 and 2017
consists of the following:
(in thousands)
|
|
As of December 31,
|
|
|
|
2018
|
|
|
2017
|
|
|
|
|
|
|
|
|
Oil and gas properties:
|
|
|
|
|
|
|
|
|
Proved oil and gas properties
|
|
$
|
347,059
|
|
|
$
|
114,893
|
|
Unproved properties not subject to depletion
|
|
|
5,416
|
|
|
|
1,947
|
|
Accumulated depreciation, depletion, amortization and impairment
|
|
|
(98,604
|
)
|
|
|
(80,715
|
)
|
Net oil and gas properties
|
|
|
253,871
|
|
|
|
36,125
|
|
|
|
|
|
|
|
|
|
|
Pipeline facilities and equipment
|
|
|
12,714
|
|
|
|
-
|
|
Base gas
|
|
|
2,122
|
|
|
|
-
|
|
Furniture and fixtures, computer hardware and software, and other equipment
|
|
|
6,649
|
|
|
|
1,758
|
|
Accumulated depreciation and amortization
|
|
|
(3,922
|
)
|
|
|
(1,021
|
)
|
Net other property, plant and equipment
|
|
|
17,563
|
|
|
|
737
|
|
|
|
|
|
|
|
|
|
|
Total property, plant and equipment, net
|
|
$
|
271,434
|
|
|
$
|
36,862
|
|
We had approximately $5.4 million and $1.9
million, at December 31, 2018 and 2017, respectively, of unproved oil and gas properties not subject to depletion. At December
31, 2018 and 2017, our unproved properties consist principally of leasehold acquisition costs in the following areas:
|
|
As of December 31,
|
|
(in thousands)
|
|
2018
|
|
|
2017
|
|
|
|
|
|
|
|
|
Ventura Basin:
|
|
|
|
|
|
|
|
|
California
|
|
$
|
1,595
|
|
|
$
|
-
|
|
Illinois Basin:
|
|
|
|
|
|
|
|
|
Indiana
|
|
|
432
|
|
|
|
432
|
|
Illinois
|
|
|
136
|
|
|
|
136
|
|
Appalachian Basin:
|
|
|
|
|
|
|
|
|
Kentucky
|
|
|
920
|
|
|
|
915
|
|
Ohio
|
|
|
66
|
|
|
|
66
|
|
Tennessee
|
|
|
1,869
|
|
|
|
-
|
|
West Virginia
|
|
|
398
|
|
|
|
398
|
|
|
|
|
|
|
|
|
|
|
Total unproved properties not subject to depletion
|
|
$
|
5,416
|
|
|
$
|
1,947
|
|
During the year ended December 31, 2018,
there were no leasehold costs reclassified into proved property.
During the year ended December 31, 2017,
expiring leasehold costs reclassified into proved property were approximately $52,000. 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
and exploration activities of approximately $337,000 and $66,000 for the years ended December 31, 2018 and 2017, respectively.
Depletion expense related to oil and gas
properties for the years ended December 31, 2018 and 2017 was approximately $7.3 million and $2.2 million or $0.89 and $0.40 per
Mcfe, respectively. Depreciation expense related to furniture and fixtures, computer hardware and software and other equipment
for the years ended December 31, 2018 and 2017 was approximately $803,000 and $387,000, respectively.
Note 6 - Investments in Affiliates
The following table outlines the changes
in our investments in affiliates:
(in thousands)
|
|
Carbon California
|
|
|
Carbon Appalachia
|
|
|
Other
|
|
|
Total
|
|
Balance, December 31, 2016
|
|
$
|
-
|
|
|
$
|
-
|
|
|
$
|
668
|
|
|
$
|
668
|
|
Investment in affiliates gain
|
|
|
-
|
|
|
|
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
|
|
|
$
|
638
|
|
|
$
|
14,267
|
|
Investment in affiliates gain
|
|
|
-
|
|
|
|
1,026
|
|
|
|
85
|
|
|
|
1,111
|
|
Cash distributions
|
|
|
-
|
|
|
|
-
|
|
|
|
(125
|
)
|
|
|
(125
|
)
|
California Warrant exercise
|
|
|
(1,854
|
)
|
|
|
-
|
|
|
|
|
|
|
|
(1,854
|
)
|
OIE Membership Acquisition
|
|
|
|
|
|
|
(12,801
|
)
|
|
|
|
|
|
|
(12,801
|
)
|
Balance, December 31, 2018
|
|
$
|
-
|
|
|
$
|
-
|
|
|
$
|
598
|
|
|
$
|
598
|
|
Carbon California
For the period February 15, 2017 (inception)
through January 31, 2018, based on our 17.81% 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.
Effective February 1, 2018, upon the exercise
of the California Warrant, we consolidate Carbon California in our consolidated financial statements (see Note 4).
The following table sets forth, selected
historical financial data for Carbon California.
(in thousands)
|
|
As of December 31, 2018
|
|
|
As of December 31, 2017
|
|
Current assets
|
|
$
|
11,829
|
|
|
$
|
3,968
|
|
Total oil and gas properties, net
|
|
|
84,825
|
|
|
|
43,458
|
|
Non-current assets
|
|
|
89,173
|
|
|
|
44,759
|
|
Current liabilities
|
|
|
6,773
|
|
|
|
6,899
|
|
Non-current liabilities
|
|
|
56,664
|
|
|
|
23,279
|
|
Total members’ equity
|
|
|
37,565
|
|
|
|
18,549
|
|
(in thousands)
|
|
Year Ended December 31,
2018
|
|
|
Period February 15,
2017 (inception)
through December 31,
2017
|
|
Revenues
|
|
$
|
32,317
|
|
|
$
|
7,235
|
|
Operating expenses
|
|
|
20,057
|
|
|
|
9,893
|
|
Income (loss) from operations
|
|
|
12,260
|
|
|
|
(2,658
|
)
|
Net income (loss)
|
|
|
8,526
|
|
|
|
(6,552
|
)
|
Carbon Appalachia
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”).
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
|
%
|
December 2018
|
|
OIE Membership Acquisition
|
|
|
100
|
%
|
|
|
100
|
%
|
Based on our 27.24% combined Class A, Class
B and Class C interest (and our ability as of December 31, 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 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 year ended December 31, 2018, Carbon Appalachia incurred a net gain, of which our share is approximately $1.0 million.
For the period of April 3, 2017 (inception) through December 31, 2017, Carbon Appalachia incurred a net gain, of which our share
is approximately $1.1 million.
On December 31, 2018, we acquired all of
Old Ironsides Class A Units of Carbon Appalachia for approximately $58.1 million, subject to certain closing adjustments. We paid
$ 33.0 million in cash and issued the Old Ironsides Notes in the aggregate original principal amount of approximately $25.1 million
to Old Ironsides.
Effective December 31, 2018, upon the closing
of the OlE Membership Acquisition, we consolidate Carbon Appalachia in our consolidated financial statements. See Note 4.
The following table sets forth, selected
historical financial data for Carbon Appalachia.
(in thousands)
|
|
As of December 31, 2018
|
|
|
As of December 31, 2017
|
|
Current assets
|
|
$
|
28,613
|
|
|
$
|
20,794
|
|
Total oil and gas properties, net
|
|
|
80,674
|
|
|
|
84,402
|
|
Non-current assets
|
|
|
96,814
|
|
|
|
97,762
|
|
Current liabilities
|
|
|
22,126
|
|
|
|
18,207
|
|
Non-current liabilities
|
|
|
58,480
|
|
|
|
59,420
|
|
Total members’ equity
|
|
|
44,821
|
|
|
|
40,929
|
|
(in thousands)
|
|
Year Ended December 31,
2018
|
|
|
Period April 3,
2017 (inception) through December 31,
2017
|
|
Revenues
|
|
$
|
83,541
|
|
|
$
|
31,584
|
|
Operating expenses
|
|
|
77,084
|
|
|
|
26,764
|
|
Income from operations
|
|
|
6,457
|
|
|
|
4,820
|
|
Net income
|
|
|
4,053
|
|
|
|
3,005
|
|
Note 7 – Credit Facilities
and Notes Payable
The table below summarizes the outstanding
credit facilities and notes payable as of December 31, 2018 (in thousands):
2018 Credit Facility – revolver
|
|
$
|
69,150
|
|
2018 Credit Facility – term note
|
|
|
15,000
|
|
Old Ironsides Notes
|
|
|
25,065
|
|
Non-current debt
|
|
|
57
|
|
Total gross notes payable
|
|
|
109,272
|
|
Less: Notes discount
|
|
|
(134
|
)
|
Total net notes payable
|
|
$
|
109,138
|
|
The table below summarizes the outstanding
notes payable – related party as of December 31, 2018 (in thousands):
Senior Revolving Notes, related party, due February 15, 2022
|
|
$
|
38,500
|
|
Subordinated Notes, related party, due February 15, 2024
|
|
|
13,000
|
|
Total gross notes payable
|
|
|
51,500
|
|
Less: Deferred notes costs
|
|
|
156
|
|
Less: Notes discount
|
|
|
(1,737
|
)
|
Total net notes payable
|
|
$
|
49,919
|
|
2018 Credit Facility
In connection with and concurrently with
the closing of the OIE Membership Acquisition, the Company and its subsidiaries amended and restated the Credit Facility and the
CAE Credit Facility which provides for a $500.0 million senior secured asset-based revolving credit facility (the
“2018
Credit Facility”)
which matures December 31, 2022 and a $15.0 million term loan which matures in 2020. The 2018 Credit
Facility includes a sublimit of $1.5 million for letters of credit. The borrowers under the 2018 Credit Facility are CAE and various
other subsidiaries of the Company (including Nytis Exploration (USA) Inc., the Company’s wholly-owned subsidiary
(“Nytis
USA”
and together with CAE the
“Borrowers”
). Under the 2018 Credit Facility, Carbon Energy
Corporation is neither a borrower nor a guarantor. The initial borrowing base under the 2018 Credit Facility is $75.0 million.
The 2018 Credit Facility is guaranteed
by each existing and future direct or indirect subsidiaries of the Borrowers and certain other subsidiaries of the Company (subject
to various exceptions) and the obligations under the 2018 Credit Facility are secured by essentially all tangible, intangible and
real property (subject to certain exclusions).
Interest accrues on borrowings under the
2018 Credit Facility at a rate per annum equal to either (i) the base rate plus an applicable margin equal to 0.25% - 0.75% depending
on the utilization percentage or (ii) the Adjusted LIBOR rate plus an applicable margin equal to 2.75% - 3.75% depending on the
utilization percentage, at the Borrowers’ option. The Borrowers are obligated to pay certain fees and expenses in connection
the 2018 Credit Facility, including a commitment fee for any unused amounts of 0.50% and an origination fee of 0.50%. Loans under
the 2018 Credit Facility may be prepaid without premium or penalty.
The 2018 Credit Facility also provides
for a $15.0 million term loan which bears interest at a rate of 6.25% and is payable in 18 equal monthly installments beginning
February 1, 2019 with the last payment due on June 30, 2020.
The 2018 Credit Facility contains certain
affirmative and negative covenants that, among other things, limit the Company’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 distribution on, or repurchase of, equity; (vi) make certain investments; (vii) enter into certain transactions
with their affiliates; (viii) enter in sale-leaseback transactions; (ix) make optional or voluntary payment of debt other than
obligations under the 2018 Credit Facility; (x) change the nature of their business; (xi) change their fiscal year or make changes
to the accounting treatment or reporting practices; (xii) amend their 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 2018 Credit
Facility requires the Borrower’s compliance, on a consolidated basis, with a maximum Net Debt (all debt of the Borrowing
Parties minus all unencumbered cash and cash equivalents of the Borrowers not to exceed $3.0 million) / EBITDAX (as defined) ratio
of 3.50 to 1.00 and a current ratio minimum of 1.00 to 1.00, tested quarterly, commencing with the quarter ending March 31, 2019.
We expect to be in compliance with these covenants throughout the next twelve month period.
Fees paid in connection with the 2018 Credit
Facility included origination fees of $450,000 and arrangement fees of $80,000. As of December 31, 2018, there was approximately
$70.0 million in outstanding borrowings and letters of credit and $5.0 million of additional borrowing capacity under the 2018
Credit Facility.
The terms of the 2018 Credit Facility require
us to enter 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 into by us and BP
Energy Company is secured by the collateral and backed by the guarantees supporting the 2018 Credit Facility.
We incurred fees of approximately $962,000
directly associated with the issuance of our previous credit facility and amortized these fees over the life of the credit facility.
The unamortized amount of fees associated with the previous credit facility was written off on December 31, 2018 in connection
with the amendment. The current portion of unamortized fees is included in prepaid expense, deposits and other current assets and
the non-current portion is included in other non-current assets. As of December 31, 2017, we had unamortized deferred issuance
costs of $484,000 associated with the previous credit facility. During the years ended December 31, 2018 and 2017, we amortized
approximately $786,000 and $176,000, respectively, as interest expense associated with the previous credit facility.
Old Ironsides Notes
On December 31, 2018, as part of the OIE
Membership Acquisition, we delivered unsecured, promissory notes in the aggregate original principal amount of approximately $25.1
million to Old Ironsides (the “
Old Ironsides Notes
”). The Old Ironsides Notes bear interest at 10% per
annum and have a term of five years, the first three of which require interest-only payments at the end of each calendar quarter
beginning with the quarter ending March 31, 2019. At the end of the three-year interest-only period, the then current outstanding
principal balance and interest is to be paid in 24 equal monthly payments. The Old Ironsides Notes also require mandatory prepayments
upon the occurrence of certain subsequent liquidity events and a one-time principal reduction payment in the aggregate amount
of $2.0 million on or before February 1, 2019. Subsequent to the closing of the OIE Membership Acquisition Old Ironsides ceased
to be a related party.
Carbon California – Credit
Facilities
Effective as of February 1, 2018, our ownership
in Carbon California increased to 56.41% 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 53.9% of
the voting and profits interests, and Prudential owns 46.08% voting and profit interest in Carbon California.
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 December 31, 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 the Prime Rate (which is defined
as the interest rate published daily by JPMorgan Chase Bank, N.A.). As of December 31, 2018, the effective borrowing rate for the
Senior Revolving Notes was 7.39%. 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 anticipated proved developed 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 non-current
assets for a combined value of approximately $900,000. For the year ended December 31, 2018, Carbon California amortized fees of
$217,000.
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 December 31, 2018, Carbon California was in compliance with its financial covenants.
2017 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, of which $10.0 million remains outstanding as of December 31, 2018.
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 December 31, 2018, Carbon California has an outstanding
discount of $1.7 million, which is presented net of the Subordinated Notes within Credit facility-related party on the 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
available after February 15, 2019. Prepayment is allowed at 100%, subject to a 3.0% fee of outstanding principal. Prepayment is
not subject to a prepayment 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 December 31, 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 in the amount of $3.0
million, of which $3.0 million remains outstanding as of December 31, 2018.
Prudential received 585 Class A Units,
representing an approximate 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 December 31, 2018, Carbon California had an outstanding discount of $390,000 associated with these notes, which is presented
net of the Carbon California 2018 Subordinated Notes within Credit facility – related party on the consolidated balance sheets.
During the year ended December 31, 2018, Carbon California amortized $57,000.
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 Subordinated Notes is
available after February 15, 2019. Prepayment is allowed at 100%, subject to a 3.0% fee of outstanding principal. Prepayment is
not subject to a prepayment fee after February 17, 2020. 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 December 31, 2018, Carbon California was in compliance
with its financial covenants.
Note 8 - Income Taxes
The provision for income taxes for the
years ended December 31, 2018 and 2017 consists of the following:
(in thousands)
|
|
For the Year Ended
|
|
|
|
December 31,
|
|
|
|
2018
|
|
|
2017
|
|
|
|
|
|
|
|
|
Current income tax benefit
|
|
$
|
-
|
|
|
$
|
(74
|
)
|
Deferred income tax (benefit) expense
|
|
|
(260
|
)
|
|
|
7,080
|
|
Change in valuation allowance
|
|
|
260
|
|
|
|
(7,080
|
)
|
|
|
|
|
|
|
|
|
|
Total income tax benefit
|
|
$
|
-
|
|
|
$
|
(74
|
)
|
The effective income tax rate for the years
ended December 31, 2018 and 2017 differed from the statutory U.S. federal income tax rate as follows:
|
|
For the Year Ended
|
|
|
|
December 31,
|
|
|
|
2018
|
|
|
2017
|
|
|
|
|
|
|
|
|
Federal income tax rate
|
|
|
21.0
|
%
|
|
|
35.0
|
%
|
State income taxes, net of federal benefit
|
|
|
5.1
|
|
|
|
3.8
|
|
Permanent differences
|
|
|
(1.2
|
)
|
|
|
(20.5
|
)
|
Non-controlling interest in consolidated partnerships
|
|
|
(9.8
|
)
|
|
|
(0.8
|
)
|
True-up of prior year depletion in excess of basis
|
|
|
1.3
|
|
|
|
1.1
|
|
Stock-based compensation deficiency
|
|
|
1.1
|
|
|
|
3.1
|
|
Rate changes of prior year deferred
|
|
|
(1.0
|
)
|
|
|
(1.8
|
)
|
True-up of prior year deferred
|
|
|
4.0
|
|
|
|
(4.5
|
)
|
Effect of tax cuts and TCJA
|
|
|
-
|
|
|
|
91.0
|
|
Increase in valuation allowance and other
|
|
|
2.0
|
|
|
|
(107.7
|
)
|
|
|
|
|
|
|
|
|
|
Total effective income tax rate
|
|
|
22.5
|
%
|
|
|
(1.1
|
)%
|
The tax effects of temporary differences
that gave rise to significant portions of the deferred tax assets and liabilities at December 31, 2018 and 2017 are presented below:
(in thousands)
|
|
As of December 31,
|
|
|
|
2018
|
|
|
2017
|
|
|
|
|
|
|
|
|
Deferred tax assets
|
|
|
|
|
|
|
|
|
Net operating loss carryforwards
|
|
$
|
8,066
|
|
|
$
|
6,407
|
|
Depletion carryforwards
|
|
|
2,185
|
|
|
|
1,934
|
|
Accrual and other
|
|
|
863
|
|
|
|
450
|
|
Stock-based compensation
|
|
|
449
|
|
|
|
476
|
|
Asset retirement obligations
|
|
|
4,640
|
|
|
|
1,944
|
|
Property, plant and equipment
|
|
|
2,340
|
|
|
|
2,972
|
|
Total deferred tax assets
|
|
|
18,543
|
|
|
|
14,183
|
|
|
|
|
|
|
|
|
|
|
Deferred tax liability
|
|
|
|
|
|
|
|
|
Interest in partnerships
|
|
|
(517
|
)
|
|
|
(790
|
)
|
Derivative and other
|
|
|
(1,056
|
)
|
|
|
(57
|
)
|
|
|
|
|
|
|
|
|
|
Less valuation allowance
|
|
|
(16,970
|
)
|
|
|
(13,336
|
)
|
|
|
|
|
|
|
|
|
|
Net deferred tax asset
|
|
$
|
-
|
|
|
$
|
-
|
|
The Company has net operating losses (“NOL”)
of approximately $29.2 million available to reduce future years’ federal taxable income. The federal net operating losses
generated before 2018 expire beginning in 2031 through 2037. While the 2018 net operating loss will never expire, it is available
to offset only 80% of future years’ federal taxable income. The Company has 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 will expire beginning in 2023 through 2037 depending
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.
The Company believes that the tax positions
taken in the Company’s tax returns satisfy the more likely than not threshold for benefit recognition. Accordingly, no liabilities
have been recorded by the Company. Any potential adjustments for uncertain tax positions would be a reclassification between the
deferred tax asset related to the Company’s NOL and another deferred tax asset.
The Company’s policy is to classify
accrued penalties and interest related to unrecognized tax benefits in the Company’s income tax provision. As of December
31, 2017, the Company 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 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, the Company had made reasonable
estimates of the effects on its existing deferred tax balances. The Company 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 twenty one 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.
The Company will continue to analyze the
TCJA and future IRS regulations, refine its 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.
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. On June 1, 2018, we amended our charter to increase the
number of authorized shares of our common stock from 10,000,000 to 35,000,000.
As of December 31, 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 preferred stock for $5.0 million.
During the year ended December 31, 2018, the increase in our issued and outstanding common stock is primarily due to (a) Yorktown’s
exercise of the California Warrant (see Note 4), 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, net of shares exchanged for payroll tax obligations paid by
us, 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, 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. The
following table shows a summary of our unvested restricted stock under the Carbon Plans as of December 31, 2018 and 2017 as well
as activity during the years then ended.
|
|
|
|
|
Weighted Avg
|
|
|
|
Number
|
|
|
Grant Date
|
|
|
|
of Shares
|
|
|
Fair Value
|
|
Restricted stock awards, unvested, January 1, 2017
|
|
|
267,750
|
|
|
$
|
7.78
|
|
|
|
|
|
|
|
|
|
|
Granted
|
|
|
81,050
|
|
|
|
7.20
|
|
|
|
|
|
|
|
|
|
|
Vested
|
|
|
(65,753
|
)
|
|
|
8.38
|
|
|
|
|
|
|
|
|
|
|
Forfeited
|
|
|
(13,050
|
)
|
|
|
6.19
|
|
|
|
|
|
|
|
|
|
|
Restricted stock awards, unvested, December 31, 2017
|
|
|
269,997
|
|
|
$
|
7.54
|
|
|
|
|
|
|
|
|
|
|
Granted
|
|
|
106,000
|
|
|
|
9.820
|
|
|
|
|
|
|
|
|
|
|
Vested
|
|
|
(59,550
|
)
|
|
|
6.82
|
|
|
|
|
|
|
|
|
|
|
Forfeited
|
|
|
(2,240
|
)
|
|
|
7.41
|
|
|
|
|
|
|
|
|
|
|
Restricted stock awards, unvested, December 31, 2018
|
|
|
314,207
|
|
|
$
|
8.40
|
|
Compensation costs recognized for these
restricted stock grants were approximately $725,000 and $664,000 for the years ended December 31, 2018 and 2017, respectively.
As of December 31, 2018, there was approximately $1.4 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, 2018 and 2017 as well as activity during the years then ended.
|
|
Number
|
|
|
|
of Shares
|
|
Restricted performance units, unvested, January 1, 2017
|
|
|
296,311
|
|
|
|
|
|
|
Granted
|
|
|
60,050
|
|
|
|
|
|
|
Vested
|
|
|
(80,000
|
)
|
|
|
|
|
|
Forfeited
|
|
|
(17,550
|
)
|
|
|
|
|
|
Restricted performance units, unvested, December 31, 2017
|
|
|
258,811
|
|
|
|
|
|
|
Granted
|
|
|
136,159
|
|
|
|
|
|
|
Vested
|
|
|
(108,484
|
)
|
|
|
|
|
|
Forfeited
|
|
|
(6,610
|
)
|
|
|
|
|
|
Restricted performance units, unvested, December 31, 2018
|
|
|
279,876
|
|
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 December 31, 2018, we estimated that none of the performance units granted in 2018 and 2017 would vest, and, accordingly,
no compensation cost has been recorded for these performance units. 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 $442,000 related to these performance
units were recognized for the years ended December 31, 2018 and 2017, respectively. During 2018, we estimated that it was probable
that the performance units granted in 2016 would vest and therefore compensation costs of approximately $273,000 were recognized,
As of December 31, 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 unvested performance units would be approximately
$3.0 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 a preferred return
over common stock holders and the holders of any junior ranking stock. As of December 31, 2018, the preferred return was approximately
$224,000.
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 December 31, 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 December 31, 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.
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 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 third party purchasers. We recognize revenue based on the net proceeds received from the purchaser when
control of the oil or natural gas passes to the purchaser. For oil sales, control is typically transferred to the purchaser upon
receipt at the wellhead or a contractually agreed upon delivery point. Under our natural gas contracts with purchasers, control
transfers upon delivery at the wellhead or the inlet of the purchaser’s system. For our other natural gas contracts, control
transfers upon delivery to the inlet or to a contractually agreed upon delivery point.
Transfer of control drives the presentation
of transportation and gathering costs within the accompanying 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
consolidated statements of operations, while transportation and gathering costs incurred subsequent to control transfer are recognized
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
year ended December 31, 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
|
|
Appalachian and Illinois Basin
|
|
|
Ventura Basin
|
|
|
Total
|
|
Natural gas sales
|
|
$
|
14,768
|
|
|
$
|
1,250
|
|
|
$
|
16,018
|
|
Natural gas liquids sales
|
|
|
-
|
|
|
|
1,143
|
|
|
|
1,143
|
|
Oil sales
|
|
|
4,963
|
|
|
|
25,928
|
|
|
|
30,891
|
|
Total natural gas, natural gas liquids, and oil revenue
|
|
$
|
19,731
|
|
|
$
|
28,321
|
|
|
$
|
48,052
|
|
In the following table, revenue for the
year ended December 31, 2017, 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
|
|
Appalachian and Illinois Basin
|
|
|
Ventura Basin
|
|
|
Total
|
|
Natural gas sales
|
|
$
|
15,298
|
|
|
$
|
-
|
|
|
$
|
15,298
|
|
Oil sales
|
|
|
4,213
|
|
|
|
-
|
|
|
|
4,213
|
|
Total natural gas and oil revenue
|
|
$
|
19,511
|
|
|
$
|
-
|
|
|
$
|
19,511
|
|
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
year ended December 31, 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 consolidated balance sheets.
Note 11 - Accounts Payable and Accrued
Liabilities
Accounts payable and accrued liabilities
at December 31, 2018 and 2017 consist of the following:
(in thousands)
|
|
|
|
|
|
|
|
|
As of December 31,
|
|
|
|
2018
|
|
|
2017
|
|
|
|
|
|
|
|
|
Accounts payable
|
|
$
|
7,670
|
|
|
$
|
3,274
|
|
Oil and gas revenue suspense
|
|
|
2,675
|
|
|
|
1,776
|
|
Gathering and transportation payables
|
|
|
1,774
|
|
|
|
497
|
|
Production taxes payable
|
|
|
1,860
|
|
|
|
214
|
|
Drilling advances received from joint venture partner
|
|
|
-
|
|
|
|
245
|
|
Accrued lease operating costs
|
|
|
3,155
|
|
|
|
684
|
|
Accrued ad valorem taxes-current
|
|
|
3,474
|
|
|
|
1,054
|
|
Accrued general and administrative expenses
|
|
|
3,111
|
|
|
|
2,473
|
|
Accrued asset retirement obligation-current
|
|
|
3,099
|
|
|
|
380
|
|
Accrued interest
|
|
|
955
|
|
|
|
247
|
|
Accrued gas purchases
|
|
|
5,441
|
|
|
|
-
|
|
Other liabilities
|
|
|
1,603
|
|
|
|
374
|
|
|
|
|
|
|
|
|
|
|
Total accounts payable and accrued liabilities
|
|
$
|
34,816
|
|
|
$
|
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
|
|
December 31, 2018
|
|
|
|
|
|
|
|
|
|
|
|
|
Asset:
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivatives
|
|
$
|
-
|
|
|
$
|
7,022
|
|
|
$
|
-
|
|
|
$
|
7,022
|
|
December 31, 2017
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Asset:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity
derivatives
|
|
$
|
-
|
|
|
$
|
225
|
|
|
$
|
-
|
|
|
$
|
225
|
|
Liability:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Warrant derivative liability
|
|
$
|
-
|
|
|
$
|
-
|
|
|
$
|
2,017
|
|
|
$
|
2,017
|
|
Commodity Derivative
As of December 31, 2018, our commodity
derivative financial instruments are comprised of fifteen natural gas swaps, twenty-eight oil swap, and eight natural gas costless
collar agreements. As of December 31, 2017, our commodity derivative financial instruments were comprised of eight natural gas
swaps, eight oil swaps, and one natural gas costless collar 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, 2018 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. The California Warrant was exercised on February
1, 2018; therefore, the warrant liability was extinguished.
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
|
|
Unrealized (gain) included in warrant gain
|
|
|
(225
|
)
|
|
|
-
|
|
|
|
(225
|
)
|
Settlement of warrant liability
|
|
|
(1,792
|
)
|
|
|
-
|
|
|
|
(1,792
|
)
|
Balance, December 31, 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.
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. See Note 4 for the fair value of the
non-controlling interest in Carbon California.
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 contract 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.
The fair value measurements associated
with the assets acquired and liabilities assumed in the business combinations for the majority control of Carbon California and
OIE Membership Acquisition of Carbon Appalachia are outlined within Note 4.
Debt Discount
The fair value of the debt discount from the
1,425 and 585 additional Class A Units issued in connection with the Subordinated Notes and 2018 Subordinated Notes was $1.3 million
and $490,000, respectively. The debt discount was a Level 3 fair value assessment and was based on the relative fair value of
Class A Units. Class A Units were issued contemporaneously at $1,000 per Class A Units.
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 $45,000, 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 between 1.52% to 2.79%; and a credit adjusted risk-free rate between 3.28% to 8.27%, 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, 2018, we recorded additions to asset
retirement obligations of approximately $14.1 million, which was the result of the Carbon California, Seneca, Liberty, and OIE
Membership Acquisitions. 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 13 - 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. 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 facilities
with LegacyTexas Bank and Prudential, we have entered into swap and collar derivative agreements to hedge certain of our oil and
natural gas production through 2021. As of December 31, 2018, these derivative agreements consisted of the following:
|
|
Natural Gas Swaps
|
|
|
Natural Gas Collars (1)
|
|
|
Oil Swaps (1)
|
|
|
|
|
|
|
Weighted
|
|
|
|
|
|
Weighted
|
|
|
|
|
|
Weighted
|
|
|
|
|
|
Weighted
|
|
|
|
|
|
|
Average
|
|
|
|
|
|
Average Price
|
|
|
WTI
|
|
|
Average
|
|
|
Brent
|
|
|
Average
|
|
Year
|
|
MMBtu
|
|
|
Price (a)
|
|
|
MMBtu
|
|
|
Range (a)
|
|
|
Bbl
|
|
|
Price (b)
|
|
|
Bbl
|
|
|
Price (c)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2019
|
|
|
15,055,000
|
|
|
$
|
2.85
|
|
|
|
836,000
|
|
|
$
|
2.60 – $3.19
|
|
|
|
218,597
|
|
|
$
|
53.50
|
|
|
|
148,086
|
|
|
$
|
66.82
|
|
2020
|
|
|
12,433,000
|
|
|
$
|
2.73
|
|
|
|
1,018,000
|
|
|
$
|
2.50 – $2.70
|
|
|
|
121,147
|
|
|
$
|
55.37
|
|
|
|
151,982
|
|
|
$
|
66.03
|
|
2021
|
|
|
2,598,000
|
|
|
$
|
2.69
|
|
|
|
-
|
|
|
$
|
-
|
|
|
|
-
|
|
|
$
|
-
|
|
|
|
86,341
|
|
|
$
|
67.12
|
|
(1)
|
Includes 100% of Carbon California’s outstanding derivative hedges at December 31, 2018, and not our proportionate share.
|
(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 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,
|
|
|
|
2018
|
|
|
2017
|
|
Commodity derivative contracts:
|
|
|
|
|
|
|
|
|
Commodity derivative asset
|
|
$
|
3,517
|
|
|
$
|
215
|
|
Commodity derivative asset – non-current
|
|
$
|
3,505
|
|
|
$
|
10
|
|
The table below summarizes the commodity
settlements and unrealized gains and losses related to our derivative instruments for the years ended December 31, 2018 and 2017.
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,
|
|
|
|
2018
|
|
|
2017
|
|
Commodity derivative contracts:
|
|
|
|
|
|
|
Settlement (loss) gains
|
|
$
|
(3,848
|
)
|
|
$
|
770
|
|
Unrealized gains
|
|
|
8,742
|
|
|
|
2,158
|
|
|
|
|
|
|
|
|
|
|
Total settlement and unrealized gains, net
|
|
$
|
4,894
|
|
|
$
|
2,928
|
|
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 International Swaps and Derivatives Association (“ISDA”) Master
Agreements with BP Energy Company that establishes standard terms for the derivative contracts and inter-creditor agreements with
LegacyTexas Bank/Prudential 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 facilities.
We net our derivative instrument fair value
amounts executed with BP Energy Company pursuant to ISDA master agreements, 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, 2018.
|
|
|
|
|
|
|
|
|
|
Net
|
|
|
|
|
|
Gross
|
|
|
|
|
|
Recognized
|
|
|
|
|
|
Recognized
|
|
|
Gross
|
|
|
Fair Value
|
|
|
|
|
|
Assets/
|
|
|
Amounts
|
|
|
Assets/
|
|
|
|
Balance Sheet Classification
|
|
Liabilities
|
|
|
Offset
|
|
|
Liabilities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivative assets:
|
|
Commodity derivative
|
|
$
|
4,605
|
|
|
$
|
(1,088
|
)
|
|
$
|
3,517
|
|
|
|
Other non-current assets
|
|
|
4,690
|
|
|
|
(1,185
|
)
|
|
|
3,505
|
|
Total derivative assets
|
|
|
|
$
|
9,295
|
|
|
$
|
(2,273
|
)
|
|
$
|
7,022
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivative liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivative
|
|
$
|
(1,088
|
)
|
|
$
|
1,088
|
|
|
$
|
-
|
|
|
|
Commodity derivative: non-current
|
|
|
(1,185
|
)
|
|
|
1,185
|
|
|
|
-
|
|
Total derivative liabilities
|
|
|
|
$
|
(2,273
|
)
|
|
$
|
2,273
|
|
|
$
|
-
|
|
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 non-current 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 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 non-current 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, 2018 are summarized in the table below.
Period
|
|
Dekatherms per day
|
|
|
Demand Charges
|
|
January 2019 – March 2020
|
|
|
3,230
|
|
|
$
|
0.20 – 0.62
|
|
April 2020 – May 2020
|
|
|
2,150
|
|
|
$
|
0.20
|
|
June 2020 – May 2036
|
|
|
1,000
|
|
|
$
|
0.20
|
|
Jan 2019 – Oct 2020
|
|
|
6,300
|
|
|
$
|
0.21
|
|
Jan 2019 – Aug 2022
|
|
|
49,341
|
|
|
$
|
0.21 – 0.56
|
|
Sep 2022 – May 2027
|
|
|
29,990
|
|
|
$
|
0.21
|
|
As of December 31, 2018, the remaining
commitment related to the firm transportation contracts assumed in the EXCO Acquisition in 2016 and OIE Membership Acquisition
is $18.9 million and reflected in the Company’s 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 reduced monthly as the Company pays these firm transportation
obligations in the future.
Natural gas processing agreement
We have entered into an initial five-year
gas processing agreement. We have 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, 2018 are approximately $1.8 million per year. We
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.
Capital Commitment
As of December 31, 2018, we had no capital commitments associated
with Carbon California.
Note 15 - 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, 2018 and 2017, we contributed
approximately $441,000 and $175,000, respectively, for 401(k) contributions and related administrative expenses.
Note 16 - Supplemental Cash Flow
Disclosure
Supplemental cash flow disclosures are
presented below. Non-cash transaction items are primarily related to the consolidation of Carbon California and Carbon Appalachia
during the year ended December 31, 2018.
(in thousands)
|
|
For the Years Ended
December 31,
|
|
|
|
2018
|
|
|
2017
|
|
|
|
|
|
|
|
|
Cash paid during the period for:
|
|
|
|
|
|
|
Interest payments
|
|
$
|
4,217
|
|
|
$
|
967
|
|
|
|
|
|
|
|
|
|
|
Non-cash transactions:
|
|
|
|
|
|
|
|
|
Units issued for 2018 Subordinated Notes
|
|
$
|
489
|
|
|
|
-
|
|
Accounts receivable
|
|
|
(17,076
|
)
|
|
|
-
|
|
Prepaid expense
|
|
|
(2,178
|
)
|
|
|
-
|
|
Commodity derivative asset – current
|
|
|
(198
|
)
|
|
|
-
|
|
Inventory
|
|
|
(900
|
)
|
|
|
-
|
|
Proved oil and gas properties
|
|
|
(139,613
|
)
|
|
|
-
|
|
Unproved oil and gas properties
|
|
|
(3,364
|
)
|
|
|
-
|
|
Other fixed assets
|
|
|
(16,502
|
)
|
|
|
-
|
|
Equity method investments
|
|
|
14,655
|
|
|
|
5,674
|
|
Other non-current assets
|
|
|
(989
|
)
|
|
|
-
|
|
Accounts payable and accrued liabilities
|
|
|
26,292
|
|
|
|
67
|
|
Commodity derivative liability – non-current
|
|
|
2,645
|
|
|
|
-
|
|
Firm transportation contract obligations
|
|
|
18,724
|
|
|
|
-
|
|
Warrant liability
|
|
|
(1,792
|
)
|
|
|
-
|
|
Notes payable
|
|
|
83,006
|
|
|
|
-
|
|
Asset retirement obligations
|
|
|
7,879
|
|
|
|
2,402
|
|
Note 17 - Related Parties
During the years ended December 31, 2018
and 2017, we were engaged in the following transactions with related parties:
Carbon California
In 2017, we received 5,077 Class B Units
of Carbon California, representing 17.81% of the voting and profits interest.
On February 1, 2018, we received 11,000
Class A Units of Carbon California upon Yorktown’s exercise of the California Warrant.
On May 1, 2018, we received 5,000 Class
A Units of Carbon California in connection with our equity contribution of $5.0 million.
On February 15, 2017, we entered into a
management service agreement with Carbon California whereby we provide general management and administrative services. We
initially received $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. Effective May 1, 2018, concurrent with the closing of the Seneca
Acquisition, we receive $1.2 million annually. 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.
In our role as manager of Carbon California
we received reimbursements for the provision of management services from Carbon California of $50,000 for the one month ended January
31, 2018. These reimbursements are included in general and administrative - related party reimbursement on our consolidated statements
of operations. Effective February 1, 2018, the management reimbursement received from Carbon California is eliminated at consolidation.
This elimination was approximately $950,000 for the period February 1, 2018 through December 31, 2018. In addition to the management
reimbursements, approximately $14,000 in general and administrative expenses were reimbursed for the one month ended January 31,
2018. General and administrative expenses reimbursed by Carbon California and eliminated in consolidation were approximately $42,000
for the period February 1, 2018, through December 31, 2018.
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, 2018, and 2017, approximately zero and $300,000, respectively, is
due from Carbon California and included in accounts receivable - due from related party on the consolidated balance sheets.
Carbon Appalachia
During 2017, 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.
On November 1, 2017, we received 2,940
Class A units of Carbon Appalachia upon Yorktown’s exercise of the Appalachia Warrant.
On December 31, 2018, we closed the OIE
Membership Acquisition, whereby we acquired 100% of all outstanding interests in Carbon Appalachia owned by Old Ironside.
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
varies quarterly based upon the percentage of our production in relation to the total of our production and Carbon Appalachia.
During 2017, we also received a one-time reimbursement of $300,000 in connection with the CNX Acquisition.
In our role as manager of Carbon Appalachia,
prior to the completion of the OIE Membership Acquisition in December 2018, we received reimbursements for the provision of management
services from Carbon Appalachia of approximately $3.0 million for the year ended December 31, 2018. These reimbursements are included
in general and administrative - related party reimbursement on our consolidated statements of operations. In addition to the management
reimbursements, approximately $1.5 million in general and administrative expenses were reimbursed for the year ended December 31,
2018 from Carbon Appalachia.
Nytis LLC 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, 2018, and 2017, approximately zero and $1.8 million, respectively, is due from Carbon Appalachia and included in accounts
receivable – due from related party on the consolidated balance sheets.
Ohio Basic Minerals
During 2017, we received $96,000 in management
reimbursements from Ohio Basic Minerals. There were no such reimbursements in 2018.
Total Management Reimbursements
Total management reimbursements recorded
by us for the year ended December 31, 2018 and 2017 and described in detail above, were approximately $4.5 million and $1.6 million,
respectively, of which approximately zero and $579,000 was included in accounts receivable – due from related party on the
consolidated balance sheets as of December 31, 2018 and 2017.
Note 18 - Subsequent Events
In January 2019, we reached a settlement
agreement and received an $800,000 payment from our insurance provider related to the damage caused by the Carbon California wildfires.
We evaluated activities from December 31,
2018, to the date of the independent registered public accountants report, the date these financial statements were available for
issuance, we believe there are no additional subsequent events requiring recognition or disclosure.
Note 19 - Supplemental
Financial Data - Oil and Gas Producing Activities (unaudited)
Estimated Proved Oil, Natural Gas, and
Natural Gas Liquid Reserves
The reserve estimates as of December 31,
2018 and 2017 presented herein were made in accordance with oil and gas reserve estimation and disclosure authoritative accounting
guidance.
Proved oil, natural gas, and natural gas
liquid reserves as of December 31, 2018 and 2017 were calculated based on the prices for oil, natural gas, and natural gas liquids
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, gas and natural gas liquids reserves and changes in our net proved oil, natural gas,
and natural gas liquid reserves for 2018 and 2017 are presented in the table below. Proved oil, natural gas, and natural gas liquid
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, 2018 and 2017 unless prices are defined by contractual
arrangements, excluding escalations based upon future conditions. Prices do not include the effects of commodity derivatives.
The independent engineering firm, Cawley, Gillespie & Associates, Inc. (“
CGA
”) evaluated and prepared
independent estimated proved reserves quantities and related pre-tax future cash flows as of December 31, 2018 and 2017. 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, 2018 and 2017 (see Note 3).
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.
A summary of the changes in quantities
of proved oil, natural gas, and natural gas liquid reserves for the years ended December 31, 2018 and 2017 are as follows (in thousands):
|
|
2018
|
|
|
2017
|
|
|
|
Oil
|
|
|
Natural Gas
|
|
|
NGL
|
|
|
Total
|
|
|
Oil
|
|
|
Natural Gas
|
|
|
NGL
|
|
|
Total
|
|
|
|
MBbls
|
|
|
MMcf
|
|
|
MBbls
|
|
|
MMcfe
|
|
|
MBbls
|
|
|
MMcf
|
|
|
MBbls
|
|
|
MMcfe
|
|
Proved reserves, beginning of year
|
|
|
919
|
|
|
|
81,702
|
|
|
|
-
|
|
|
|
87,216
|
|
|
|
882
|
|
|
|
74,265
|
|
|
|
-
|
|
|
|
79,557
|
|
Revisions of previous estimates
|
|
|
(2,803
|
)
|
|
|
1,832
|
|
|
|
(1,147
|
)
|
|
|
(21,868
|
)
|
|
|
107
|
|
|
|
12,199
|
|
|
|
-
|
|
|
|
12,841
|
|
Extensions and discoveries
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
16
|
|
|
|
136
|
|
|
|
-
|
|
|
|
232
|
|
Production
|
|
|
(451
|
)
|
|
|
(4,798
|
)
|
|
|
(33
|
)
|
|
|
(7,702
|
)
|
|
|
(86
|
)
|
|
|
(4,898
|
)
|
|
|
-
|
|
|
|
(5,414
|
)
|
Purchases of reserves in-place
|
|
|
21,233
|
|
|
|
376,664
|
|
|
|
3,103
|
|
|
|
522,680
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
Sales of reserves in-place
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
Proved reserves, end of year
|
|
|
18,898
|
|
|
|
455,400
|
|
|
|
1,923
|
|
|
|
580,326
|
|
|
|
919
|
|
|
|
81,702
|
|
|
|
-
|
|
|
|
87,216
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved developed reserves at:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
End of year
|
|
|
14,336
|
|
|
|
450,424
|
|
|
|
1,472
|
|
|
|
545,272
|
|
|
|
903
|
|
|
|
81,702
|
|
|
|
-
|
|
|
|
87,216
|
|
Proved undeveloped reserves at:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
End of year
|
|
|
4,562
|
|
|
|
4,976
|
|
|
|
451
|
|
|
|
35,054
|
|
|
|
16
|
|
|
|
-
|
|
|
|
-
|
|
|
|
96
|
|
The estimated proved reserves for December
31, 2018 and 2017 includes approximately 3.3 Bcfe and 3.0 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:
(in thousands)
|
|
2018
|
|
|
2017
|
|
|
|
|
|
Oil and gas properties:
|
|
|
|
|
|
|
Proved oil and gas properties
|
|
$
|
347,059
|
|
|
$
|
114,893
|
|
Unproved properties not subject to depletion
|
|
|
5,416
|
|
|
|
1,947
|
|
Accumulated depreciation, depletion, amortization and impairment
|
|
|
(98,604
|
)
|
|
|
(80,715
|
)
|
Total
|
|
$
|
253,871
|
|
|
$
|
36,125
|
|
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, 2018 and 2017:
(in thousands)
|
|
2018
|
|
|
2017
|
|
|
|
|
|
|
|
|
Property acquisition costs:
|
|
|
|
|
|
|
Unevaluated properties
|
|
$
|
3,464
|
|
|
$
|
1
|
|
Proved properties and gathering facilities
|
|
|
63,517
|
|
|
|
289
|
|
Development costs
|
|
|
2,074
|
|
|
|
952
|
|
Gathering facilities
|
|
|
460
|
|
|
|
43
|
|
Asset retirement obligation
|
|
|
14,085
|
|
|
|
2,309
|
|
Total
|
|
$
|
83,600
|
|
|
$
|
3,594
|
|
Our investment in unproved properties as
of December 31, 2018, by the year in which such costs were incurred is set forth in the table below:
|
|
2018
|
|
|
2017
|
|
|
2016
and Prior
|
|
(in thousands)
|
|
|
|
|
|
|
|
|
|
Acquisition costs
|
|
$
|
3,464
|
|
|
$
|
1
|
|
|
$
|
1,946
|
|
Results of Operations from Oil and Gas
Producing Activities
Results of operations from oil and gas
producing activities for the years ended December 31, 2018 and 2017 are presented below:
(in thousands)
|
|
|
|
|
|
2018
|
|
|
2017
|
|
|
|
|
|
|
|
|
Revenues:
|
|
|
|
|
|
|
|
|
Oil and gas sales, including commodity derivative gains and losses
|
|
$
|
52,946
|
|
|
$
|
22,439
|
|
|
|
|
|
|
|
|
|
|
Expenses:
|
|
|
|
|
|
|
|
|
Production expenses
|
|
|
22,226
|
|
|
|
9,589
|
|
Depletion expense
|
|
|
7,305
|
|
|
|
2,157
|
|
Accretion of asset retirement obligations
|
|
|
868
|
|
|
|
307
|
|
Total expenses
|
|
|
30,399
|
|
|
|
12,053
|
|
|
|
|
|
|
|
|
|
|
Results of operations from oil and gas producing activities
|
|
$
|
22,547
|
|
|
$
|
10,386
|
|
|
|
|
|
|
|
|
|
|
Depletion rate per Mcfe
|
|
$
|
0.89
|
|
|
$
|
0.40
|
|
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. 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,
|
|
|
|
2018
|
|
|
2017
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Future cash inflows
|
|
$
|
2,878,392
|
|
|
$
|
283,664
|
|
Future production costs
|
|
|
(1,538,870
|
)
|
|
|
(119,501
|
)
|
Future development costs
|
|
|
(76,852
|
)
|
|
|
(210
|
)
|
Future income taxes
|
|
|
(258,277
|
)
|
|
|
(35,482
|
)
|
Future net cash flows
|
|
|
1,004,393
|
|
|
|
128,471
|
|
10% annual discount
|
|
|
(612,325
|
)
|
|
|
(71,389
|
)
|
Standardized measure of discounted future net cash flows
|
|
$
|
392,068
|
|
|
$
|
57,082
|
|
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,
|
|
|
|
2018
|
|
|
2017
|
|
(in thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Standardized measure of discounted future net cash flows, beginning of period
|
|
$
|
57,082
|
|
|
$
|
44,711
|
|
Sales of oil and gas, net of production costs and taxes
|
|
|
(25,681
|
)
|
|
|
(10,038
|
)
|
Price revisions
|
|
|
133,789
|
|
|
|
17,588
|
|
Extensions, discoveries and improved recovery, less related costs
|
|
|
-
|
|
|
|
298
|
|
Changes in estimated future development costs
|
|
|
(32,711
|
)
|
|
|
(324
|
)
|
Development costs incurred during the period
|
|
|
926
|
|
|
|
804
|
|
Quantity revisions
|
|
|
(23,484
|
)
|
|
|
11,196
|
|
Accretion of discount
|
|
|
5,708
|
|
|
|
4,471
|
|
Net changes in future income taxes
|
|
|
(89,117
|
)
|
|
|
(7,425
|
)
|
Purchases of reserves-in-place
|
|
|
391,877
|
|
|
|
-
|
|
Sales of reserves-in-place
|
|
|
-
|
|
|
|
-
|
|
Changes in production rate timing and other
|
|
|
(26,321
|
)
|
|
|
(4,199
|
)
|
|
|
|
|
|
|
|
|
|
Standardized measure of discounted future net cash flows, end of period
|
|
$
|
392,068
|
|
|
$
|
57,082
|
|
The twelve-month weighted averaged adjusted
prices in effect at December 31, 2018 and 2017 were as follows:
|
|
2018
|
|
|
2017
|
|
Oil (per Bbl)
|
|
$
|
65.56
|
|
|
$
|
51.34
|
|
Natural Gas (per Mcf)
|
|
$
|
3.10
|
|
|
$
|
2.98
|
|