ITEM 1. BUSINESS
Overview
EV
Energy Partners, L.P. (“we,” “our,” “us” or the “Partnership”) is a publicly held
Delaware limited partnership formed in 2006. Our general partner is EV Energy GP, L.P. (“EV Energy GP”), a Delaware
limited partnership, and the general partner of our general partner is EV Management, LLC (“EV Management”), a Delaware
limited liability company. EV Management is a wholly owned subsidiary of EnerVest, Ltd. (“EnerVest”), a Texas limited
partnership. EnerVest and its affiliates have a significant interest in us through their 71.25% ownership of EV Energy GP which,
in turn, owns a 2% general partner interest in us and all of our incentive distribution rights (“IDRs”). Our business
activities are primarily conducted through wholly owned subsidiaries.
As
of December 31, 2017, our oil and natural gas properties were located in the Barnett Shale, the San Juan Basin, the Appalachian
Basin (which includes the Utica Shale), Michigan, Central Texas (which includes the Austin Chalk area), the Mid–Continent
areas in Oklahoma, Texas, Arkansas, Kansas and Louisiana, the Permian Basin, the Monroe Field in Northern Louisiana and Karnes
County, Texas (which includes the Eagle Ford Shale).
Oil,
natural gas and natural gas liquids reserve information is derived from our reserve reports prepared by Cawley, Gillespie &
Associates, Inc. (“Cawley Gillespie”) and Wright & Company, Inc. (“Wright”), our independent reserve
engineers. All of our proved reserves are located in the United States. The following table summarizes information about our proved
reserves by geographic region as of December 31, 2017:
|
|
Estimated Net Proved Reserves
|
|
|
|
|
|
|
|
|
|
Natural Gas
|
|
|
|
|
|
|
|
|
|
Oil
|
|
|
Natural Gas
|
|
|
Liquids
|
|
|
|
|
|
PV10
(1)
|
|
|
|
(MMBbls)
|
|
|
(Bcf)
|
|
|
(MMBbls)
|
|
|
Bcfe
|
|
|
($ in millions)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Barnett Shale
|
|
|
0.3
|
|
|
|
186.5
|
|
|
|
17.2
|
|
|
|
291.1
|
|
|
$
|
184.9
|
|
San Juan Basin
|
|
|
1.4
|
|
|
|
107.6
|
|
|
|
8.2
|
|
|
|
165.3
|
|
|
|
83.8
|
|
Appalachian Basin
|
|
|
6.9
|
|
|
|
99.7
|
|
|
|
0.5
|
|
|
|
144.3
|
|
|
|
133.8
|
|
Michigan
|
|
|
0.1
|
|
|
|
69.8
|
|
|
|
0.3
|
|
|
|
72.1
|
|
|
|
36.4
|
|
Central Texas
|
|
|
1.9
|
|
|
|
22.5
|
|
|
|
2.0
|
|
|
|
46.2
|
|
|
|
63.5
|
|
Mid–Continent area
|
|
|
1.4
|
|
|
|
21.6
|
|
|
|
0.6
|
|
|
|
33.5
|
|
|
|
31.2
|
|
Permian Basin
|
|
|
0.4
|
|
|
|
9.7
|
|
|
|
2.5
|
|
|
|
27.1
|
|
|
|
17.9
|
|
Monroe Field
|
|
|
-
|
|
|
|
24.1
|
|
|
|
-
|
|
|
|
24.1
|
|
|
|
1.5
|
|
Karnes County, Texas
|
|
|
1.0
|
|
|
|
2.2
|
|
|
|
0.3
|
|
|
|
9.9
|
|
|
|
29.2
|
|
Total
|
|
|
13.4
|
|
|
|
543.7
|
|
|
|
31.6
|
|
|
|
813.6
|
|
|
$
|
582.2
|
|
|
(1)
|
At December 31, 2017, our standardized measure of discounted future net cash flows was $579.4
million. Because we are a limited partnership, we made no provision for federal income taxes in the calculation of standardized
measure; however, we made a provision for future obligations under the Texas gross margin tax. The present value of future net
pre–tax cash flows attributable to estimated net proved reserves, discounted at 10% per annum (“PV–10”),
is a computation of the standardized measure of discounted future net cash flows on a pre–tax basis. PV–10 is computed
on the same basis as standardized measure but does not include a provision for federal income taxes or the Texas gross margin tax.
PV–10 is considered a non–GAAP financial measure under the regulations of the Securities and Exchange Commission (the
“SEC”). We believe PV–10 to be an important measure for evaluating the relative significance of our oil and natural
gas properties. We further believe investors and creditors may utilize our PV–10 as a basis for comparison of the relative
size and value of our reserves to other companies. PV–10, however, is not a substitute for the standardized measure. Our
PV–10 measure and the standardized measure do not purport to present the fair value of our reserves.
|
The table below
provides a reconciliation of PV–10 to the standardized measure at December 31, 2017 (dollars in millions):
Standardized measure
|
|
$
|
579.4
|
|
Future Texas gross margin taxes, discounted at 10%
|
|
|
2.8
|
|
PV-10
|
|
$
|
582.2
|
|
Restructuring and Bankruptcy Proceedings
under Chapter 11
As discussed under “Item
7. Management’s Discussion and Analysis of Financial Condition and Results of Operations,” continued low oil and natural
gas prices have had a significant adverse impact on our business, and, as a result of our financial condition, substantial doubt
exists that we will be able to continue as a going concern.
On March 13, 2018, EVEP,
EV Energy GP, EV Management and certain of EVEP’s wholly owned subsidiaries (each a “Debtor” and, collectively,
the “Debtors”) entered into a Restructuring Support Agreement (the “Restructuring Support Agreement”) with
(i) holders (collectively, the “Supporting Noteholders”) of approximately 70% of the 8.0% senior unsecured notes due
April 2019 (the “Senior Notes”) issued pursuant to that certain indenture, dated as of March 22, 2011 (as amended,
restated, supplemented or otherwise modified from time to time, the “Indenture”), among EVEP, EV Energy Finance Corp.,
each of the guarantors party thereto, and Delaware Trust Company, as indenture trustee (the “Notes Trustee”), that
are signatories to the Restructuring Support Agreement; (ii) lenders (collectively, the “Supporting Lenders” and, together
with the Supporting Noteholders, the “Supporting Parties”) under our reserve-based lending facility, by and among EVEP,
EV Properties, L.P., JPMorgan Chase Bank, N.A., as administrative agent (the “Administrative Agent”), BNP Paribas and
Wells Fargo, National Association, as co-syndication agents, the guarantors party thereto (the “credit facility”),
and the lenders signatory thereto, constituting approximately 94% of the principal amount outstanding thereunder; (iii) EnerVest;
and (iv) EnerVest Operating, L.L.C. (“EnerVest Operating” and, together with EnerVest, the “EnerVest Parties”).
The Restructuring Support Agreement sets forth, subject to certain conditions, the commitment of the Debtors and the Consenting
Creditors to support a comprehensive restructuring of the Debtors’ long-term debt (the “Restructuring”).
The prepackaged plan of
reorganization (the “Plan”) which remains subject to confirmation by the Bankruptcy Court and other closing conditions,
provides that, among other things, on the effective date of the Plan (the “Effective Date”), subject to the occurrence
and completion of certain structuring steps:
|
·
|
the lenders under the credit facility that vote to accept the Plan will receive (a) pro rata loans
under an amendment to the credit facility (the “Exit Credit Facility”), (b) cash in an amount equal to the accrued
but unpaid interest payable to such lenders under the credit facility as of the Effective Date, and (c) unfunded commitments and
letter of credit participation under the Exit Credit Facility equal to the unfunded commitments and letter of credit participation
of such lender as of the Effective Date;
|
|
·
|
lenders under the credit facility that vote to reject the Plan will receive (a) term loans under
a new term loan facility and (b) cash in an amount equal to the accrued and unpaid interest payable to such lender under the credit
facility as of the Effective Date;
|
|
·
|
the holders of the Senior Notes will receive 95% of the new common stock (subject to dilution)
in the new, reorganized company, on a pro rata basis;
|
|
·
|
the holders of general unsecured claims, including customers, will be paid in full or will otherwise
be unimpaired; and
|
|
·
|
the holders of the existing common interests in EVEP will receive 5% of the new common stock (subject
to dilution) and five-year warrants for 8% of the new common stock (subject to dilution) in the new, reorganized company, on a
pro rata basis, with an exercise price set at an equity value at which the holders of the Senior Notes would receive a recovery
equal to par plus accrued and unpaid interest as of the Petition Date in respect of the Senior Notes (after taking into account
value dilution on account of the three percent of the new common stock to be allocated to the participants in the management incentive
plan on the Effective Date pursuant to a management incentive plan).
|
On March 14, 2018, the
Debtors commenced the solicitation of votes from the holders of the Senior Notes to accept or reject the Plan in accordance with
the terms of the Restructuring Support Agreement.
On April 2, 2018, the Debtors
commenced cases (the “Chapter 11 Cases”) under Chapter 11 of the United States Bankruptcy Code (the “Bankruptcy
Code”) in the US Bankruptcy Court for the District of Delaware (the “Bankruptcy Court”). The Debtors have filed
motions with the Bankruptcy Court seeking operational and procedural relief, including joint administration of their Chapter 11
Cases. The Debtors have also filed a motion requesting that the Bankruptcy Court schedule a hearing to confirm the Plan. If the
Plan is confirmed by the Bankruptcy Court and becomes effective, then the claims of the lenders under the credit facility and the
holders of the Senior Notes will be discharged. There can be no assurance regarding the Partnership’s ability to obtain confirmation
of the Plan or approval of other relief in the Chapter 11 Cases, the Bankruptcy Court’s rulings in the Chapter 11 Cases or
the ultimate outcome of the Chapter 11 Cases in general.
As of April 2, 2018, the
Partnership was in default under certain of its debt instruments. The Partnership’s filing of the Chapter 11 Cases described
above accelerated the Partnership’s obligations under its credit facility and the Senior Notes. Additionally, events of default,
including cross-defaults, including the receipt of a going concern explanatory paragraph from the Partnership’s independent
registered public accounting firm on the Partnership’s consolidated financial statements, which is subject to a 30 day grace
period. Under the Bankruptcy Code, the creditors under these debt agreements are stayed from taking any action against the Partnership
as a result of an event of default.
For the duration of the
Restructuring and after the Chapter 11 Cases, our operations and our ability to develop and execute our business plan are subject
to risks and uncertainties associated with the Restructuring and Chapter 11 Cases. As a result of these risks and uncertainties,
our assets, liabilities, officers and/or directors could be significantly different following the outcome of the Chapter 11 Cases,
and the description of our operations, properties and capital plans included in these financial statements may not accurately reflect
our operations, properties and capital plans following the Chapter 11 Cases.
The Partnership expects
to continue its operations without interruption during the pendency of the Chapter 11 Cases. See Note 2 of the Notes to Consolidated
Financial Statements included under “Item 8. Financial Statements and Supplementary Data” for additional information.
Current Developments
NASDAQ Delisting
Our common units are traded
on the NASDAQ Capital Market (the “NASDAQ”) under the symbol “EVEP.” On July 17, 2017, we received a letter
from the NASDAQ notifying us that we were not in compliance with the NASDAQ Global Market’s rules that require the minimum
bid price of our units to be at least $1.00 per share over a consecutive 30-trading-day period. On December 27, 2017, we applied
to transfer from the NASDAQ Global Market to the NASDAQ Capital Market and requested an additional 180-day grace period to regain
compliance with the NASDAQ Capital Market’s minimum bid price requirement because our common units have continued to trade
below the $1.00 minimum closing bid price. In January 2018, the NASDAQ approved both the transfer and the extension of the 180-day
grace period, which will end on July 16, 2018. This notice from the NASDAQ does not affect our business operations or trigger any
default or other violation of our debt or other material obligations.
In connection with filing
the Chapter 11 Cases, we expect to receive a notice from the NASDAQ stating that our units will be delisted from the NASDAQ Capital
Market. The delisting decision will be reached under the NASDAQ Listing Rules 5101, 5110(b), and IM-5101-1 following our announcement
that the Debtors filed the Chapter 11 Cases. Trading of our common units will be suspended by the NASDAQ, and a Form 25-NSE will
be filed with the Securities and Exchange Commission, which will remove our securities from listing and registration on the NASDAQ
Capital Market.
Following the expected
delisting from the NASDAQ, our units will commence trading on the OTC Pink Marketplace under the symbol “EVEPQ”. We
can provide no assurance that its units will commence or continue to trade on this market, whether broker-dealers will continue
to provide public quotes of the units on this market, whether the trading volume of the units will be sufficient to provide for
an efficient trading market or whether quotes for the units will continue on this market in the future.
Industry Conditions
and Our Financial Position
Oil, natural gas and natural
gas liquids prices are determined by many factors that are outside of our control. Historically, these prices have been volatile,
and we expect them to remain volatile. In late 2014, prices for oil, natural gas and natural gas liquids declined precipitously,
and prices remained low through 2015 and most of 2016. While prices showed some improvement during the second half of 2016 and
2017, they continue to fluctuate.
Factors contributing to lower oil prices in recent years have included
real or perceived geopolitical risks in oil producing regions of the world, particularly the Middle East; excess global supply
and buildup of oil inventory levels above the historical norm; actions taken by the Organization of Petroleum Exporting Countries;
and the strength of the US dollar in international currency markets. Factors contributing to lower natural gas prices include increased
supplies of natural gas due to greater exploration and development activities; higher levels of natural gas in storage; and competition
from other energy sources. Prices for natural gas liquids generally correlate to the price of oil and are likely to continue to
directionally follow the market for oil.
In 2017, oil, natural gas
and natural gas liquids prices increased relative to previous years, but did not reach a level for our revenues and cash flows
to sufficiently reduce our total leverage ratio to meet the longer term level required by our credit agreement, which have a material
adverse effect on our liquidity. Continued volatility or further declines in prices could also have a significant adverse impact
on the value and quantities of our reserves.
In response, we took a
number of actions in 2017 to preserve our liquidity and financial flexibility, including:
|
·
|
negotiating and pursuing consummation of the Restructuring, which is expected to substantially
deleverage our balance sheet and reduce debt service obligations;
|
|
·
|
focusing on managing and enhancing our base business through continued reductions in operating
costs;
|
|
·
|
increasing our capital spending in 2017 to $39.3 million from $10.7 million in 2016, in an effort
to maintain production levels;
|
|
·
|
concentrating on maintaining sufficient liquidity;
|
|
·
|
continuing to evaluate strategic acquisitions of long–life, producing oil and natural gas
properties; and
|
|
·
|
seeking opportunities to further realize the value of our undeveloped acreage through either alternative
sources of capital (including farmouts, production payments and joint ventures) or monetization of acreage.
|
As a result of the steps
above, at December 31, 2017, we had over $66 million of liquidity available between our borrowing base capacity and cash on hand.
However, our current leverage position, covenant defaults under our credit facility and our Indenture governing our Senior Notes
and the fact that we have less production hedged at lower prices in 2018 relative to previous years, has required us to take additional
steps going forward into 2018 to continue to preserve our liquidity and financial flexibility. These steps include:
|
·
|
focusing on managing and enhancing our base business through continued reductions in operating
costs;
|
|
·
|
increasing our capital spending budget to $55 - $65 million from $39.3 million in 2017, in an effort
to maintain current production levels;
|
|
·
|
continuing to evaluate strategic acquisitions of long–life, producing oil and natural gas
properties such as our Eagle Ford Acquisition described below; and
|
|
·
|
realizing the value of our undeveloped acreage through either alternative sources of capital, including
farmouts, production payments and joint ventures, or potential monetization of acreage.
|
During 2016 and 2017, the
board of directors of EV Management announced that it had elected to suspend distributions for those fiscal years. The Partnership
continues to generate positive distributable cash flow, albeit at significantly lower levels than previous years. However, to reinstate
distributions, we must be in compliance with the covenants contained in our current credit agreement. We do not anticipate that
we will be able to reinstate distributions in the foreseeable future, given that our operating cash flows have not increased, and
are currently unlikely to increase, to a level that can support a sustainable distribution in compliance with theses covenants.
Furthermore, as of April
2, 2018, the Partnership was in default under certain of its debt instruments. The Partnership’s filing of the Chapter 11
Cases accelerated the Partnership’s obligations under its credit facility and the Senior Notes. Additionally, events of default,
including cross-defaults, are present, including the receipt of a going concern explanatory paragraph from the Partnership’s
independent registered public accounting firm on the Partnership’s consolidated financial statements, subject to a 30 day
grace period. As a result, our credit facility could become due and payable because of this event of default. This has a material,
adverse effect on our business, including our ability to resume and sustain distributions. See “Item 1A. Risk Factors
-
Covenants in our credit agreement may restrict our ability to resume and sustain distributions
.”
Acquisition
of Eagle Ford Shale Properties
In December 2016, we sold
a portion of our Barnett Shale natural gas properties for $52.1 million (before post-closing adjustments), which proceeds were
deposited with a qualified intermediary to facilitate a like-kind exchange transaction pursuant to Section 1031 of the Internal
Revenue Code. On January 31, 2017, we acquired a 5.8% working interest in 9,151 gross acres (529 net acres) in Karnes County,
Texas for $58.7 million (before post-closing purchase price adjustments) with the proceeds and $6.6 million of borrowings under
our credit facility (the “Eagle Ford Acquisition”). Certain EnerVest institutional partnerships own an 87% working
interest in, and EnerVest acts as operator of, the properties.
Our Relationship with EnerVest
Our general partner is and historically has
been EV Energy GP. Its general partner is EV Management, which is a wholly owned subsidiary of EnerVest. Through our omnibus agreement
with EnerVest, EnerVest agrees to make available to us its personnel to permit us to carry on our business. We therefore benefit
from the technical expertise of EnerVest, which we believe would generally not otherwise be available to a company of our size.
EnerVest’s
principal business is to act as general partner or manager of EnerVest partnerships, formed to acquire, explore, develop and produce
oil and natural gas properties. A primary investment objective of the EnerVest partnerships is to make periodic cash distributions.
EnerVest was formed in 1992 and is one of the 25 largest oil and natural gas companies in the United States, with more than 36,500
wells across 15 states, 8.0 million acres under lease and 4.4 Tcfe of proved reserves under management.
While our relationship
with EnerVest is a significant attribute, it is also a source of potential conflicts. For example, we have acquired oil and natural
gas properties from partnerships formed by EnerVest and partnerships in which EnerVest has an interest, and we may do so in the
future. We have also acquired interests in oil and natural gas properties in conjunction with institutional partnerships managed
by EnerVest. In these acquisitions, we and the institutional partnerships managed by EnerVest each acquire an interest in all of
the properties subject to the acquisition. The purchase is allocated among us and the institutional partnerships managed by EnerVest
based on the interest acquired. In the future, it is possible that we would vary the manner in which we jointly acquire oil and
natural gas properties with the institutional partnerships managed by EnerVest.
EnerVest currently operates
oil and natural gas properties representing 93% of our proved oil and gas reserves as of December 31, 2017. The EnerVest partnerships
own interests in oil and gas properties in which we own interests. The properties are primarily located in the Barnett Shale, the
Appalachian Basin and the San Juan Basin, and these properties represent approximately 74% of our net proved reserves at December
31, 2017. The investment strategy of the EnerVest partnerships is to typically divest their properties in three to five years,
while our strategy contemplates holding such properties for a longer term. If the EnerVest partnerships were to sell their interests
in these properties to an entity not affiliated with EnerVest, we may not have a sufficient working interest to cause EnerVest
to remain operator of the property. The EnerVest partnerships are under no obligation to us with respect to their sale of the properties
they own.
EnerVest is not restricted
from competing with us. It may acquire, develop or dispose of oil and natural gas properties or other assets in the future without
any obligation to offer us the opportunity to purchase or participate in the development of those assets. In addition, the principal
business of the EnerVest partnerships is to acquire and develop oil and natural gas properties. The agreements for certain of our
EnerVest partnerships, however, provide that if EnerVest becomes aware, other than in its capacity as an owner of our general partner,
of acquisition opportunities that are suitable for purchase by the EnerVest partnerships during their investment periods, EnerVest
must first offer those opportunities to those EnerVest partnerships, in which case we would be offered the opportunities only if
the EnerVest partnerships chose not to pursue the acquisition. EnerVest’s obligation to offer acquisition opportunities to
its existing EnerVest partnership will not apply to acquisition opportunities which we generate internally, and EnerVest has agreed
with us that for so long as it controls our general partner it will not enter into any agreements which would limit our ability
to pursue acquisition opportunities that we generate internally.
On March 8, 2018, our Board
of Directors, after receiving the recommendation of our conflicts committee, approved an extension of our Omnibus Agreement with
EnerVest through the end of 2018, at a monthly fee of $1,433,333.
As a result of the Restructuring,
we anticipate that EV Energy GP and EV Management will be dissolved. Pursuant to the Restructuring Support Agreement, EnerVest
has agreed to continue to satisfy, consistent with past practice, all obligations to the Debtors under the existing omnibus agreement
and any joint operating agreements and other operating agreements to which the Debtors and EnerVest are party and has agreed to
negotiate in good faith the terms of a new omnibus agreement and any modifications to the joint operating agreements and other
operating agreements to which the Debtors and EnerVest are party.
Oil and Natural
Gas Producing Activities
At December 31, 2017, our
oil and natural gas properties were located in the Barnett Shale, the San Juan Basin, the Appalachian Basin (which includes the
Utica Shale), Michigan, Central Texas (which includes the Austin Chalk area), the Mid–Continent areas in Oklahoma, Texas,
Arkansas, Kansas and Louisiana, the Permian Basin, the Monroe Field in Northern Louisiana and Karnes County, Texas.
Barnett Shale
Our properties are primarily
located in Denton, Montague, Parker, Tarrant and Wise counties in Northern Texas. Our estimated net proved reserves as of December 31,
2017 were 291.1 Bcfe, 64% of which is natural gas. During 2017, we drilled 9 gross wells (2.5 net wells) in the Barnett Shale,
which were successfully completed. EnerVest operates wells representing 98% of our estimated net proved reserves in this area,
and we own an average 27% working interest in 1,398 gross productive wells.
San Juan Basin
Our
properties are primarily located in Rio Arriba County, New Mexico and La Plata County in Colorado. Our estimated net proved reserves
as of December 31, 2017 were 165.3 Bcfe, 65% of which is natural gas. During 2017, we did not drill any wells in the
San Juan Basin. EnerVest operates wells representing 98% of our estimated net proved reserves in this area, and we own an average
79% working interest in 502 gross productive wells.
Appalachian
Basin (including the Utica Shale)
Our
activities are concentrated in the Ohio and West Virginia areas of the Appalachian Basin. Our Ohio area properties are producing
primarily from the Knox and Clinton formations and other Devonian age sands in 40 counties in Eastern Ohio and 8 counties in Western
Pennsylvania. Our West Virginia area properties are producing primarily from the Balltown, Benson and Big Injun formations in 22
counties in North Central West Virginia. Our estimated net proved reserves as of December 31, 2017 were 144.3 Bcfe, 69% of which
is natural gas. During 2017, we did not drill any wells in the Appalachian Basin. EnerVest operates wells representing 86% of our
estimated net proved reserves in this area, and we own an average 63% working interest in 9,876 gross productive wells.
Michigan
Our properties are located
in the Antrim Shale reservoir in Otsego and Montmorency counties in northern Michigan. Our estimated net proved reserves as of
December 31, 2017 were 72.1 Bcfe, 97% of which is natural gas. During 2017, we did not drill any wells in Michigan. EnerVest operates
wells representing 99% of our estimated net proved reserves in this area, and we own an average 61% working interest in 1,625 gross
productive wells.
Central Texas
Our properties produce
primarily from the Austin Chalk formation and are located in 16 counties in Central Texas. Our portion of the estimated net proved
reserves as of December 31, 2017 was 46.2 Bcfe, 49% of which is natural gas. During 2017, we drilled 2 gross wells (0.3 net wells)
in Central Texas, which were successfully completed. In August 2017, we acquired a 40% working interest in additional oil and gas
properties in central Texas for $2.7 million (net of post-closing purchase price adjustments) from a third party. EnerVest operates
wells representing 98% of our estimated net proved reserves in this area, and we own an average 22% working interest in 1,544
gross productive wells.
Mid–Continent Area
Our properties are primarily
located in 43 counties in Oklahoma, 22 counties in Texas, four parishes in North Louisiana, two counties in Kansas and six counties
in Arkansas. Our estimated net proved reserves as of December 31, 2017 were 33.5 Bcfe, 65% of which is natural gas. During
2017, we did not drill any wells in the Mid-Continent area. EnerVest operates wells representing 15% of our estimated net proved
reserves in this area, and we own an average 16% working interest in 1,610 gross productive wells.
Permian Basin
Our properties are primarily
located in the Yates, Seven Rivers, Queen, Morrow, Clear Fork and Wichita Albany formations in four counties in New Mexico and
Texas. Our estimated net proved reserves as of December 31, 2017 were 27.1 Bcfe, 36% of which is natural gas. During 2017, we did
not drill any wells in the Permian Basin. EnerVest operates wells representing 99% of our estimated net proved reserves in this
area, and we own an average 95% working interest in 136 gross productive wells.
Monroe Field
Our
properties are primarily located in two parishes in Northeast Louisiana. Our estimated net proved reserves as of December 31, 2017
were 24.1 Bcfe, 100% of which is natural gas. During 2017, we did not drill any wells in the Monroe Field. EnerVest operates wells
representing 100% of our estimated net proved reserves in this area, and we own an average 98% working interest in 3,851 gross
productive wells.
Karnes County, Texas
On
January 31, 2017, we acquired an additional 5.8% working interest in certain oil and gas properties in Karnes County, Texas for
$58.7 million (net of post-closing purchase price adjustments). Our estimated net proved reserves as of December 31, 2017 were
9.9 Bcfe, 22% of which is natural gas. During 2017, we drilled 22 gross wells (1.0 net wells) in Karnes County, which were successfully
completed. EnerVest operates wells representing 94% of our estimated net proved reserves in this area, and we own an average 6%
working interest in 127 gross productive wells.
Our Oil, Natural Gas and Natural Gas Liquids
Data
Our Reserves
The
following table presents our estimated net proved reserves at December 31, 2017:
|
|
Oil (MMBbls)
|
|
|
Natural Gas
(Bcf)
|
|
|
Natural Gas
Liquids
(MMBbls)
|
|
|
Bcfe
|
|
Proved reserves:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Developed
|
|
|
13.4
|
|
|
|
543.7
|
|
|
|
31.6
|
|
|
|
813.6
|
|
Undeveloped
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
Total
|
|
|
13.4
|
|
|
|
543.7
|
|
|
|
31.6
|
|
|
|
813.6
|
|
Proved
developed reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating
methods. PUDs 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. See “Glossary of Oil and Natural Gas Terms.” Proved
undeveloped locations conform to the SEC rules defining proved undeveloped locations. We do not have any reserves that would be
classified as synthetic oil or synthetic natural gas.
Our estimates of proved
reserves are based on the quantities of oil, natural gas and natural gas liquids which, by analysis of geoscience and engineering
data, can be estimated with reasonable certainty to be economically producible – from a given date forward, from known reservoirs,
and under existing economic conditions, operating methods, and government regulations – prior to the time at which contracts
providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic
or probabilistic methods are used for the estimate. Reserves for proved developed producing wells were estimated using production
performance and material balance methods. Certain new producing properties with little production history were forecast using a
combination of production performance and analogy to offset production, both of which are believed to provide accurate forecasts.
Non–producing reserve estimates for both developed and undeveloped properties were forecast using either or both volumetric
or analogy methods. These methods are believed to provide accurate forecasts due to the mature nature of the properties targeted
for development and an abundance of subsurface control data.
The data in the above table
represents estimates only. Oil, natural gas and natural gas liquids reserve engineering is inherently a subjective process of estimating
underground accumulations of oil, natural gas and natural gas liquids that cannot be measured exactly. The accuracy of any reserve
estimate is a function of the quality of available data and engineering and geological interpretation and judgment. Accordingly,
reserve estimates may vary from the quantities of oil, natural gas and natural gas liquids that are ultimately recovered. Please
read “Item 1A. Risk Factors.”
Future prices received
for production and costs may vary, perhaps significantly, from the prices and costs assumed for purposes of these estimates. The
standardized measure of discounted future net cash flows is the present value of estimated future net revenues to be generated
from the production of proved reserves, determined in accordance with the rules and regulations of the SEC, without giving effect
to non–property related expenses such as general and administrative expenses and debt service or to depreciation, depletion
and amortization and discounted using an annual discount rate of 10%. Because we are a limited partnership which passes through
our taxable income to our unitholders, we have made no provisions for federal income taxes in the calculation of standardized measure;
however, we have made a provision for future obligations under the Texas gross margin tax. Standardized measure does not give effect
to derivative transactions. The standardized measure shown should not be construed as the current market value of the reserves.
The 10% discount factor, which is required by Financial Accounting Standards Board pronouncements, is not necessarily the most
appropriate discount rate. The present value, no matter what discount rate is used, is materially affected by assumptions as to
timing of future production, which may prove to be inaccurate.
Our Proved Undeveloped Reserves
We annually review all
PUDs to ensure an appropriate plan for development exists. As of December 31, 2017, we have no reportable estimated PUDs with respect
to any of our properties due to uncertainty regarding our ability to continue as a going concern and the availability of capital
that would be required to develop the PUD reserves. We previously reported estimated PUDs in SEC filings, and, if in the future
we can satisfy the reasonable certainty criteria for recording PUDs as prescribed under the SEC requirements, we will likely report
estimated PUDs in future filings
.
At December 31, 2017, we
had no PUDs compared with 87.1 Bcfe of PUDs at December 31, 2016. The following table describes the changes in our PUDs during
2017:
|
|
Bcfe
|
|
PUDs as of December 31, 2016
|
|
|
87.1
|
|
Revisions of previous estimates
|
|
|
(85.0
|
)
|
Converted to proved developed reserves
|
|
|
(2.1
|
)
|
PUDs as of December 31, 2017
|
|
|
-
|
|
The following describes
the material changes to our PUDs during 2017:
Revisions of previous
estimates
. The annual review of our PUDs for 2017 resulted in a negative revision of 85.0 Bcfe. This change from prior estimates
results from uncertainty regarding our ability to continue as a going concern and the availability of capital that would be required
to develop the PUDs within the SEC five-year development limitation on PUDs. Further, decreases in prices for oil, natural gas
and natural gas liquids have delayed the development of certain PUDs.
Converted to proved
developed reserves
.
In 2017, we developed approximately 2.8% of our
PUD volume and 2.5% of our PUD locations booked as of December 31, 2016 through the drilling of 4 gross (0.7 net) development wells.
Of these reserves and wells, 1.4 Bcfe and 2 gross (0.4 net) wells are located in the Barnett Shale and the remaining 0.7 Bcfe and
2 gross (0.3 net) wells produce from the Austin Chalk located in the Central Texas area. Costs incurred relating to the development
of PUDs were approximately $3.6 million during 2017.
Internal Controls Applicable to our Reserve
Estimates
Our policies and procedures
regarding internal controls over the recording of our reserves is structured to objectively and accurately estimate our reserves
quantities and present values in compliance with both accounting principles generally accepted in the United States and the SEC’s
regulations. Compliance with these rules and regulations is the responsibility of Terry Wagstaff, our Vice President of Acquisitions
and Engineering, who is also our principal engineer. Mr. Wagstaff has over 35 years of experience in the oil and natural gas industry,
with exposure to reserves and reserve related valuations and issues during most of this time, and is a qualified reserves estimator
(“QRE”), as defined by the standards of the Society of Petroleum Engineers. Further professional qualifications include
a Bachelor of Science in Petroleum Engineering, extensive internal and external reserve training, asset evaluation and management,
and he is a registered professional engineer in the state of Texas. In addition, our principal engineer is an active participant
in industry reserve seminars, professional industry groups, and is a member of the Society of Petroleum Engineers.
Our controls over reserve
estimates included retaining Cawley Gillespie and Wright as our independent petroleum engineers. We provided information about
our oil and natural gas properties, including production profiles, prices and costs, to Cawley Gillespie and Wright, and they prepared
their own estimates of 88% and 12%, respectively, of our reserves attributable to our properties. All of the information regarding
reserves in this annual report on Form 10–K is derived from the reports of Cawley Gillespie and Wright, which are included
as exhibits to this annual report on Form 10–K.
The principal engineer
at Cawley Gillespie responsible for preparing our reserve estimates is W. Todd Brooker, a President and Principal with Cawley Gillespie.
Mr. Brooker is a licensed professional engineer in the state of Texas (license #83462) with over 25 years of experience in petroleum
engineering. The principal engineer at Wright responsible for preparing our reserve estimates is D. Randall Wright, the President
of Wright. Mr. Wright is a licensed professional engineer in the state of Texas (license #43291) with over 43 years of experience
in petroleum engineering.
We and EnerVest maintain
an internal staff of petroleum engineers, geoscience professionals and petroleum landmen who work closely with Cawley Gillespie
and Wright to ensure the integrity, accuracy and timeliness of data furnished to Cawley Gillespie and Wright in their reserves
estimation process. Our Vice President of Acquisitions and Engineering reviews and approves the reserve information compiled by
our internal staff. Our technical team meets regularly with representatives of Cawley Gillespie and Wright to review properties
and discuss the methods and assumptions used by Cawley Gillespie and Wright in their preparation of the year end reserves estimates.
Our technical team and Vice President of Acquisitions and Engineering also meet regularly to review the methods and assumptions
used by Cawley Gillespie and Wright in their preparation of the year end reserves estimates.
The audit committee of
our board of directors meets with management, including the Vice President of Acquisitions and Engineering, to discuss matters
and policies related to our reserves.
Our Productive Wells
The
following table sets forth information relating to the productive wells in which we owned a working interest as of December 31,
2017. Productive wells consist of producing wells and wells capable of production, including natural gas wells awaiting pipeline
connections to commence deliveries and oil wells awaiting connection to production facilities. Gross wells are the total number
of productive wells in which we have a working interest, regardless of our percentage interest. A net well is not a physical well,
but is a concept that reflects the actual total working interest we hold in a given well. We compute the number of net wells we
own by totaling the percentage interests we hold in all our gross wells. Operated wells are the wells operated by EnerVest in which
we own an interest.
Our
wells may produce both oil and natural gas. We classify a well as an oil well if the net equivalent production of oil was greater
than natural gas for the well.
|
|
Gross Wells
|
|
|
Net Wells
|
|
|
|
|
|
|
Natural
|
|
|
|
|
|
|
|
|
Natural
|
|
|
|
|
|
|
Oil
|
|
|
Gas
|
|
|
Total
|
|
|
Oil
|
|
|
Gas
|
|
|
Total
|
|
Barnett Shale:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operated
|
|
|
10
|
|
|
|
1,254
|
|
|
|
1,264
|
|
|
|
3
|
|
|
|
364
|
|
|
|
367
|
|
Non–operated
|
|
|
9
|
|
|
|
125
|
|
|
|
134
|
|
|
|
-
|
|
|
|
9
|
|
|
|
9
|
|
San Juan Basin:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operated
|
|
|
20
|
|
|
|
408
|
|
|
|
428
|
|
|
|
20
|
|
|
|
367
|
|
|
|
387
|
|
Non–operated
|
|
|
23
|
|
|
|
51
|
|
|
|
74
|
|
|
|
2
|
|
|
|
7
|
|
|
|
9
|
|
Appalachian Basin:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operated
|
|
|
1,545
|
|
|
|
6,179
|
|
|
|
7,724
|
|
|
|
1,491
|
|
|
|
4,550
|
|
|
|
6,041
|
|
Non–operated
|
|
|
343
|
|
|
|
1,809
|
|
|
|
2,152
|
|
|
|
29
|
|
|
|
176
|
|
|
|
205
|
|
Michigan:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operated
|
|
|
1
|
|
|
|
1,223
|
|
|
|
1,224
|
|
|
|
1
|
|
|
|
969
|
|
|
|
970
|
|
Non–operated
|
|
|
32
|
|
|
|
369
|
|
|
|
401
|
|
|
|
1
|
|
|
|
18
|
|
|
|
19
|
|
Central Texas:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operated
|
|
|
612
|
|
|
|
660
|
|
|
|
1,272
|
|
|
|
193
|
|
|
|
133
|
|
|
|
326
|
|
Non–operated
|
|
|
40
|
|
|
|
232
|
|
|
|
272
|
|
|
|
1
|
|
|
|
14
|
|
|
|
15
|
|
Mid–Continent area:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operated
|
|
|
52
|
|
|
|
97
|
|
|
|
149
|
|
|
|
43
|
|
|
|
72
|
|
|
|
115
|
|
Non–operated
|
|
|
629
|
|
|
|
832
|
|
|
|
1,461
|
|
|
|
46
|
|
|
|
104
|
|
|
|
150
|
|
Permian Basin:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operated
|
|
|
1
|
|
|
|
132
|
|
|
|
133
|
|
|
|
1
|
|
|
|
127
|
|
|
|
128
|
|
Non–operated
|
|
|
3
|
|
|
|
-
|
|
|
|
3
|
|
|
|
1
|
|
|
|
-
|
|
|
|
1
|
|
Monroe Field:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operated
|
|
|
-
|
|
|
|
3,851
|
|
|
|
3,851
|
|
|
|
-
|
|
|
|
3,764
|
|
|
|
3,764
|
|
Non–operated
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
Karnes County, Texas:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operated
|
|
|
94
|
|
|
|
10
|
|
|
|
104
|
|
|
|
5
|
|
|
|
1
|
|
|
|
6
|
|
Non–operated
|
|
|
19
|
|
|
|
4
|
|
|
|
23
|
|
|
|
1
|
|
|
|
-
|
|
|
|
1
|
|
Total
(1)
|
|
|
3,433
|
|
|
|
17,236
|
|
|
|
20,669
|
|
|
|
1,838
|
|
|
|
10,675
|
|
|
|
12,513
|
|
(1)
In addition,
we own small royalty interests in over 1,000 wells.
Our Developed and Undeveloped Acreage
The
following table sets forth information relating to our leasehold acreage as of December 31, 2017:
|
|
Developed Acreage
|
|
|
Undeveloped Acreage
|
|
|
|
Gross
|
|
|
Net
|
|
|
Gross
|
|
|
Net
|
|
Barnett Shale
|
|
|
145,986
|
|
|
|
38,222
|
|
|
|
13,738
|
|
|
|
3,240
|
|
San Juan Basin
|
|
|
166,844
|
|
|
|
73,365
|
|
|
|
49,508
|
|
|
|
33,793
|
|
Appalachian Basin
|
|
|
651,108
|
|
|
|
463,903
|
|
|
|
383,757
|
|
|
|
268,496
|
|
Michigan
|
|
|
266,266
|
|
|
|
67,938
|
|
|
|
2,806
|
|
|
|
1,175
|
|
Central Texas
|
|
|
756,222
|
|
|
|
122,507
|
|
|
|
1,423
|
|
|
|
268
|
|
Mid–Continent area
|
|
|
389,363
|
|
|
|
56,265
|
|
|
|
10,315
|
|
|
|
493
|
|
Permian Basin
|
|
|
11,415
|
|
|
|
10,868
|
|
|
|
520
|
|
|
|
385
|
|
Monroe Field
(1)
|
|
|
5,904
|
|
|
|
5,904
|
|
|
|
170,346
|
|
|
|
145,666
|
|
Karnes County, Texas
|
|
|
7,771
|
|
|
|
381
|
|
|
|
1,921
|
|
|
|
123
|
|
Total
|
|
|
2,400,879
|
|
|
|
839,353
|
|
|
|
634,334
|
|
|
|
453,639
|
|
|
(1)
|
There are no spacing requirements on substantially all of the wells on our Monroe Field properties;
therefore, one developed acre is assigned to each productive well for which there is no spacing unit assigned.
|
Substantially all of our
acreage is held by production, which means that as long as our wells on the acreage continue to produce, we will continue to hold
the leases. The acreage in which we hold interests that are not held by production are not significant to our overall undeveloped
acreage.
Title to Properties
As is customary in the
oil and natural gas industry, we initially conduct only a cursory review of the title to our properties on which we do not have
proved reserves. Prior to the commencement of drilling operations on those properties, we conduct a thorough title examination
and perform curative work with respect to significant defects. To the extent title opinions or other investigations reflect title
defects on those properties, we are typically responsible for curing any title defects at our expense. We generally will not commence
drilling operations on a property until we have cured any material title defects on such property. Prior to completing an acquisition
of producing leases, we perform title reviews on the most significant leases and, depending on the materiality of the properties,
we may obtain a title opinion or review previously obtained title opinions. As a result, we have obtained title opinions on a significant
portion of our properties and believe that we have satisfactory title to our producing properties in accordance with standards
generally accepted in the oil and natural gas industry. Our properties are subject to customary royalty and other interests, liens
for current taxes and other burdens that we believe do not materially interfere with the use of or affect our carrying value of
the properties.
Production,
Average Sales Price and Average Production Cost by Field
The following table sets
forth our production, production prices and production costs for 2017, 2016 and 2015 from the Barnett Shale, the Appalachian Basin
and the San Juan Basin, which are the only fields during those years for which our estimated net proved reserves at December 31,
2017 attributable to the field represented 15% or more of our total estimated net proved reserves at December 31, 2017:
|
|
Year Ended December 31,
|
|
|
|
2017
|
|
|
2016
|
|
|
2015
|
|
|
|
|
|
|
|
|
|
|
|
Oil
|
|
|
|
|
|
|
|
|
|
|
|
|
Production (MBbls):
|
|
|
|
|
|
|
|
|
|
|
|
|
Barnett Shale
|
|
|
35
|
|
|
|
39
|
|
|
|
65
|
|
Appalachian Basin
|
|
|
541
|
|
|
|
611
|
|
|
|
420
|
|
San Juan Basin
|
|
|
74
|
|
|
|
75
|
|
|
|
53
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average sales price per Bbl:
|
|
|
|
|
|
|
|
|
|
|
|
|
Barnett Shale
|
|
$
|
48.74
|
|
|
$
|
36.96
|
|
|
$
|
43.64
|
|
Appalachian Basin
|
|
$
|
47.29
|
|
|
$
|
39.59
|
|
|
$
|
42.99
|
|
San Juan Basin
|
|
$
|
38.20
|
|
|
$
|
31.01
|
|
|
$
|
34.82
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas
|
|
|
|
|
|
|
|
|
|
|
|
|
Production (MMcf):
|
|
|
|
|
|
|
|
|
|
|
|
|
Barnett Shale
|
|
|
12,948
|
|
|
|
19,936
|
|
|
|
22,249
|
|
Appalachian Basin
|
|
|
11,465
|
|
|
|
12,097
|
|
|
|
7,553
|
|
San Juan Basin
|
|
|
5,336
|
|
|
|
3,751
|
|
|
|
1,949
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average sales price per Mcf:
|
|
|
|
|
|
|
|
|
|
|
|
|
Barnett Shale
|
|
$
|
2.70
|
|
|
$
|
1.93
|
|
|
$
|
2.22
|
|
Appalachian Basin
|
|
$
|
2.45
|
|
|
$
|
1.70
|
|
|
$
|
1.79
|
|
San Juan Basin
|
|
$
|
2.82
|
|
|
$
|
2.37
|
|
|
$
|
2.48
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas Liquids
|
|
|
|
|
|
|
|
|
|
|
|
|
Production (MBbls):
|
|
|
|
|
|
|
|
|
|
|
|
|
Barnett Shale
|
|
|
1,183
|
|
|
|
1,320
|
|
|
|
1,593
|
|
Appalachian Basin
|
|
|
43
|
|
|
|
59
|
|
|
|
43
|
|
San Juan Basin
|
|
|
390
|
|
|
|
405
|
|
|
|
203
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average sales price per Bbl:
|
|
|
|
|
|
|
|
|
|
|
|
|
Barnett Shale
|
|
$
|
19.91
|
|
|
$
|
14.01
|
|
|
$
|
13.50
|
|
Appalachian Basin
|
|
$
|
15.53
|
|
|
$
|
14.12
|
|
|
$
|
2.51
|
|
San Juan Basin
|
|
$
|
27.34
|
|
|
$
|
20.94
|
|
|
$
|
17.22
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average unit costs per Mcfe:
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expenses per Mcfe
(1)
|
|
|
|
|
|
|
|
|
|
|
|
|
Barnett Shale
|
|
$
|
1.25
|
|
|
$
|
0.95
|
|
|
$
|
1.15
|
|
Appalachian Basin
|
|
$
|
1.85
|
|
|
$
|
1.65
|
|
|
$
|
1.73
|
|
San Juan Basin
|
|
$
|
1.59
|
|
|
$
|
1.80
|
|
|
$
|
1.70
|
|
|
(1)
|
Excluding ad valorem taxes.
|
Our Drilling Activity
We intend to concentrate
our drilling activity on low risk development drilling opportunities. The number and types of wells we drill will vary depending
on the amount of funds we have available for drilling, the cost of each well, the size of the fractional working interests we acquire
in each well, the estimated recoverable reserves attributable to each well and the accessibility to the well site.
The
following table summarizes our approximate gross and net interest in development wells completed by us during 2017, 2016 and 2015,
regardless of when drilling was initiated. The information should not be considered indicative of future performance, nor should
it be assumed that there is necessarily any correlation between the number of productive wells drilled, quantities of reserves
found or economic value.
|
|
Year Ended December 31,
|
|
|
|
2017
|
|
|
2016
|
|
|
2015
|
|
Gross wells:
|
|
|
|
|
|
|
|
|
|
|
|
|
Productive
|
|
|
33.0
|
|
|
|
9.0
|
|
|
|
62.0
|
|
Dry
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
Total
|
|
|
33.0
|
|
|
|
9.0
|
|
|
|
62.0
|
|
Net wells:
|
|
|
|
|
|
|
|
|
|
|
|
|
Productive
|
|
|
3.8
|
|
|
|
2.6
|
|
|
|
14.6
|
|
Dry
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
Total
|
|
|
3.8
|
|
|
|
2.6
|
|
|
|
14.6
|
|
As of December 31, 2017,
we were participating in the drilling of 17 gross (1.9 net) development wells.
We did not drill any
exploratory wells in 2017 or in 2016. We drilled three gross (1.7 net) exploratory wells in 2015, all of which were successfully
completed as producers.
Well Operations
We have entered into operating
agreements with EnerVest. Under these operating agreements, EnerVest acts as contract operator of the oil and natural gas wells
and related gathering systems and production facilities in which we own an interest, provided that our interest entitles us to
control the appointment of the operator of the well, gathering system or production facilities. As contract operator, EnerVest
designs and manages the drilling and completion of our wells and manages the day to day operating and maintenance activities for
our wells.
Under
these operating agreements, EnerVest has established a joint account for each well in which we have an interest. We are required
to pay our working interest share of amounts charged to the joint account. The joint account is charged with all direct expenses
incurred in the operation of our wells and related gathering systems and production facilities. The determination of which direct
expenses can be charged to the joint account and the manner of charging direct expenses to the joint account for our wells is done
in accordance with the Council of Petroleum Accountants Societies (“COPAS”) model form of accounting procedure.
Under the COPAS model form,
direct expenses include the costs of third party services performed on our properties and wells, as well as gathering and other
equipment used on our properties. In addition, direct expenses include the allocable share of the cost of services performed on
our properties and wells by EnerVest employees. The allocation of the cost of EnerVest employees who perform services on our properties
is based on time sheets maintained by EnerVest’s employees. Direct expenses charged to the joint account also include an
amount determined by EnerVest to be the fair rental value of facilities owned by EnerVest and used in the operation of our properties.
Principal Customers, Marketing Arrangements
and Delivery Commitments
The market for our oil,
natural gas and natural gas liquids production depends on factors beyond our control, including the extent of domestic production
and imports of oil, natural gas and natural gas liquids, the proximity and capacity of natural gas pipelines and other transportation
facilities, the demand for oil, natural gas and natural gas liquids, the marketing of competitive fuels and the effect of state
and federal regulation. The oil and natural gas industry also competes with other industries in supplying the energy and fuel requirements
of industrial, commercial and individual consumers.
Our oil, natural gas and
natural gas liquids production is sold to a variety of purchasers. The terms of sale under the majority of existing contracts are
short–term, usually one year or less in duration. The prices received for oil, natural gas and natural gas liquids sales
are generally tied to monthly or daily indices as quoted in industry publications.
In 2017, Energy
Transfer
Partners, L.P. and EnLink Midstream Partners, L.P. accounted for 15.5% and 11.0%, respectively, of our consolidated oil, natural
gas and natural gas liquids revenues. In 2016, Energy Transfer Partners, L.P., EnLink Midstream Partners, L.P. and Ergon Oil Purchasing,
Inc. accounted for 18.5%, 13.4% and 10.4%, respectively, of our consolidated oil, natural gas and natural gas liquids revenues.
In 2015, Energy Transfer Partners, L.P. and EnLink Midstream Partners, L.P. accounted for 17.1% and 10.8%, respectively, of our
consolidated oil, natural gas and natural gas liquids revenues. We believe that the loss of a major customer would have a temporary
effect on our revenues but that over time, we would be able to replace our major customers.
Information regarding our
delivery commitments is contained in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results
of Operations — Contractual Obligations” contained herein.
Competition
The oil and natural gas
industry is highly competitive. We encounter strong competition from other independent operators and from major oil and natural
gas companies in acquiring properties, contracting for drilling equipment and securing trained personnel. Many of these competitors
have financial and technical resources and staffs substantially larger than ours. As a result, our competitors may be able to pay
more for desirable leases, or to evaluate, bid for and purchase a greater number of properties or prospects than our financial
or personnel resources will permit.
We are also affected by
competition for drilling rigs and the availability of related equipment. In the past, the oil and natural gas industry has experienced
shortages of drilling rigs, equipment, pipe and personnel, which have delayed development drilling and other exploitation activities
and have caused significant price increases. We are unable to predict when, or if, such shortages may occur or how they would affect
our development and exploitation program.
Competition
is also strong for attractive oil and natural gas producing properties, undeveloped leases and drilling rights, and there can be
no assurances that we will be able to compete satisfactorily when attempting to make further acquisitions.
Seasonal Nature of Business
Seasonal
weather conditions and lease stipulations can limit our drilling and producing activities and other operations primarily in certain
areas of the Appalachian Basin, the San Juan Basin and Michigan. As a result, we generally perform the majority of our drilling
in these areas during the summer and autumn months. In addition, the Monroe Field properties in Louisiana are subject to flooding.
These seasonal anomalies can pose challenges for meeting our drilling objectives and increase competition for equipment, supplies
and personnel during the drilling season, which could lead to shortages and increased costs or delay our operations. Generally
demand for natural gas is higher in summer and winter months. In addition, certain natural gas users utilize natural gas storage
facilities and purchase some of their anticipated winter natural gas requirements during off–peak months. This can also lessen
seasonal demand fluctuations.
Environmental, Health and Safety Matters
and Regulation
Our
operations are subject to stringent and complex federal, state and local laws and regulations that govern the protection of the
environment as well as the discharge of materials into the environment. These laws and regulations may, among other things:
|
·
|
require the acquisition of various permits before drilling commences;
|
|
·
|
require the installation of pollution control equipment in connection with operations and place
other conditions on our operations;
|
|
·
|
place restrictions or regulations upon the use or disposal of the material utilized in our operations;
|
|
·
|
restrict the types, quantities and concentrations of various substances that can be released into
the environment or used in connection with drilling, production and transportation activities;
|
|
·
|
limit or prohibit drilling activities on lands lying within
wilderness, wetlands and other protected areas;
|
|
·
|
govern gathering, transportation and marketing of oil and natural gas and pipeline and facilities
construction;
|
|
·
|
require remedial measures to mitigate pollution from former and ongoing operations, such as site
restoration, pit closure and plugging of abandoned wells; and
|
|
·
|
require the expenditure of significant amounts in connection with worker health and safety.
|
These laws, rules
and regulations may also restrict the rate of oil and natural gas production below the rate that would otherwise be possible. The
regulatory burden on the oil and natural gas industry increases the cost of doing business in the industry and consequently affects
profitability. Additionally, Congress and federal, state and local agencies frequently revise environmental laws and regulations,
and such changes could result in increased costs for environmental compliance, such as waste handling, permitting, or cleanup for
the oil and natural gas industry and could have a significant impact on our operating costs. In general, the oil and natural gas
industry has recently been the subject of increased legislation and regulatory attention with respect to environmental matters.
The US Environmental Protection Agency (the “EPA”) has identified environmental compliance by the energy extraction
sector as one of its enforcement initiatives for fiscal years 2018 and 2019 although it is unclear whether the Trump Administration
will implement this initiative. Even if regulatory burdens temporarily ease, the historic trend of more expansive and stricter
environmental regulation may continue for the long term.
The following is a summary
of some of the existing laws, rules and regulations to which our business operations are subject.
Solid and Hazardous
Waste Handling
The federal Resource Conservation
and Recovery Act (“RCRA”) and comparable state statutes regulate the generation, transportation, treatment, storage,
disposal and cleanup of hazardous solid waste. Although oil and natural gas waste generally is exempt from regulations as hazardous
waste under RCRA, we generate waste as a routine part of our operations that may be subject to RCRA. Although a substantial amount
of the waste generated in our operations are regulated as non–hazardous solid waste rather than hazardous waste, there is
no guarantee that the EPA or individual states will not adopt more stringent requirements for the handling of non–hazardous
or exempt waste or categorize some non–hazardous or exempt waste as hazardous in the future. For example, following the filing
of a lawsuit in the US District Court for the District of Columbia in May 2016 by several non-governmental environmental groups
against the EPA for the agency’s failure to timely assess its RCRA Subtitle D criteria regulations for oil and gas wastes,
the EPA and the environmental groups entered into an agreement that was finalized in a consent decree issued by the District Court
on December 28, 2016. Under the decree, the EPA is required to propose no later than March 15, 2019, a rulemaking for revision
of certain Subtitle D criteria regulations pertaining to oil and gas wastes or sign a determination that revision of the regulations
is not necessary. If the EPA proposes a rulemaking for revised oil and gas waste regulations, the Consent Decree requires that
the EPA take final action following notice and comment rulemaking no later than July 15, 2021. Non-exempt waste is subject to more
rigorous and costly disposal requirements. Any such change could result in an increase in our costs to manage and dispose of waste,
which could have a material adverse effect on our results of operations and financial position.
Comprehensive
Environmental Response, Compensation and Liability Act
The Comprehensive Environmental
Response, Compensation and Liability Act (“CERCLA”) imposes joint and several liability for costs of investigation
and remediation and for natural resource damages without regard to fault or legality of the original conduct, on certain classes
of persons with respect to the release into the environment of substances designated under CERCLA as hazardous substances. These
classes of persons, or so–called potentially responsible parties (“PRPs”) include the current and past owners
or operators of a site where the release occurred and anyone who disposed or arranged for the disposal of a hazardous substance
found at the site. CERCLA also authorizes the EPA and, in some instances, third parties to take actions in response to threats
to public health or the environment and to seek to recover from PRPs the costs of such action. Many states have adopted comparable
or more stringent state statutes.
Although CERCLA generally
exempts “petroleum” from the definition of hazardous substance, in the course of our operations, we have generated
and will generate wastes that may fall within CERCLA’s definition of hazardous substance and may have disposed of these wastes
at disposal sites owned and operated by others. Comparable state statutes may not provide a comparable exemption for petroleum.
We may also be the owner or operator of sites on which hazardous substances have been released. To our knowledge, neither we nor
our predecessors have been designated as a PRP by the EPA under CERCLA; we also do not know of any prior owners or operators of
our properties that are named as PRPs related to their ownership or operation of such properties. In the event contamination is
discovered at a site on which we are or have been an owner or operator or to which we sent hazardous substances, we could be liable
for the costs of investigation and remediation and natural resources damages.
We currently own, lease,
or operate numerous properties that have been used for oil and natural gas exploration and production for many years. Although
we believe we have utilized operating and waste disposal practices that were standard in the industry at the time, hazardous substances,
wastes or hydrocarbons may have been released on or under the properties owned or leased by us, or on or under other locations,
including offsite locations, where such substances have been taken for disposal. In addition, some of these properties have been
operated by third parties or by previous owners or operators whose treatment and disposal of hazardous substances, wastes, or hydrocarbons
were not under our control. These properties and the substances disposed or released on them may be subject to CERCLA, RCRA and
analogous state laws. In the future, we could be required to remediate property, including groundwater, containing or impacted
by previously disposed wastes (including wastes disposed or released by prior owners or operators, or property contamination, including
groundwater contamination by prior owners or operators) or to perform remedial plugging operations to prevent future or mitigate
existing contamination.
Clean Water
Act
The Federal Water Pollution
Control Act (the “Clean Water Act”) and analogous state laws impose restrictions and strict controls with respect to
the discharge of pollutants, including discharges, spills and leaks of produced water and other oil and natural gas wastes, into
state waters and waters of the United States. The discharge of pollutants into regulated waters is prohibited, except in accordance
with the terms of a permit issued by the EPA or an analogous state agency. The Clean Water Act also prohibits the discharge of
dredge and fill material in regulated waters, including wetlands, unless authorized by a permit issued by the US Army Corps of
Engineers.
The EPA has issued final rules outlining its position on the
federal jurisdictional reach over waters of the United States. Litigation surrounding this rule is ongoing.
Federal and
state regulatory agencies can impose administrative, civil and criminal penalties, as well as require remedial or mitigation measures,
for non–compliance with discharge permits or other requirements of the Clean Water Act and analogous state laws and regulations.
In the event of an unauthorized discharge of wastes, we may be liable for penalties and cleanup and response costs.
Safe Drinking
Water Act and Hydraulic Fracturing
Hydraulic fracturing involves
the injection of water, sand and chemicals under pressure into formations to fracture the surrounding rock and stimulate production.
Hydraulic fracturing activities are typically regulated by state oil and gas commissions but not at the federal level, as the federal
Safe Drinking Water Act expressly excludes regulation of these fracturing activities (except for fracturing activities involving
the use of diesel). Due to public concerns raised regarding potential impacts of hydraulic fracturing on groundwater quality, there
have been recent developments at the federal, state, regional and local levels that could result in regulation of hydraulic fracturing
becoming more stringent and costly. In December 2016, the EPA released its final report on the potential impacts of hydraulic fracturing
on drinking water resources, concluding that “water cycle” activities associated with hydraulic fracturing may impact
drinking water resources “under some circumstances,” including water withdrawals for fracturing in times or areas of
low water availability; surface spills during the management of fracturing fluids, chemicals or produced water; injection of fracturing
fluids into wells with inadequate mechanical integrity; injection of fracturing fluids directly into groundwater resources; discharge
of inadequately treated fracturing wastewater to surface waters; and disposal or storage of fracturing wastewater in unlined pits.
This report could result in additional regulatory scrutiny that could make it more difficult to perform hydraulic fracturing and
increase our costs of compliance and business.
Legislation was introduced
in prior sessions of Congress to provide for federal regulation of hydraulic fracturing by eliminating the current exemption in
the Safe Drinking Water Act, and, further, to require disclosure of the chemicals used in the fracturing process, but did not pass.
Also, some states and local or regional regulatory bodies have adopted, or are considering adopting, regulations that could restrict
or ban hydraulic fracturing in certain circumstances or that require disclosure of chemical in the fracturing fluids. For example,
New York has imposed a ban on hydraulic fracturing. Further, Pennsylvania has adopted a variety of regulations limiting how and
where fracturing can be performed, and Wyoming and Texas have adopted legislation requiring drilling operators conducting hydraulic
fracturing activities in that state to publicly disclose the chemicals used in the fracturing process. States have also considered
or adopted other restrictions on drilling and completion operations, including requirements regarding casing and cementing of wells;
testing of nearby water wells; restrictions on access to, and usage of, water; and restrictions on the type of chemical additives
that may be used in hydraulic fracturing operations. Further, the EPA has published guidance on hydraulic fracturing using diesel.
Further, the EPA published an effluent limit guideline final rule prohibiting the discharge of wastewater from onshore unconventional
oil and natural gas extraction facilities to publicly owned wastewater treatment plants. The Bureau of Land Management (the “BLM”)
published a final rule that established new or more stringent standards relating to hydraulic fracturing on federal and American
Indian lands but, in late 2017, the BLM repealed this rule.
State and federal regulatory
agencies have also recently focused on a possible connection between the operation of injection wells used for oil and gas wastewater
and an observed increase in minor seismic activity and tremors. When caused by human activity, such events are called induced seismicity.
In a few instances, operators of injection wells in the vicinity of minor seismic events have reduced injection volumes or suspended
operations, often voluntarily. Some state regulatory agencies have modified their regulations to account for induced seismicity.
For example, the Texas Railroad Commission rules allow it to modify, suspend, or terminate a permit based on a determination that
the permitted activity is likely to be contributing to seismic activity. Regulatory agencies are continuing to study possible linkage
between injection activity and induced seismicity.
If new laws or regulations
imposing significant restrictions or conditions on hydraulic fracturing activities are adopted in areas where we conduct business,
we could incur substantial compliance costs and such requirements could adversely delay or restrict our ability to conduct fracturing
activities on our assets.
Oil Pollution Act
The
primary federal law for oil spill liability is the Oil Pollution Act (“OPA”) which amends and augments oil spill provisions
of the Clean Water Act and imposes certain duties and liabilities on certain “responsible parties” related to the prevention
of oil spills and damages resulting from such spills in or threatening United States waters or adjoining shorelines. A liable "responsible
party" includes the owner or operator of a facility, vessel or pipeline that is a source of an oil discharge or that poses
the substantial threat of discharge, or in the case of offshore facilities, the lessee or permittee of the area in which a discharging
facility is located. OPA assigns joint and several liability, without regard to fault, to each liable party for oil removal costs
and a variety of public and private damages. Although defenses exist to the liability imposed by OPA, they are limited. In the
event of an oil discharge or substantial threat of discharge, we may be liable for costs and damages.
Air Emissions
Our operations are subject
to the federal Clean Air Act (“CAA”) and analogous state laws and local ordinances governing the control of emissions
from sources of air pollution. The CAA and analogous state laws require new and modified sources of air pollutants to obtain permits
prior to commencing construction. Major sources of air pollutants are subject to more stringent, federally imposed requirements
including additional permits. Federal and state laws designed to control hazardous (or toxic) air pollutants, might require installation
of additional controls. Administrative enforcement actions for failure to comply strictly with air pollution regulations or permits
are generally resolved by payment of monetary fines and correction of any identified deficiencies. Alternatively, regulatory agencies
could bring lawsuits for civil penalties or seek injunctive relief, requiring us to forego construction, modification or operation
of certain air emission sources.
On
April 17, 2012, the EPA issued final rules to subject oil and natural gas production, storage, processing and transmission operations
to regulation under the New Source Performance Standards (“NSPS”) and the National Emission Standards for Hazardous
Air Pollutants (“NESHAPS”) programs under the CAA, and to impose new and amended requirements under both programs.
The EPA rules include NSPS standards for completions of hydraulically fractured natural gas wells. Beginning January 1, 2015, operators
have been required to capture the natural gas and make it available for use or sale, which can be done through the use of green
completions. The standards are applicable to new hydraulically fractured wells and also existing wells that are refractured. Further,
the finalized regulations also establish specific new requirements, effective in 2012, for emissions from compressors, controllers,
dehydrators, storage tanks, natural gas processing plants and certain other equipment. These rules may require changes to our operations,
including the installation of new equipment to control emissions. We continuously evaluate the effect of new rules on our business.
The EPA has adopted rules
to regulate methane emissions, including from new and modified oil and gas production sources and natural gas processing and transmission
sources, and has announced its intention to regulate methane emissions from existing oil and gas sources. The status of future
regulation remains unclear but if adopted could require changes to our operations, including the installation of new emission control
equipment. Simultaneously with the methane rules, the EPA adopted new rules governing the aggregating of multiple surface sites
into a single-source of air quality permitting purposes, a change which could impact the applicability of permitting requirement
to our operations and subject certain operations to additional regulatory requirements. We continuously evaluate the effect of
these rules on our operations. In late 2016, the BLM adopted rules governing flaring and venting on public and tribal lands, which
could require additional equipment and emissions controls as well as inspection requirements. These rules have been challenged
in court and remain in litigation. Additionally, the US House of Representatives has passed a resolution under the Congressional
Review Act disapproving the rules; Senate action remains pending. If allowed to stand, these additional regulations on our air
emissions is likely to result in increased compliance costs and additional operating restrictions on our business.
National Environmental
Policy Act
Oil and natural gas exploration
and production activities on federal lands may be subject to the National Environmental Policy Act (“NEPA”) which requires
federal agencies, including the Department of Interior, to evaluate major agency actions having the potential to significantly
impact the environment. In the course of such evaluations, an agency will prepare an Environmental Assessment that assesses the
potential direct, indirect and cumulative impacts of a proposed project and, if necessary, will prepare a more detailed Environmental
Impact Statement that may be made available for public review and comment. Depending on the mitigation strategies recommended in
the Environmental Assessment or Environmental Impact Statement, we could incur added costs, which may be significant. Reviews and
decisions under NEPA are also subject to protest or appeal, any or all of which may delay or halt projects. All of our current
exploration and production activities, as well as proposed exploration and development plans, on federal lands require governmental
permits that are subject to the requirements of NEPA. This process has the potential to delay or impose additional conditions upon
the development of oil and natural gas projects.
Climate Change Legislation
More stringent laws and
regulations relating to climate change and greenhouse gases (“GHGs”) may be adopted in the future and could cause us
to incur material expenses in complying with them. In the absence of comprehensive federal legislation on GHG emission control,
the EPA attempted to require the permitting of GHG emissions; although the Supreme Court struck down the permitting requirements,
it upheld the EPA’s authority to control GHG emissions when a permit is required due to emissions of other pollutants. Some
states, regions and localities have adopted or have considered programs to address GHG emissions. In addition, both houses of Congress
previously considered legislation to reduce emissions of greenhouse gases and many states have adopted or considered measures to
establish GHG emissions reduction levels, often involving the planned development of GHG emission inventories and/or GHG cap and
trade programs; this legislation was not passed
.
Depending on the regulatory reach of
new CAA legislation implementing regulations or new EPA and/or state, regional or local rules restricting the emission of GHGs,
we could incur significant costs to control our emissions and comply with regulatory requirements. In addition, the EPA has adopted
a mandatory GHG emissions reporting program which imposes reporting and monitoring requirements on various industries, including
onshore and offshore oil and natural gas production facilities and onshore oil and natural gas processing, transmission, storage
and distribution facilities. Compliance with these requirements has and is anticipated to require us to make investments in monitoring
and recordkeeping equipment. We do not believe, however, that our compliance with applicable monitoring, recordkeeping and reporting
requirements under GHG reporting program as recently amended will have a material adverse effect on our results of operations or
financial position. We have submitted annual reports for emissions starting with our 2012 GHG emissions.
The EPA has adopted rules
to regulate methane emissions, including from new and modified oil and gas production sources and natural gas processing and transmission
sources. The EPA attempted to suspend enforcement of its methane rule, but this action was challenged on appeal and ruled improper.
The EPA is reported to be considering rulemaking to rescind or revise the rule. Simultaneously with the methane rules for new and
modified sources, the EPA adopted new rules governing the aggregating of multiple surface sites into a single-source of air quality
permitting purposes, a change which could impact the applicability of permitting requirement to our operations and subject certain
operations to additional regulatory requirements. We continuously evaluate the effect of these rules on our operations.
On November 18, 2016, the
BLM published a final rule, which became effective on January 17, 2017, that was intended to reduce waste of natural gas from venting,
flaring, and leaks during oil and natural gas production activities on onshore Federal and Indian leases. Unlike the somewhat overlapping
EPA regulations, which apply to new, modified and reconstructed sources, the BLM’s 2016 rule was drafted to address existing
facilities, including a substantial number of existing wells that are likely to be marginal or low-producing, including leak detection
and repair and other requirements regarding methane emissions. Just as the EPA has proposed a temporary stay of some of its requirements
contained in NSPS Subpart OOOOa, as the EPA reconsiders some of these requirements, the BLM issued a proposed rule on February
12, 2018, that concludes that the costs the rule would impose would exceed the benefits it is expected to generate and therefore
reduces those unnecessary compliance burdens, including requirements to write waste minimization plans, meet methane capture targets
and use equipment that meets certain technical standards. It is too recent an event to determine the impact these proposed regulatory
changes may have on oil and gas producers.
In December 2015, the United
States participated in the 21st Conference of the Parties of the United Nations Framework Convention on Climate Change in Paris,
France. The resulting Paris Agreement calls for the parties to undertake “ambitious efforts” to limit the average global
temperature and to conserve and enhance sinks and reservoirs of GHGs. The Paris Agreement went into effect on November 4, 2016.
The Paris Agreement establishes a framework for the parties to cooperate and report actions to reduce GHG emissions. However, on
June 1, 2017, President Trump announced that the United States would withdraw from the Paris Agreement. It is not clear what steps
the Trump Administration plans to take to withdraw from the Paris Agreement, whether a new agreement can be negotiated, or what
terms would be included in such an agreement. Restrictions on GHG emissions that may be imposed could adversely affect the oil
and gas industry. The adoption of legislation or regulatory programs to reduce GHG emissions could require us to incur increased
operating costs, such as costs to purchase and operate emissions control systems, to acquire emissions allowances or comply with
new regulatory requirements. Any GHG emissions legislation or regulatory programs applicable to power plants or refineries could
also increase the cost of consuming, and thereby reduce demand for, the oil and natural gas we produce. Consequently, legislation
and regulatory programs to reduce GHG emissions could have an adverse effect on our business, financial condition and results of
operations.
Because of the lack of
any comprehensive legislative program addressing GHGs, there is a great deal of uncertainty as to how and when federal regulation
of GHGs might take place. Moreover, the federal, regional, state and local regulatory initiatives also could adversely affect the
marketability of the oil, natural gas and natural gas liquids we produce. The impact of such future programs cannot be predicted,
but we do not expect our operations to be affected any differently than other similarly situated domestic competitors.
Endangered Species Act
The
Endangered Species Act was established to protect endangered and threatened species. Pursuant to that act, if a species is listed
as threatened or endangered, restrictions may be imposed on activities that would harm the species or that would adversely affect
that species’ habitat. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act. We conduct
operations on oil and natural gas leases that have species that are listed and species that could be listed as threatened or endangered
under the act. The US Fish and Wildlife Service designates the species’ protected habitat as part of the effort to protect
the species. A protected habitat designation or the mere presence of threatened or endangered species could result in material
restrictions to our use of the land and may materially delay or prohibit land access for oil and natural gas development. It also
may adversely impact the value of the affected leases.
OSHA and Other Laws
and Regulation
To the extent not preempted
by other applicable laws, we are subject to the requirements of the federal Occupational Safety and Health Act (“OSHA”)
and comparable state statutes, where applicable. These laws and the implementing regulations strictly govern the protection of
the health and safety of employees. The OSHA hazard communication standard, the EPA community right–to–know regulations
under the Title III of CERCLA and similar state statutes, where applicable, require that we organize and/or disclose information
about hazardous materials used or produced in our operations. We believe that we are in substantial compliance with these applicable
requirements and with other OSHA and comparable state statute requirements.
We believe that we are
in substantial compliance with all existing environmental laws and regulations applicable to our current operations and that our
continued compliance with existing requirements will not have a material adverse impact on our financial condition and results
of operations. We did not incur any material capital expenditures for remediation or pollution control activities for the years
ended December 31, 2017, 2016 and 2015. Additionally, we are not aware of any environmental issues or claims that will require
material capital expenditures during 2018 or that will otherwise have a material impact on our financial position or results of
operations in the future. However, we cannot assure you that the passage of more stringent laws and regulations in the future will
not have a negative impact our business activities, financial condition and results of operations.
Other Regulation of the
Oil and Natural Gas Industry
The oil and natural gas
industry is extensively regulated by numerous federal, state, local and tribal authorities. Rules and regulations affecting the
oil and natural gas industry are under constant review for amendment or expansion, which could increase the regulatory burden and
the potential for financial sanctions for noncompliance. Also, numerous departments and agencies, both federal and state, are authorized
by statute to issue rules and regulations binding on the oil and natural gas industry and its individual members, some of which
carry substantial penalties for failure to comply. Although the regulatory burden on the oil and natural gas industry increases
our cost of doing business and, consequently, affects our profitability, these burdens generally do not affect us any differently
or to any greater or lesser extent than they affect other companies in the industry with similar types, quantities and locations
of production.
Drilling and
Production
Statutes,
rules and regulations affecting exploration and production undergo constant review and often are amended, expanded and reinterpreted,
making difficult the prediction of future costs or the impact of regulatory compliance attributable to new laws and statutes. The
regulatory burden on the oil and natural gas industry increases the cost of doing business and, consequently, affects its profitability.
Our drilling and production operations are subject to various types of regulation at the federal, state and local levels.
These types of regulation include requiring permits for the drilling of wells, drilling bonds and reports concerning operations.
Most states and some counties and municipalities in which we operate also regulate one or more of the following:
|
·
|
the method of drilling, completing and operating wells;
|
|
·
|
the surface use and restoration of properties upon which
wells are drilled;
|
|
·
|
the venting or flaring of natural gas;
|
|
·
|
the plugging and abandoning of wells;
|
|
·
|
notice to surface owners and other third parties; and
|
|
·
|
produced water and disposal of waste water, drilling fluids and other liquids and solids utilized
or produced in the drilling and extraction process.
|
State
and
federal regulations are generally intended to prevent waste of oil and natural gas, protect correlative rights to produce oil and
natural gas between owners in a common reservoir or formation, control
the amount of oil and natural gas
produced
by assigning allowable rates of production and control contamination of the environment. Pipelines and natural gas plants operated
by other companies that provide midstream services to us are also subject to the jurisdiction of various federal, state and local
authorities, which can affect our operations. State laws also
regulate the size and shape of drilling and spacing units
or proration units governing the pooling of oil and natural gas properties and impose bonding requirements in order to drill and
operate wells. Some states have taken up consideration of forced pooling. Other states rely on voluntary pooling of lands and leases.
States generally impose
a production, ad valorem or severance tax with respect to the production and sale of oil and natural gas within their respective
jurisdictions.
States do not generally regulate wellhead prices or engage in other, similar direct
economic regulation, but there can be no assurance they will not do so in the future.
We do not control the availability
of transportation and processing facilities used in the marketing of our production. For example, we may have to shut–in
a productive natural gas well because of a lack of available natural gas gathering or transportation facilities.
If we conduct operations
on federal, state or Indian oil and natural gas leases, these operations must comply with numerous regulatory restrictions, including
various non–discrimination statutes, royalty and related valuation requirements, and certain of these operations must be
conducted pursuant to certain on-site security regulations and other appropriate permits issued by the BLM, Bureau of Ocean Energy
Management, Bureau of Safety and Environmental Enforcement, Bureau of Indian Affairs, tribal or other appropriate federal, state
and/or Indian tribal agencies.
The Mineral Leasing Act
of 1920 (the “Mineral Act”) prohibits direct or indirect ownership of any interest in federal onshore oil and gas leases
by a foreign citizen of a country that denies “similar or like privileges” to citizens of the United States. Such restrictions
on citizens of a “non-reciprocal” country include ownership or holding or controlling stock in a corporation that holds
a federal onshore oil and gas lease. If this restriction is violated, the corporation’s lease can be cancelled in a proceeding
instituted by the United States Attorney General. Although the regulations of the BLM (which administers the Mineral Act) provide
for agency designations of non–reciprocal countries, there are presently no such designations in effect. It is possible that
our unitholders may be citizens of foreign countries which at some time in the future might be determined to be non–reciprocal
under the Mineral Act.
Federal Regulation
of Oil, Natural Gas and Natural Gas Liquids, including Regulation of Transportation
The availability, terms
and cost of transportation significantly affect sales of natural gas. The interstate transportation and sale for resale of natural
gas are subject to federal regulation, including regulation of the terms, conditions and rates for interstate transportation, storage
and various other matters, primarily by the Federal Energy Regulatory Commission (“FERC”). Federal and state regulations
govern the price and terms for access to natural gas pipeline transportation. FERC’s regulations for interstate natural gas
transmission in some circumstances may also affect the intrastate transportation of natural gas. FERC regulates the rates, terms
and conditions applicable to the interstate transportation of natural gas by pipelines under the Natural Gas Act as well as under
Section 311 of the Natural Gas Policy Act.
Under FERC’s current
regulatory regime, interstate transportation services must be provided on an open-access, non-discriminatory basis at cost-based
rates or at market-based rates if the transportation market at issue is sufficiently competitive. The FERC-regulated tariffs, under
which interstate pipelines provide such open-access transportation service, contain strict limits on the means by which a shipper
releases its pipeline capacity to another potential shipper, which provisions include FERC’s “shipper-must-have-title”
rule. Violations by a shipper (i.e., a pipeline customer) of FERC’s capacity release rules or shipper-must-have-title rule
could subject a shipper to substantial penalties from FERC.
With respect to its regulation
of natural gas pipelines under the NGA, FERC has not generally required the applicant for construction of a new interstate natural
gas pipeline to produce evidence of the greenhouse gas (“GHG”) emissions of the proposed pipeline’s customers.
In August 2017, the US Circuit Court of Appeals for the DC Circuit issued a decision remanding a natural gas pipeline certificate
application to FERC, which required FERC to revise its environmental impact statement for the proposed pipeline to take into account
GHG carbon emissions from downstream power plants using natural gas transported by the new pipeline. It is too early to determine
the impacts of this Court decision, but it could be significant.
Sales
of our oil and natural gas liquids are also affected by the availability, terms and costs of transportation. The rates, terms,
and conditions applicable to the interstate transportation of oil and natural gas liquids by pipelines are regulated by the FERC
under the Interstate Commerce Act (the “ICA”). FERC has implemented a simplified and generally applicable ratemaking
methodology for interstate oil and natural gas liquids pipelines to fulfill the requirements of Title XVIII of the Energy Policy
Act of 1992 comprised of an indexing system to establish ceilings on interstate oil and natural gas liquids pipeline rates. In
addition, FERC issued a declaratory order in November 2017, involving a marketing affiliate of an oil pipeline, which held that
certain arrangements between an oil pipeline and its marketing affiliate would violate the ICA’s anti-discrimination provisions.
FERC held that providing transportation service to affiliates at what is essentially the variable cost of the movement, while requiring
non-affiliated shippers to pay the (higher) filed tariff rate, would violate the ICA. Rehearing has been sought of this FERC order
by various pipelines. It is too recent an event to determine the impact this FERC order may have on oil pipelines, their marketing
affiliates, and the price of oil and other liquids transported by such pipelines.
Gathering
service, which occurs on pipeline facilities located upstream of FERC-jurisdictional interstate transportation services, is regulated
by the states onshore and in state waters. Depending on changes in the function performed by particular pipeline facilities, FERC
has in the past reclassified certain FERC-jurisdictional transportation facilities as non-jurisdictional gathering facilities and
FERC has reclassified certain non-jurisdictional gathering facilities as FERC-jurisdictional transportation facilities. Any such
changes could result in an increase to our costs of transporting gas to point-of-sale locations.
The
pipelines used to gather and transport natural gas being produced by us are also subject to regulation by the US Department of
Transportation (the “DOT”) under the Natural Gas Pipeline Safety Act of 1968, as amended (“NGPSA”), the
Pipeline Safety Act of 1992, as reauthorized and amended (“Pipeline Safety Act”), and the Pipeline Safety, Regulatory
Certainty, and Job Creation Act of 2011. The DOT Pipeline and Hazardous Materials Safety Administration (“PHMSA”) has
established a risk–based approach to determine which gathering pipelines are subject to regulation and what safety standards
regulated gathering pipelines must meet. In addition, the PHMSA had initially considered regulations regarding, among other things,
the designation of additional high consequence areas along pipelines, minimum requirements for leak detection systems, installation
of emergency flow restricting devices, and revision of valve spacing requirements. In October 2015, the PHMSA issued proposed new
safety regulations for hazardous liquid pipelines, including a requirement that all hazardous liquid pipelines have a system for
detecting leaks and that operators establish a timeline for inspections of affected pipelines following extreme weather events
or natural disasters. If such revisions to gathering line regulations and liquids pipelines regulations are enacted by the PHMSA,
we could incur significant expenses.
Transportation
of our oil, natural gas liquids and purity components (ethane, propane, butane, iso–butane, and natural gasoline) by rail
is also subject to regulation by the DOT’s PHMSA and the DOT’s Federal Railroad Administration (“FRA”)
under the Hazardous Materials Regulations at 49 CFR Parts 171-180 (“HMR”), including Emergency Orders by the FRA and
new regulations being proposed by the PHMSA, arising due to the consequences of train accidents and the increase in the rail transportation
of flammable liquids.
Although natural gas sales
prices are currently unregulated, Congress historically has been active in the area of natural gas regulation. We cannot predict
whether new legislation to regulate natural gas might be proposed, what proposals, if any, might actually be enacted by Congress
or the various state legislatures, and what effect, if any, the proposals might have on the operations of the underlying properties.
Sales of oil and natural gas liquids are not currently regulated and are made at market prices.
Exports of US Crude Oil Production and
Natural Gas Production
The federal government
has recently ended its decades-old prohibition of exports of oil produced in the lower 48 states of the US. The general perception
in the industry is that ending the prohibition of exports of oil produced in the US will be positive for producers of US oil. In
addition, the US Department of Energy (the “DOE”) authorizes exports of natural gas, including exports of natural gas
by pipelines connecting US natural gas production to pipelines in Mexico, which are expected to increase significantly with the
changes taking place in the Mexican government’s regulations of the energy sector in Mexico. In addition, the DOE authorizes
the export of liquefied natural gas (“LNG”) through LNG export facilities, the construction of which are regulated
by FERC. In the third quarter of 2016, the first quantities of natural gas produced in the lower 48 states of the US were exported
as LNG from the first of several LNG export facilities being developed and constructed in the US Gulf Coast region. While it is
too recent an event to determine the impact this change may have on our operations or our sales of natural gas, the perception
in the industry is that this will be a positive development for producers of US natural gas.
Hydraulic Fracturing
Most of our oil and natural
gas properties are subject to hydraulic fracturing to economically develop the properties. The hydraulic fracturing process is
integral to our drilling and completion costs in these areas and typically represent up to 60% of the total drilling/completion
costs per well.
We diligently review best
practices and industry standards, and comply with all regulatory requirements in the protection of these potable water sources.
Protective practices include, but are not limited to, setting multiple strings of protection pipe across the potable water sources
and cementing these pipes from setting depth to surface, continuously monitoring the hydraulic fracturing process in real time,
and disposing of all non–commercially produced fluids in certified disposal wells at depths below the potable water sources.
In compliance with laws
enacted in various states, we will disclose hydraulic fracturing data to the appropriate chemical registry. These laws generally
require disclosure for each chemical ingredient that is subject to the requirements of OSHA regulations, as well as the total volume
of water used in the hydraulic fracturing treatment.
There have not been any material
incidents, citations or suits related to our hydraulic fracturing activities involving violations of environmental laws and regulations.
Other Regulation
In addition to the regulation
of oil and natural gas pipeline transportation rates, the oil and natural gas industry generally is subject to compliance with
various other federal, state and local regulations and laws. Some of those laws relate to occupational safety, resource conservation
and equal employment opportunity. We do not believe that compliance with these laws will have a material adverse effect upon our
unitholders.
Insurance
In accordance with industry
practice, we maintain insurance against some, but not all, of the operating risks to which our business is exposed. We currently
have insurance policies that include coverage for control of well, general liability (includes sudden and accidental pollution),
physical damage to our oil and gas natural properties, auto liability, worker’s compensation and employer's liability, among
other things.
Currently, we have general
liability insurance coverage up to $1.0 million per occurrence, which includes sudden and accidental environmental liability coverage
for the effects of pollution on third parties arising from our operations. Our insurance policies contain maximum policy limits
and in most cases, deductibles that must be met prior to recovery. These insurance policies are subject to certain customary exclusions
and limitations. In addition, we maintain $100.0 million in excess liability coverage, which is in addition to and triggered if
the general liability per occurrence limit is reached.
We do not currently have
any insurance policies in effect that are intended to provide coverage for losses solely related to hydraulic fracturing operations.
However, we believe our general liability and excess liability insurance policies would cover third party claims related to hydraulic
fracturing operations and associated legal expenses, in accordance with, and subject to, the terms of such policies.
We re–evaluate the
purchase of insurance, coverage limits and deductibles annually. Future insurance coverage for the oil and natural gas industry
could increase in cost and may include higher deductibles or retentions. In addition, some forms of insurance may become unavailable
in the future or unavailable on terms that are economically acceptable. No assurance can be given that we will be able to maintain
insurance in the future at rates that we consider reasonable, and we may elect to self–insure or maintain only catastrophic
coverage for certain risks in the future.
Employees
EV Management, the
general partner of our general partner, has six full–time employees who spend a significant amount of their time on our operations.
At December 31, 2017, EnerVest, the sole member of EV Management, had 1,179 full–time employees, including over 89 geologists,
engineers and land professionals. To carry out our operations, EnerVest employs the people who will provide direct support to our
operations. None of these employees are covered by collective bargaining agreements. We consider EV Management’s relationship
with its employees to be good, and EnerVest considers its relationship with its employees to be good.
Offices
We do not have any material
owned or leased property (other than our interests in oil and gas properties). Under our omnibus agreement, EnerVest provides us
office space for our executive officers and other employees at EnerVest’s offices in Houston, Texas.
Available Information
Our annual reports on Form
10–K, quarterly reports on Form 10–Q, current reports on Form 8–K and amendments to those reports filed or furnished
pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), are made
available free of charge on our website at www.evenergypartners.com as soon as reasonably practicable after these reports have
been electronically filed with, or furnished to, the SEC. These documents are also available on the SEC’s website at www.sec.gov
or you may read and copy any materials that we file with the SEC at the SEC’s Public Reference Room at 100 F Street, NE,
Washington DC 20549. Our website also includes our Code of Business Conduct and the charters of our audit committee and compensation
committee. No information from either the SEC’s website or our website is incorporated herein by reference.
ITEM 1A. RISK FACTORS
Our
business and operations are subject to many risks. The risks described below, in addition to the risks described in “Item
1. Business” and “Item 7A. Quantitative and Qualitative Disclosures About Market Risk” of this annual report,
may not be the only risks we face, as our business and operations may also be subject to risks that we do not yet know of, or that
we currently believe are immaterial. You should carefully consider the following risk factors together with all of the other information
included in this annual report, including the financial statements and related notes, when deciding to invest in us. You should
be aware that the occurrence of any of the events described in this Risk Factors section and elsewhere in this annual report could
have a material adverse effect on our business, financial position, results of operations and cash flows and the trading price
of our securities could decline and you could lose all or part of your investment.
Risks Related to
our Restructuring and our Indebtedness
On April 2, 2018, we filed voluntary
petitions commencing the Chapter 11 Cases under the Bankruptcy Code. The Chapter 11 Cases and the Restructuring may have a material
adverse impact on our business, financial condition, results of operations, and cash flows. In addition, the Chapter 11 Cases and
the Restructuring may have a material adverse impact on the trading price and ultimately are expected to result in the cancelation
and discharge of our securities, including our equity units. Our proposed Plan, if confirmed by the Bankruptcy Court and consummated,
will govern distributions to and the recoveries of holders of our securities.
We have engaged financial
and legal advisors to assist us in, among other things, analyzing various strategic alternatives to address our liquidity and capital
structure, including strategic and refinancing alternatives to restructure our indebtedness in private transactions. These restructuring
efforts led to the execution of the Restructuring Support Agreement on March 13, 2018. Consistent with the Restructuring Support
Agreement, on April 2, 2018, we commenced the Chapter 11 Cases in the Bankruptcy Court.
Commencing the Chapter
11 Cases could have a material adverse effect on our business, financial condition, results of operations and liquidity. So long
as the Chapter 11 Cases continue, our senior management may be required to spend a significant amount of time and effort dealing
with the reorganization instead of focusing on our business operations. Bankruptcy Court protection also may make it more difficult
to retain management and the key personnel necessary to the success and growth of our business. In addition, during the period
of time we are involved in a bankruptcy proceeding, our customers and suppliers might lose confidence in our ability to reorganize
our business successfully and may seek to establish alternative commercial relationships.
Additionally, all of our
indebtedness is senior to the existing common units in our capital structure. As a result, if the Bankruptcy Court confirms the
Plan, then our common units will be canceled, resulting in a limited recovery for unitholders, and would place unitholders at a
significant risk of losing all of their investment in our units. More specifically, pursuant to the Plan, existing common units
would be canceled and would receive 5% of the new common stock (subject to dilution) and five-year warrants for 8% of the new common
stock (subject to dilution) in the new, reorganized company, on a pro rata basis, with an exercise price set at an equity value
at which the holders of the Senior Notes would receive a recovery equal to par plus accrued and unpaid interest as of the Petition
Date in respect of the Senior Notes (after taking into account value dilution on account of the three percent of the new common
stock to be allocated to the participants in the management incentive plan on the Effective Date pursuant to a management incentive
plan).
Other significant risks
include the following:
|
·
|
our ability to prosecute, confirm and consummate the Plan;
|
|
·
|
our ability to obtain Bankruptcy Court approval of operational and procedural motions in the Chapter
11 Cases and the outcomes of Bankruptcy Court rulings and of the Chapter 11 Cases in general;
|
|
·
|
risks associated with third party motions or objections in the Chapter 11 Cases, which may interfere
with our business operations or our ability to confirm the Plan;
|
|
·
|
the high costs of bankruptcy and related fees;
|
|
·
|
our ability to obtain sufficient financing to emerge from bankruptcy and execute our business plan post-emergence;
|
|
·
|
our ability to maintain our relationships with our suppliers, service providers, customers and other third parties;
|
|
·
|
potential increased difficulty in retaining and motivating our key employees through the process of reorganization, and potential
increased difficulty in attracting new employees;
|
|
·
|
significant time and effort required to be spent by our senior management in dealing with the bankruptcy and restructuring
activities rather than focusing exclusively on business operations; and
|
|
·
|
the actions and decisions of the holders of our existing indebtedness and other third parties who have interests in our Chapter
11 Cases that may be inconsistent with our plans.
|
Because of the risks and uncertainties associated with Chapter 11
Cases, we cannot predict or quantify the ultimate impact that events occurring during the Chapter 11 Cases may have on our business,
cash flows, liquidity, financial condition and results of operations, nor can we predict the ultimate impact that events occurring
during the Chapter 11 Cases may have on our corporate or capital structure.
Any Partnership de-levering transaction or change in the Partnership’s
capital structure, including in connection with a plan of reorganization in the Chapter 11 Cases, may involve significant taxable
cancellation-of-debt or other income, such that the Partnership’s unitholders may be required to pay taxes on their share
of such income even if they do not receive any cash distributions from the Partnership.
Our unitholders, as the
owners of the Partnership, are allocated the taxable income (or loss) of the Partnership for income tax purposes. Each unitholder
is required to report its share of our taxable income on its federal and applicable state and local income tax returns. Accordingly,
depending on their individual tax position, each unitholder may be required to pay income taxes on its share of our taxable income,
even if the unitholder receives no cash distributions from the Partnership, which could happen.
The Restructuring pursuant
to the Plan is intended to be structured in a manner that minimizes, to the extent possible, the negative tax impact of cancellation
of debt income (“CODI”) to our unitholders. Nevertheless, such transaction and any or other transactions we may engage
in to de-lever the Partnership and manage its liquidity could result in the allocation of substantial taxable income to our unitholders
without a corresponding cash distribution and possibly without any cash distribution. CODI may or may not be generated. The generation
of CODI will depend on whether the principal amount of the outstanding Senior Notes, plus accrued and unpaid interest, exceeds
the fair value of the equity received by the noteholders upon emergence from bankruptcy. Because the valuation upon emergence from
bankruptcy is something determined in the future, we are currently unable to determine whether, and by how much, if any, the principal
amount, plus accrued and unpaid interest, of the outstanding Senior Notes will exceed such valuation. If CODI is generated, it
would be allocated to the unitholders of record as of the opening of the first NYSE trading day of the month we emerge from bankruptcy
(the “CODI Allocation Date”). No CODI should be allocated to a unitholder with respect to units which are sold prior
to the CODI Allocation Date. In certain cases, CODI can be realized even when existing debt is modified with no reduction in such
debt’s stated principal amount. We will not make a corresponding cash distribution with respect to such allocation of CODI.
Therefore, any CODI will cause a unitholder to be allocated income with respect to our units with no corresponding distribution
of cash to fund the payment of the resulting tax liability to such unitholder. Such CODI, like other items of our income, gain,
loss, and deduction that are allocated to our unitholders, will be taken into account in the taxable income of the holders of our
units as appropriate. CODI is not itself an additional tax due but is an amount that must be reported as ordinary income by the
unitholder, potentially increasing such unitholder’s tax liabilities.
Our unitholders may not
have sufficient tax attributes (including allocated past and current losses from our activities) available to offset such allocated
CODI. Moreover, CODI that is allocated to our unitholders will be ordinary income, and, as a result, it may not be possible for
our unitholders to offset such CODI by claiming capital losses with respect to their units, even if such units are cancelled for
no consideration in connection with such a restructuring. Importantly, certain exclusions that are available with respect to CODI
generally do not apply at the partnership level, and any solvent unitholder that is not in a Chapter 11 proceeding will be unable
to rely on such exclusions.
Each unitholder’s
tax situation is different. The ultimate effect to each unitholder will depend on the unitholder’s individual tax position
with respect to its units. Additionally, certain of our unitholders may have more losses available than other of our unitholders,
and such losses may be available to offset some or all of the CODI that could be generated in a strategic transaction involving
our debt. Accordingly, unitholders are highly encouraged to consult, and depend on, their own tax advisors in making such evaluation.
Additionally, the Partnership
expects to emerge from the Chapter 11 Cases as a corporation, including for US federal income tax purposes.
During the existence of an event of default
and the Chapter 11 Cases, we have no borrowing capacity under our credit agreement. Unless we are able to successfully restructure
our existing indebtedness we may not be able to continue as a going concern.
Over the periods presented
in the accompanying financial statements, our growth has been funded through a combination of borrowings under our credit agreement,
the sale of assets and cash flows from operating activities. We currently have limited access to additional capital. During the
existence of an event of default, we have no availability under our credit agreement.
The accompanying Consolidated
Financial Statements have been prepared on a going concern basis which contemplates continuity of operations, realization of assets
and liquidation of liabilities in the ordinary course of business. As a result of losses incurred, there is no assurance that the
carrying amounts of assets will be realized or that liabilities will be settled for the amounts recorded. Unless we are able to
successfully restructure our existing indebtedness under the Chapter 11 Cases we may not be able to continue as a going concern.
There can be no assurance that the Plan as outlined in the Restructuring Support Agreement (or any other plan of reorganization)
will be confirmed by the Bankruptcy Court and consummated.
Delays in our Chapter 11 Cases may increase
the risks of our being unable to reorganize our business and emerge from bankruptcy and increase our costs associated with the
bankruptcy process.
Our Restructuring Support
Agreement contemplates the confirmation of the Plan through an orderly prepackaged plan of reorganization, but there can be no
assurance that we will be able to confirm and consummate the Plan. In addition to obtaining the required votes of stakeholders
(which requirement we believe we satisfied before commencing the Chapter 11 Cases), the requirements for the Bankruptcy Court to
confirm a plan of reorganization include, among other judicial findings, that:
|
·
|
we acted in accordance with the applicable provisions of the Bankruptcy Code; and
|
|
·
|
the plan of reorganization has been proposed in good faith and not by any means forbidden by law;
and
|
|
·
|
the plan of reorganization does not unfairly discriminate and is fair and equitable with respect
to those classes of claims and interests that did not vote to accept the plan of reorganization.
|
We may not be able to confirm
the Plan promptly, if at all. In such event, a prolonged Chapter 11 bankruptcy proceeding could adversely affect our relationships
with customers, suppliers and employees, among other parties, which in turn could adversely affect our business, competitive position,
financial condition, liquidity and results of operations and our ability to continue as a going concern. A weakening of our financial
condition, liquidity and results of operations could adversely affect our ability to implement our proposed Plan (or any other
plan of reorganization). If no plan is confirmed by the Bankruptcy Court, we may be forced to liquidate our assets.
In addition, the confirmation and effectiveness of the Plan is subject
to certain conditions and requirements in addition to those described above that may not be satisfied.
We believe it is likely that our common units will substantially
decrease in value in our Chapter 11 Cases.
We have a significant amount
of indebtedness that is senior to our common units in our capital structure. We believe that the existing common units will substantially
decrease in value during and after emergence from the Chapter 11 Cases. Accordingly, any trading in our common units during the
pendency of our Chapter 11 Cases is highly speculative and poses substantial risks to purchasers of our common units.
Pursuant to the Plan, existing
common units will be canceled and will receive 5% of the new common stock (subject to dilution) and five-year warrants for 8% of
the new common stock (subject to dilution) in the new, reorganized company, on a pro rata basis, with an exercise price set at
an equity value at which the holders of the Senior Notes would receive a recovery equal to par plus accrued and unpaid interest
as of the Petition Date in respect of the Senior Notes (after taking into account value dilution on account of the three percent
of the new common stock to be allocated to the participants in the management incentive plan on the Effective Date pursuant to
a management incentive plan).
The Restructuring Support Agreement is
subject to significant conditions and milestones that may be difficult for us to satisfy.
There are certain material
conditions we must satisfy under the Restructuring Support Agreement, including the timely satisfaction of milestones in the Chapter
11 Cases, including for confirmation and consummation of the Plan. Our ability to timely complete such milestones is subject to
risks and uncertainties, many of which are beyond our control.
We may not be able to obtain confirmation
of the Plan.
There can be no assurance
that the Plan as outlined in the Restructuring Support Agreement (or any other plan of reorganization) will be confirmed by the
Bankruptcy Court. As a result, investors should exercise caution with respect to existing and future investments in our securities.
The success of any reorganization will depend on approval by the Bankruptcy Court, and there can be no guarantee of success with
respect to the Plan or any other plan of reorganization. For instance, we might receive objections from stakeholders to confirmation
of the Plan or other relief we seek in the Chapter 11 Cases. We cannot predict the impact of any such objections. Any objection
may cause us to devote significant resources in response which could materially and adversely affect our business, financial condition
and results of operations.
If the Plan is not confirmed
by the Bankruptcy Court, it is unclear whether we would be able to reorganize our business and what, if any, distributions holders
of claims against us, including holders of our existing indebtedness, would ultimately receive with respect to their claims. The
Plan provides for a recovery to our public unitholders. If the Plan is not confirmed, we believe that any other plan is likely
to provide a reduced recovery (or no recovery at all) to our unitholders and will place them at significant risk of losing most
or all of their investments in the Partnership. See Note 2 of the Notes to Consolidated Financial Statements included under “Item
8. Financial Statements and Supplementary Data.”
There can be no assurance
to whether we will successfully reorganize and emerge from the Chapter 11 Cases or, if we do successfully reorganize, as to when
we would emerge from the Chapter 11 Cases. If we are unable to successfully reorganize, we may not be able to continue our operations.
If the Restructuring Support Agreement
is terminated, our ability to confirm and consummate the Plan could be materially and adversely affected.
The Restructuring Support
Agreement contains a number of termination events, upon the occurrence of which certain parties to the Restructuring Support Agreement
may terminate the agreement. If the Restructuring Support Agreement is terminated, each of the parties thereto will be released
from their obligations in accordance with the terms of the Restructuring Support Agreement. Such termination may result in the
loss of support for the Plan by the parties to the Restructuring Support Agreement, which could adversely affect our ability to
confirm and consummate the Plan. If the Plan is not consummated, there can be no assurance that any new Chapter 11 plan of reorganization
would be as favorable to holders of claims and units as the current Plan.
Even if a Chapter 11 plan of reorganization
is consummated, we may not be able to achieve our stated goals and there is substantial doubt regarding our ability to continue
as a going concern.
Even if the Plan or any
other Chapter 11 plan of reorganization is consummated, we may continue to face a number of risks, such as further deterioration
in commodity prices or other changes in economic conditions, changes in our industry, changes in demand for our oil and gas and
increasing expenses. Some of these risks become more acute when a case under the Bankruptcy Code continues for a protracted period
without indication of how or when the case may be completed. As a result of these risks and others, we cannot guarantee that any
Chapter 11 plan of reorganization will achieve our stated goals.
In addition, at the outset
of the Chapter 11 Cases, the Bankruptcy Code gives the Debtors the exclusive right to propose a plan of reorganization and prohibits
creditors, equity security holders and others from proposing a plan. Accordingly, we currently have the exclusive right to propose
a plan of reorganization. If that right is terminated, however, or the exclusivity period expires, there could be a material adverse
effect on our ability to achieve confirmation of a plan of reorganization in order to achieve our stated goals.
Furthermore, even if our
debts are reduced or discharged through a plan of reorganization, we may need to raise additional funds through public or private
debt or equity financing or other various means to fund our business after the completion of the Chapter 11 Cases. Our access to
additional financing may be limited, if it is available at all. Therefore, adequate funds may not be available when needed or may
not be available on favorable terms, if they are available at all.
As a result of the entry
into the Chapter 11 Cases, even with the creditor support for the restructuring under the Restructuring Support Agreement, there
is substantial doubt regarding our ability to continue as a going concern. As a result, we cannot give any assurance of our ability
to continue as a going concern, even if a plan of reorganization is confirmed.
Our common units will be delisted from
trading on the NASDAQ Capital Market, and no longer been listed on a national securities exchange effective following the commencement
of the Chapter 11 Cases, and will be quoted only in the over-the-counter market, which could negatively affect the price and liquidity
of our common units.
In connection with filing
the Chapter 11 Cases, we expect to receive a notice from the NASDAQ stating that our units will be delisted from the NASDAQ Capital
Market. The delisting decision will be reached under the NASDAQ Listing Rules 5101, 5110(b), and IM-5101-1 following our announcement
that the Debtors filed the Chapter 11 Cases. Trading of our common units will be suspended by the NASDAQ, and a Form 25-NSE will
be filed with the Securities and Exchange Commission, which will remove our securities from listing and registration on the NASDAQ
Capital Market.
Following the expected
delisting from the NASDAQ Capital Market, our units will commence trading on the OTC Pink Marketplace under the symbol “EVEPQ”.
We can provide no assurance that its units will commence or continue to trade on this market, whether broker-dealers will continue
to provide public quotes of the units on this market, whether the trading volume of the units will be sufficient to provide for
an efficient trading market or whether quotes for the units will continue on this market in the future.
The OTC Pink is a significantly
more limited market than the NASDAQ Capital Market, and the quotation of our common units on the OTC Pink Marketplace may result
in a less liquid market available for existing and potential shareholders to trade our common units. This could further depress
the trading price of our common units and could also have a long-term adverse effect on our ability to raise capital. There can
be no assurance that any public market for our common units will exist in the future or that we will be able to relist our common
units on a national securities exchange. In connection with the delisting of our common units, there may also be other negative
implications, including the potential loss of confidence in us by suppliers, customers and employees and the loss of institutional
investor interest in our common units
In certain instances, a Chapter 11 case
may be converted to a case under Chapter 7 of the Bankruptcy Code.
Upon a showing of cause,
the Bankruptcy Court may convert our Chapter 11 Cases to a case under Chapter 7 of the Bankruptcy Code. In such event, a Chapter
7 trustee would be appointed or elected to liquidate our assets for distribution in accordance with the priorities established
by the Bankruptcy Code. We believe that liquidation under chapter 7 would result in significantly smaller distributions being made
to our creditors than those provided for in our Plan because of (i) the likelihood that the assets would have to be sold or otherwise
disposed of in a distressed fashion over a short period of time rather than in a controlled manner and as a going concern, (ii)
additional administrative expenses involved in the appointment of a Chapter 7 trustee, and (iii) additional expenses and claims,
some of which would be entitled to priority, that would be generated during the liquidation and from the rejection of leases and
other executory contracts in connection with a cessation of operations.
As a result of the Chapter 11 Cases,
our historical financial information may not be indicative of our future performance, which may be volatile.
During the Chapter 11 Cases,
we expect our financial results to continue to be volatile as restructuring activities and expenses, contract terminations and
rejections, and claims assessments significantly impact our consolidated financial statements. As a result, our historical financial
performance is likely not indicative of our financial performance after the date of the filing of the Chapter 11 Cases. In addition,
if we emerge from Chapter 11, the amounts reported in subsequent consolidated financial statements may materially change relative
to historical consolidated financial statements, including as a result of revisions to our operating plans pursuant to the Plan.
We also may be required to adopt fresh start accounting, in which case our assets and liabilities will be recorded at fair value
as of the fresh start reporting date, which may differ materially from the recorded values of assets and liabilities on our consolidated
balance sheets. Our financial results after the application of fresh start accounting also may be different from historical trends.
We may be subject
to claims that will not be discharged in the Chapter 11 Cases, which could have a material adverse effect on our financial condition
and results of operations.
The Bankruptcy Court provides
that the confirmation of a plan of reorganization discharges a debtor from substantially all debts arising prior to confirmation.
With few exceptions, all claims that arose prior to April 2, 2018, or before confirmation of the Plan (i) would be subject to compromise
and/or treatment under the Plan and/or (ii) would be discharged in accordance with the Bankruptcy Code and the terms of the Plan.
Any claims not ultimately discharged pursuant to the Plan could be asserted against the reorganized entities and may have an adverse
effect on our financial condition and results of operations on a post-reorganization basis.
We have significant exposure to fluctuations
in commodity prices since none of our estimated future production is covered by commodity derivative contracts and we may not be
able to enter into commodity derivative contracts covering our estimated future production on favorable terms or at all.
During the Chapter 11 Cases,
our ability to enter into commodity derivative contracts covering estimated future production will be limited. As a result, we
may not be able to enter into commodity derivative contracts covering our production in future periods on favorable terms or at
all. If we cannot or choose not to enter into commodity derivative contracts in the future, we could be more affected by changes
in commodity prices. Our inability to hedge the risk of low commodity prices in the future, on favorable terms or at all, could
have a material adverse impact on our business, financial condition and results of operations.
We may experience employee attrition
as a result of the Chapter 11 Cases.
As a result of the Chapter
11 Cases, we may experience employee attrition, and our employees may face considerable distraction and uncertainty. A loss of
key personnel or material erosion of employee morale could adversely affect our business and results of operations. Our ability
to engage, motivate and retain key employees or take other measures intended to motivate and incentivize key employees to remain
with us through the pendency of the Chapter 11 Cases is limited by restrictions on implementation of incentive programs under the
Bankruptcy Code. The loss of services of members of our senior management team could impair our ability to execute our strategy
and implement operational initiatives, which would be likely to have a material adverse effect on our financial condition, liquidity
and results of operations.
Risks Related to Our Business
The board of directors of our general
partner has suspended quarterly cash distributions on our common units and, in connection with the transactions contemplated by
the Plan in the Chapter 11 Cases, we will convert into an entity that will not seek to pay a quarterly cash distribution or any
other amount to equity holders.
Since
2016, we have suspended cash distributions to the holders of our common units in order to conserve cash and improve our liquidity.
In connection with the transactions contemplated by the Plan in the Chapter 11 Cases, the Partnership will convert into a corporation
or other entity with a primary business objective other than generating stable cash flows that will allow for quarterly cash distributions
to equity holders.
If we were to resume
quarterly cash distributions, the cash available to service our indebtedness or otherwise operate our business may be limited and
we may be required to incur additional debt to enable us to pay such quarterly distributions.
If
we were to resume quarterly cash distributions, we may not accumulate significant amounts of cash. These distributions could significantly
reduce the cash available to us in subsequent periods to make payments on our indebtedness or otherwise operate our business. For
more information, see below “—- Covenants in our credit agreement may restrict our ability to resume and sustain distributions.”
Covenants in
our credit agreement may restrict our ability to resume and sustain distributions.
The terms of our credit
agreement may restrict our ability to pay distributions if we do not satisfy the financial and other covenants in the credit facility.
Prior to reinstating distributions, we will ensure that we are, and will continue to be, in compliance with the covenants contained
in our credit agreement. As of April 2, 2018, the Partnership was in default under certain of its debt instruments. The Partnership’s
filing of the Chapter 11 Cases accelerated the Partnership’s obligations under its credit facility and the Senior Notes.
Additionally, events of default, including cross-defaults, are present, including the receipt of a going concern explanatory paragraph
from the Partnership’s independent registered public accounting firm on the Partnership’s consolidated financial statements,
subject to a 30 day grace period. As a result, our credit facility could become due and payable because of this event of default.
This has a material, adverse effect on our business, including our ability to resume and sustain distributions.
Oil, natural gas and natural gas liquids
prices are highly volatile and depressed prices can significantly and adversely affect our cash flows from operations and our ability
to service our debt obligations.
Our
revenue, profitability and cash flow depend upon the prices for oil, natural gas and natural gas liquids. Prices for these commodities
have been depressed when compared with historical prices prior to the second half of 2014. The prices we receive for our production
are volatile and a drop in prices can significantly affect our financial results and impede our growth, including our ability to
maintain or increase our borrowing capacity, to repay current or future indebtedness and to obtain additional capital on attractive
terms. Changes in prices have a significant impact on the value of our reserves and on our cash flows. Prices may fluctuate widely
in response to relatively minor changes in supply and demand, market uncertainty and a variety of additional factors that are beyond
our control, such as:
|
·
|
the domestic and foreign supply of and demand for oil, natural gas and natural gas liquids;
|
|
·
|
the amount of added production from development of unconventional natural gas reserves;
|
|
·
|
the price and quantity of foreign imports of oil, natural gas and natural gas liquids;
|
|
·
|
the level of consumer product demand;
|
|
·
|
the value of the U.S dollar relative to the currencies of other countries;
|
|
·
|
market uncertainty and overall domestic and global economic conditions;
|
|
·
|
political and economic conditions and events in foreign oil and natural gas producing countries,
including embargoes, continued hostilities in the Middle East and other sustained military campaigns, conditions in South America,
China and Russia, and acts of terrorism or sabotage;
|
|
·
|
the increasing exports of oil produced in the US and natural gas produced in the US from LNG liquefaction
facilities;
|
|
·
|
the ability of members of the Organization of Petroleum Exporting Countries to agree to and maintain
oil price and production controls;
|
|
·
|
technological advances affecting energy production and consumption;
|
|
·
|
domestic and foreign governmental regulations and taxation;
|
|
·
|
the impact of energy conservation efforts and the increasing use of renewable sources of energy
such as wind energy and solar photovoltaic energy;
|
|
·
|
the proximity and capacity of natural gas pipelines and other transportation facilities to our
production; and
|
|
·
|
the price and availability of alternative fuels.
|
Low
prices will decrease our revenues, but may also reduce the amount of oil, natural gas or natural gas liquids that we can economically
produce. This may result in our having to make substantial downward adjustments to our estimated proved reserves. If this occurs,
or if our estimates of development costs increase, production data factors change or drilling results deteriorate, accounting rules
may require us to write down, as a non–cash charge to earnings, the carrying value of our oil and natural gas properties
for impairments. We are required to perform impairment tests on our assets whenever events or changes in circumstances lead to
a reduction of the estimated useful life or estimated future cash flows that would indicate that the carrying amount may not be
recoverable or whenever management’s plans change with respect to those assets. We may incur impairment charges in the future,
which could have a material adverse effect on our results of operations in the period taken and our ability to borrow funds under
our credit facility, which may adversely affect our ability to service our debt obligations.
Low commodity prices or further declines
would have a material adverse effect on our business.
Our
financial position, results of operations, access to capital and the quantities of oil and natural gas that may be economically
produced would be negatively impacted if oil and natural gas prices decrease further or remain depressed for an extended period
of time. The ways in which such price decreases could have a material negative effect include:
|
·
|
a significant decrease in the number of wells we drill on our acreage, thereby reducing our production
and cash flows;
|
|
·
|
a reduction in cash flow, which would decrease funds available for capital expenditures employed
to replace reserves and maintain or increase production;
|
|
·
|
a decrease in future undiscounted and discounted net cash flows from producing properties, possibly
resulting in impairment expense that may be significant;
|
|
·
|
lower proved reserves, production and cash flow as certain reserves may no longer be economic to
produce;
|
|
·
|
access to sources of capital, such as equity or long–term debt markets could be severely
limited or unavailable; and
|
|
·
|
a reduction in the borrowing base on our credit facility or our Exit Credit Facility.
|
The terms of our indebtedness include
restrictions and financial covenants that may restrict our business and financing activities.
The operating and financial
restrictions and covenants in any future financing agreements may restrict our ability to finance future operations or capital
needs or to engage, expand or pursue our business activities or to pay distributions to our unitholders. See “Item 7. Management’s
Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources.” Our future
ability to comply with these restrictions and covenants is uncertain and will be affected by the levels of cash flow from our operations
and other events or circumstances beyond our control. If market or other economic conditions deteriorate, our ability to comply
with these covenants may be impaired. If we violate any provisions of such financing agreements that are not cured or waived within
the appropriate time periods provided therein, a significant portion of our indebtedness may become immediately due and payable
and our lenders’ commitment to make further loans to us may terminate. We might not have, or be able to obtain, sufficient
funds to make these accelerated payments. In addition, our obligations under our credit facility are secured by substantially all
of our assets, and if we are unable to repay our indebtedness under our credit facility, the lenders could seek to foreclose on
our assets.
The terms and conditions
governing our indebtedness:
|
·
|
require us to dedicate a substantial portion of our cash flow from operations to service our existing
debt, thereby reducing the cash available to finance our operations and other business activities and could limit our flexibility
in planning for or reacting to changes in our business and the industry in which we operate;
|
|
·
|
increase our vulnerability to economic downturns and adverse developments in our business;
|
|
·
|
limit our ability to access the capital markets to raise capital on favorable terms or to obtain
additional financing for working capital, capital expenditures or acquisitions or to refinance existing indebtedness;
|
|
·
|
place restrictions on our ability to obtain additional financing, make investments, lease equipment,
sell assets and engage in business combinations;
|
|
·
|
place us at a competitive disadvantage relative to competitors with lower levels of indebtedness
in relation to their overall size or less restrictive terms governing their indebtedness;
|
|
·
|
make it more difficult for us to satisfy our obligations under our debt and increase the risk that
we may default on our debt obligations; and
|
|
·
|
limit management’s discretion in operating our business.
|
We expect our Exit Credit
Facility to be at least as restrictive as our revolving credit facility.
Our lenders periodically redetermine
the amount we may borrow under our credit facility, which may materially impact our operations.
Our credit facility allowed,
and we expect our Exit Credit Facility will allow, us to borrow in an amount up to the borrowing base, which is primarily based
on the estimated value of our oil and natural gas properties and our commodity derivative contracts as determined semi-annually
by our lenders in their sole discretion. The borrowing base is subject to redetermination on at least a semi-annual basis primarily
based on an engineering report with respect to our estimated natural gas, oil and NGL reserves, which takes into account the prevailing
natural gas, oil and NGL prices at such time, as adjusted for the impact of our commodity derivative contracts. Accordingly,
declining commodity prices may have an impact on the amount we can borrow, which could affect our cash flows and ability to execute
on our business plans. Any reduction in the borrowing base would materially and adversely affect our business and financing activities,
limit our flexibility and management’s discretion in operating our business, and increase the risk that we may default on
our debt obligations. In addition, as hedges expire, the borrowing base is subject to further reduction. Our credit
facility required, and we expect our Exit Credit Facility will require, us to repay any deficiency over a certain period or pledge
additional oil and gas properties to eliminate such deficiency, which we are required to do within 30 days of electing to do so.
If our outstanding borrowings exceed the borrowing base and we are unable to repay the deficiency or pledge additional oil and
gas properties to eliminate such deficiency, our failure to repay any of the installments due related to the borrowing base deficiency
would constitute an event of default under the credit facility and as such, the lenders could declare all outstanding principal
and interest to be due and payable, could freeze our accounts, or foreclose against the assets securing the obligations owed under
the credit facility.
We may not be able to generate enough
cash flow to meet our debt obligations and may be forced to take other actions to satisfy our debt obligations that may not be
successful.
We have historically funded
our operations, including our operating and capital expenditures, our debt service obligations and our acquisitions primarily through
cash generated from operations, amounts available under our credit facility and equity and debt offerings. Our future cash flows
are subject to a number of variables, including oil and natural gas prices, and due to the steep decline in commodity prices, our
ability to obtain funding in the equity or capital markets has been, and will continue to be, constrained, and there can be no
assurances that our liquidity requirements will continue to be satisfied given current commodity prices. If our sources
of liquidity are not sufficient to fund our current or future liquidity needs, including as a result of a decrease in the borrowing
base under our credit facility, we may be required to take other actions, including those actions discussed below.
We expect our earnings
and cash flow to vary significantly from year to year due to the cyclical nature of our industry. As a result, the amount of debt
that we can service in some periods may not be appropriate for us in other periods. Moreover, and subject to certain limitations,
we may be able to incur substantial additional indebtedness in the future. Additionally, our future cash flow may be insufficient
to meet our debt obligations and commitments. Any insufficiency could negatively impact our business. A range of economic, competitive,
business and industry factors will affect our future financial performance, and, as a result, our ability to generate cash flow
from operations and to pay our debt. Many of these factors, such as oil and natural gas prices, economic and financial conditions
in our industry and the global economy or competitive initiatives of our competitors, are beyond our control.
If we do not generate
enough cash flow from operations to satisfy our debt obligations, we may have to undertake alternative strategic actions or financing
plans, such as:
|
·
|
refinancing or restructuring debt;
|
|
·
|
reducing or delaying capital investments;
|
|
·
|
seeking to raise additional capital;
|
|
·
|
liquidating all or a portion of our hedge portfolio;
|
|
·
|
seeking additional partners to develop our assets;
|
|
·
|
reducing our planned capital program;
|
|
·
|
continuing to take, and potentially increasing, our cost saving measures to reduce costs, including
renegotiation contracts with contractors, suppliers and service providers, reducing the number of staff and contractors and deferring
and eliminating discretionary costs; or
|
|
·
|
revising or delaying our other strategic plans.
|
We
continually monitor the capital markets and our capital structure and may make changes to our capital structure from time to time,
with the goal of maintaining financial flexibility, preserving or improving liquidity, strengthening our balance sheet, meeting
our debt service obligations and/or achieving cost efficiency. Our ability to restructure or refinance our indebtedness
will depend on the condition of the capital markets and our financial condition at such time. Any refinancing of our indebtedness
could cause us to incur high transaction costs, may be at higher interest rates and may require us to comply with more onerous
covenants, which could further restrict our business operations. The terms of existing or future debt instruments, including our
credit facility, may restrict us from adopting some of these alternatives. In addition, any failure to make payments of interest
and principal on our outstanding indebtedness on a timely basis would likely result in a reduction of our credit rating, which
could harm our ability to incur additional indebtedness. In the absence of sufficient cash flows and capital resources, we could
face substantial liquidity problems and might be required to dispose of material assets or operations to meet our debt service
and other obligations. Our debt instruments restrict our ability to dispose of assets and our use of the proceeds from such disposition.
We may not be able to consummate those dispositions, and the proceeds of any such disposition may not be adequate to meet any debt
service obligations then due.
We can provide no assurances
that any alternative strategic action or financing plan undertaken will be successful in allowing us to meet our debt obligations
or will result in additional liquidity. Our inability to generate sufficient cash flow to satisfy our debt obligations or to obtain
alternative financing could materially and adversely affect our ability to make payments on our indebtedness and our business,
financial condition, results of operations and cash flows.
Despite our current level of indebtedness,
we may still be able to incur substantially more debt. This could further exacerbate the risks associated with our substantial
indebtedness.
We and our subsidiaries
may be able to incur substantial additional indebtedness in the future, subject to certain limitations, including under our credit
facility or our Exit Credit Facility. If new debt is added to our current debt levels, the related risks that we now face could
increase. Our level of indebtedness could, for instance, prevent us from engaging in transactions that might otherwise be beneficial
to us or from making desirable capital expenditures. This could put us at a competitive disadvantage relative to other less leveraged
competitors that have more cash flow to devote to their operations. In addition, the incurrence of additional indebtedness could
make it more difficult to satisfy our existing financial obligations.
Our variable rate indebtedness subjects us to interest rate
risk, which could cause our debt service obligations to increase significantly.
Borrowings under our credit
facility bear interest at variable rates and expose us to interest rate risk. If interest rates increase and we are unable to effectively
hedge our interest rate risk, our debt service obligations on the variable rate indebtedness would increase even if the amount
borrowed remained the same, and our net income and cash available for servicing our indebtedness would decrease. See “Item
7A. Quantitative and Qualitative Disclosures About Market Risk — Interest Price Risk” included under Part II of
this annual report for further information regarding interest rate sensitivity.
The board of directors of our general
partner has suspended quarterly cash distributions on common units and, in connection with the transactions contemplated by the
plan of reorganization in the Chapter 11 Cases, we will convert into an entity that will not seek to pay a quarterly cash distribution
or any other amount to equity holders.
Under the terms of our
partnership agreement, we distribute all of our available cash to our unitholders after reserves established by our general partner.
The amount of cash available for distribution is reduced by our operating expenses and the amount of any cash reserves established
by our general partner to provide for future operations, future capital expenditures, including acquisitions of additional oil
and natural gas properties, and future debt service requirements. In 2016, the board of directors of our general partner suspended
and has not reinstated distributions on common units primarily due to the current and expected commodity price environment and
market conditions and their impact on our future business as well as restrictions imposed by our debt instruments, including our
credit facility.
In connection with the transactions contemplated
by the plan of reorganization in the Chapter 11 Cases, the Partnership will convert into a corporation or other entity with a primary
business objective other than generating stable cash flows that will allow for quarterly cash distributions to equity holders.
If we were to resume quarterly cash distributions,
the cash available to service our indebtedness or otherwise operate our business may be limited and we may incur additional debt
to enable us to pay such quarterly distributions.
If we were to resume quarterly
cash distributions, we may not accumulate significant amounts of cash. These distributions could significantly reduce the cash
available to us in subsequent periods to make payments on our indebtedness or otherwise operate our business.
In addition, we may be
unable to pay the quarterly cash distribution, if resumed, without borrowing under our credit facility or otherwise. If we use
borrowings to pay distributions to our equity holders for an extended period of time rather than to fund capital expenditures and
other activities relating to our operations, we may be unable to maintain or grow our business. Such a curtailment of our business
activities, combined with our payment of principal and interest on our future indebtedness incurred to pay these distributions,
will reduce our cash available for distribution on our equity and will have a material adverse effect on our business, financial
condition and results of operations.
Our inability to finance the development
of our properties, future oil and natural gas price declines and other factors may result in additional write-downs of our asset
carrying values.
Accounting
rules require us to write down, as a non–cash charge to earnings, the carrying value of our oil and natural gas properties
in the event we have impairments. We are required to perform impairment tests on our assets periodically and whenever events or
changes in circumstances warrant a review of our assets. To the extent such tests indicate a reduction of the estimated useful
life or estimated future cash flows of our assets, the carrying value may not be recoverable and therefore requires a write–down.
During 2017, we recorded impairment charges of approximately $93.6 million. The impairment charges during 2017 included $69.9 million
of proved oil and natural gas properties, of which, $49.5 million related to properties located in the Mid-Continent area and the
Permian Basin, $15.3 million related to properties located in the Monroe Field, $2.2 million related to properties located in Central
Texas and $2.9 million related to properties in East Texas which were sold during April 2017. We also may incur impairment charges
in the future, which could have a material adverse effect on our results of operations in the period incurred. Since December 31,
2017, commodity prices have continued to fluctuate. If commodity prices significantly decrease in future quarters, we could have
additional impairments of our oil and natural gas properties.
As of December 31, 2017, we had no
estimated proved undeveloped reserves (“PUDs”).
As of December 31, 2017,
we did not report any estimated PUDs with respect to any of our properties due to uncertainty regarding our ability to continue
as a going concern and the availability of capital that would be required to develop the PUDs. These undeveloped properties may
not be ultimately developed by us. We previously reported estimated PUDs in our SEC filings, and, if in the future we can satisfy
the reasonable certainty criteria for recording PUDs as prescribed under the SEC requirements, we would likely report estimated
PUDs in future filings.
Identified potential drilling locations,
which are part of our anticipated future drilling plans, are susceptible to uncertainties that could materially alter the occurrence
or timing of their drilling and result in changes to the amount of our proved undeveloped reserves.
As of December 31, 2017,
we had over 3,374 gross identified potential drilling locations, of which approximately 1,360 were located in the Barnett Shale
and approximately 1,100 were located in the Appalachian Basin. This inventory was developed using data gathered from our appraisal
efforts and development drilling, along with offset operators drilling activities. As noted above, we did not include any reserves
attributable to our identified potential drilling as PUDs.
Our ability to drill and
develop these locations depends on a number of uncertainties, including the availability of capital, construction of infrastructure,
inclement weather, regulatory changes and approvals, oil and natural gas prices, costs, drilling results and the availability of
water. Further, our identified potential drilling locations are in various stages of evaluation, ranging from locations that are
ready to drill to locations that will require substantial additional interpretation. We cannot predict in advance of drilling and
testing whether any particular drilling location will yield oil or natural gas in sufficient quantities to recover drilling or
completion costs or to be economically viable. Because of these uncertainties, we do not know if the potential drilling locations
we have identified will ever be drilled or if we will be able to produce oil or natural gas from these or any other potential drilling
locations. As such, our actual drilling activities may materially differ from those presently identified, which could adversely
affect our business.
The
recovery of PUDs requires significant capital expenditures and successful drilling operations. We can provide no assurances that
we will have the ability to finance these future expenditures, whether development will occur as scheduled or that the results
of such development will be as estimated. In addition, delays in the development could force us to reclassify certain of our proved
reserves as unproved reserves. Further, the decision of the operators to develop the PUDs attributable to our properties that EnerVest
does not operate will be subject to the business plans and constraints of the operators of these properties, and be beyond our
control.
We currently own interests
in oil and natural gas properties in which partnerships managed by EnerVest also own an interest and we may acquire properties
in which the EnerVest managed partnerships own an interest in the future. If the EnerVest partnerships elect to sell their interest
in these properties, we would own a minority interest in the properties, and EnerVest may lose the ability to operate the properties.
We
own interests in oil and natural gas properties in which partnerships managed by EnerVest also own interests, and we expect to
make acquisitions of properties jointly with EnerVest partnerships in the future. These properties are primarily in the Barnett
Shale and San Juan Basin, and these properties represent approximately 56% of our estimated net proved reserves as of December
31, 2017. The EnerVest partnerships generally have an investment strategy to typically divest properties in three to five years,
while our strategy is to hold properties for the longer term. We own less than a majority working interest in the properties in
which the EnerVest partnerships also own an interest. If the EnerVest partnerships were to sell their interest in these properties
to an entity not affiliated with EnerVest, our working interest would not be large enough that we could control the selection of
the operator and EnerVest may lose the ability to operate the properties on our behalf. Loss of operations would mean that EnerVest
would no longer control decisions regarding the development and production of those properties, and any replacement operator could
make decisions regarding development or production activities that make it difficult to implement our strategy.
We depend on EnerVest
to provide us services necessary to operate our business. If EnerVest were unable or unwilling to provide these services, it would
result in disruption in our business which could have an adverse effect on our ability to service our debt obligations.
Under
an omnibus agreement, EnerVest provides services to us such as accounting, human resources, office space and other administrative
services, and under an operating agreement, EnerVest operates our properties for us. If EnerVest were to become unable or unwilling
to provide these services, we would need to develop these services internally or arrange for the services from another service
provider. Developing the capabilities internally or by retaining another service provider could have an adverse effect on our business,
and the services, when developed or retained, may not be of the same quality as provided to us by EnerVest.
Our hedging transactions may limit our
gains, result in financial losses or could reduce our net income, which may adversely affect our ability to service our debt obligations
and expose us to counterparty credit risk.
While we currently have
no commodity price derivative hedges in place, we enter into derivative contracts from time to time to manage our exposure to fluctuations
in oil, natural gas and natural gas liquids prices, to achieve more predictable cash flows and to reduce our exposure to fluctuations
in the prices of oil, natural gas and natural gas liquids.
These derivative contracts limit our
potential gains if prices rise above the fixed prices established by the derivative contracts. These derivative contracts may also
expose us to other risks of financial losses, for example, if our production is less than we anticipated at the time we entered
into the derivatives contract, we might be forced to satisfy all or a portion of our hedging obligations without the benefit of
the cash flows from our sale of the underlying physical commodity, resulting in a substantial diminution of our liquidity.
During
periods of falling commodity prices,
our
derivative contracts expose us to risk of financial
loss if the counterparty to the derivative contract fails to perform its obligations under the derivative contract (e.g., our counterparty
fails to perform its obligation to make payments to us under the derivative contract when the market (floating) price under such
derivative contract falls below the specified fixed price). To mitigate counterparty credit risk, we conduct our hedging activities
with financial institutions who are lenders under our credit facility. Disruptions in the financial markets could lead to
sudden changes in a counterparty’s liquidity, which could impair their ability to perform under the terms of the derivative
contract. We are unable to predict sudden changes in a counterparty’s creditworthiness or ability to perform. Even if we
do accurately predict sudden changes, our ability to negate the risk may be limited depending upon market conditions. If the creditworthiness
of our counterparties deteriorates and results in their nonperformance, we could incur a significant loss.
Our ability to use hedging
transactions to protect us from future price declines will be dependent upon oil and natural gas prices at the time we enter into
future hedging transactions and our future levels of hedging, and as a result our future net cash flows may be more sensitive to
commodity price changes. In addition, as substantial doubt exists that we will be able to continue as a going concern, finding
counterparties for commodity hedges has proven difficult.
Our
policy has been to hedge a significant portion of our near–term estimated production. However, our price hedging strategy
and future hedging transactions will be determined at the discretion of our general partner, which is not under an obligation to
hedge a specific portion of our production except that the Exit Credit Facility will require the Partnership to hedge no less than
70% of forecasted proved developed producing production not later than the closing date and for the 18-month period thereafter.
The prices at which we hedge our production in the future will be dependent upon commodity prices at the time we enter into these
transactions, which may be substantially higher or lower than current oil and natural gas prices. Accordingly, our price hedging
strategy may not protect us from significant declines in oil and natural gas prices received for our future production. Conversely,
our hedging strategy may limit our ability to realize cash flows from commodity price increases. Relative to previous years, we
have less volumes hedged at lower prices. This makes our near-term oil, natural gas and natural gas liquids revenues more sensitive
to changes in commodity prices.
Our limited ability to hedge our natural
gas liquids production could adversely impact our net cash provided by operating activities and results of operations.
A liquid, readily available
and commercially viable market for hedging natural gas liquids has not developed in the same way that exists for oil and natural
gas. The current direct natural gas liquids hedging market is constrained in terms of price, volume, duration and number of counterparties,
which limits our ability to hedge our natural gas liquids production effectively or at all. As a result, our net cash provided
by operating activities and results of operations could be adversely impacted by fluctuations in the market prices for natural
gas liquids.
The adoption of derivatives
legislation and regulations related to derivative contracts could have an adverse impact on our ability to hedge risks associated
with our business.
Title
VII of the Dodd-Frank Act establishes federal oversight and regulation of over-the-counter (“OTC”) derivatives and
requires the Commodity Futures Trading Commission (the “CFTC”) and the SEC to enact further regulations affecting derivative
contracts, including the derivative contracts we use to hedge our exposure to price volatility through the OTC market. Although
the CFTC and the SEC have issued final regulations in certain areas, final rules in other areas and the scope of relevant definitions
and/or exemptions still remain to be finalized.
In
one of its rulemaking proceedings still pending under the Dodd-Frank Act, the CFTC issued on December 5, 2016, a re-proposed rule
imposing position limits for certain futures and option contracts in various commodities (including crude oil and natural gas)
and for swaps that are their economic equivalents. Under the proposed rules on position limits, certain types of hedging transactions
are exempt from these limits on the size of positions that may be held, provided that such hedging transactions satisfy the CFTC’s
requirements for certain enumerated “bona fide hedging” transactions or positions. A final rule has not yet been issued.
Similarly, on December 2, 2016, the CFTC has re-issued a proposed rule regarding the capital a swap dealer or major swap participant
is required to set aside with respect to its swap business, but the CFTC has not yet issued a final rule.
The
CFTC issued a final rule on margin requirements for uncleared swap transactions on January 6, 2016, which includes an exemption
from any requirement to post margin to secure uncleared swap transactions entered into by commercial end-users in order to hedge
commercial risks affecting their business. In addition, the CFTC has issued a final rule authorizing an exemption from the otherwise
applicable mandatory obligation to clear certain types of swap transactions through a derivatives clearing organization and to
trade such swaps on a regulated exchange, which exemption applies to swap transactions entered into by commercial end-users in
order to hedge commercial risks affecting their business. The mandatory clearing requirement currently applies only to certain
interest rate swaps and credit default swaps, but the CFTC could act to impose mandatory clearing requirements for other types
of swap transactions. The Dodd-Frank Act also imposes recordkeeping and reporting obligations on counterparties to swap transactions
and other regulatory compliance obligations.
All
of the above regulations could increase the costs to us of entering into financial derivative transactions to hedge or mitigate
our exposure to commodity price volatility and other commercial risks affecting our business. While it is not possible at this
time to predict when the CFTC will issue final rules applicable to position limits or capital requirements, depending on our ability
to satisfy the CFTC’s requirements for a commercial end-user using swaps to hedge or mitigate our commercial risks, these
rules and regulations may require us to comply with position limits and with certain clearing and trade-execution requirements
in connection with our financial derivative activities. When a final rule on capital requirements for swap dealers is issued, the
Dodd-Frank Act may require our current swap dealer counterparties to post additional capital as a result of entering into uncleared
financial derivatives with us, which capital requirements rule could increase the costs to us of future financial derivatives transactions.
The Volcker Rule provisions of the Dodd-Frank Act may also require our current bank counterparties that engage in financial derivative
transactions to spin off some of their derivatives activities to separate entities, which separate entities may not be as creditworthy
as the current bank counterparties. Under such rules, other bank counterparties may cease their current business as hedge providers.
These changes could reduce the liquidity of the financial derivatives markets thereby reducing the ability of entities like us,
as commercial end-users, to have access to financial derivatives to hedge or mitigate our exposure to commodity price volatility.
As
a result, the Dodd-Frank Act and any new regulations issued thereunder could significantly increase the cost of derivative contracts
(including through requirements to post cash collateral), which could adversely affect our capital available for other commercial
operations purposes, materially alter the terms of future swaps relative to the terms of our existing bilaterally negotiated financial
derivative contracts and reduce the availability of derivatives to protect against commercial risks we encounter.
If
we reduce our use of derivative contracts as a result of the new requirements, our results of operations may become more volatile
and cash flows less predictable, which could adversely affect our ability to plan for and fund capital expenditures. Finally, the
legislation was intended, in part, to reduce the volatility of oil, natural gas and natural gas liquids prices, which some legislators
attributed to speculative trading in derivatives and commodity instruments related to oil, natural gas and natural gas liquids.
Our revenues could therefore be adversely affected if a consequence of the legislation and regulations is to lower commodity prices.
Any of these consequences could have a material adverse effect on our consolidated financial condition, results of operations or
cash flows.
Should we fail to comply with all applicable statutes, rules,
regulations and orders administered by the CFTC or FERC, we could be subject to substantial penalties and fines.
Under the Energy Policy
Act of 2005, FERC has been given greater civil penalty authority under the Natural Gas Act (“NGA”), including the ability
to impose penalties of up to $1 million per day for each violation and disgorgement of profits associated with any violation.
While our operations have not been regulated by FERC as a natural gas company under the NGA, FERC has adopted regulations that
may subject certain of our otherwise non-FERC jurisdictional operations to FERC annual reporting and posting requirements.
We also must comply with the anti-market manipulation rules enforced by FERC under the NGA. Under the Commodity Exchange
Act (as amended by the Dodd-Frank Act) and regulations promulgated thereunder by the CFTC, the CFTC has also adopted anti-market
manipulation, fraud and market disruption rules relating to the prices of commodities, futures contracts, options on futures, and
swaps. Additional rules and legislation pertaining to those and other matters may be considered or adopted by Congress, the
FERC, or the CFTC from time to time. Failure to comply with those statutes, regulations, rules and orders could subject us
to civil penalty liability.
The distressed financial conditions of
customers could have an adverse impact on us in the event these customers are unable to pay us for the products or services we
provide.
Some of our customers may
experience, in the future, severe financial problems that have had or may have a significant impact on their creditworthiness.
We cannot provide assurance that one or more of our financially distressed customers will not default on their obligations to us
or that such a default or defaults will not have a material adverse effect on our business, financial position, future results
of operations or future cash flows. Furthermore, the bankruptcy of one or more of our customers, or some other similar proceeding
or liquidity constraint, might make it unlikely that we would be able to collect all or a significant portion of amounts owed by
the distressed entity or entities. In addition, such events might force such customers to reduce or curtail their future use of
our products and services, which could have a material adverse effect on our results of operations and financial condition.
We may be unable
to integrate successfully the operations of our recent or future acquisitions with our operations and we may not realize all the
anticipated benefits of the recent acquisitions or any future acquisition.
Integration of our recent
acquisitions with our business and operations has been a complex, time consuming and costly process. Failure to successfully assimilate
our past or future acquisitions could adversely affect our financial condition and results of operations.
Our acquisitions involve
numerous risks, including:
|
·
|
operating a significantly larger combined organization and adding operations;
|
|
·
|
difficulties in the assimilation of the assets and operations of the acquired business, especially
if the assets acquired are in a new business segment or geographic area;
|
|
·
|
the risk that reserves acquired may not be of the anticipated magnitude or may not be developed
as anticipated;
|
|
·
|
the loss of significant key employees from the acquired business;
|
|
·
|
the diversion of management’s attention from other business concerns;
|
|
·
|
the failure to realize expected profitability or growth;
|
|
·
|
the failure to realize expected synergies and cost savings;
|
|
·
|
coordinating geographically disparate organizations, systems and facilities; and
|
|
·
|
coordinating or consolidating corporate and administrative functions.
|
Further, unexpected costs
and challenges may arise whenever businesses with different operations or management are combined, and we may experience unanticipated
delays in realizing the benefits of an acquisition. If we consummate any future acquisition, our capitalization and results of
operation may change significantly, and you may not have the opportunity to evaluate the economic, financial and other relevant
information that we will consider in evaluating future acquisitions.
Properties that we buy may not produce
as projected and we may be unable to determine reserve potential, identify liabilities associated with the properties or obtain
protection from sellers against such liabilities, which could adversely affect our liquidity and results of operations.
One
of our strategies is to capitalize on opportunistic acquisitions of oil, natural gas and natural gas liquids reserves. Any future
acquisition will require an assessment of recoverable reserves, title, future oil, natural gas and natural gas liquids prices,
operating costs, potential environmental hazards, potential tax and ERISA liabilities, and other liabilities and similar factors.
Ordinarily, our review efforts are focused on the higher valued properties and are inherently incomplete because it generally is
not feasible to review in depth every individual property involved in each acquisition. Even a detailed review of records and properties
may not necessarily reveal existing or potential problems, nor will it permit a buyer to become sufficiently familiar with the
properties to assess fully their deficiencies and potential. Inspections may not always be performed on every well, and potential
problems, such as ground water contamination and other environmental conditions and deficiencies in the mechanical integrity of
equipment are not necessarily observable even when an inspection is undertaken. Any unidentified problems could result in material
liabilities and costs that negatively impact our financial condition and results of operations and our ability to service our debt
obligations.
Additional
potential risks related to acquisitions include, among other things:
|
·
|
incorrect assumptions regarding the future prices of oil, natural gas and natural gas liquids or
the future operating or development costs of properties acquired;
|
|
·
|
incorrect estimates of the reserves attributable to a property we acquire;
|
|
·
|
an inability to integrate successfully the businesses we acquire;
|
|
·
|
the assumption of liabilities;
|
|
·
|
limitations on rights to indemnity from the seller;
|
|
·
|
the diversion of management’s attention from other business concerns; and
|
|
·
|
losses of key employees at the acquired businesses.
|
If
we consummate any future acquisitions, our capitalization and results of operations may change significantly.
Unless we replace the reserves we produce,
our revenues and production will decline, which would adversely affect our cash flows from operations and our ability to service
our debt obligations.
Producing
reservoirs are characterized by declining production rates that vary depending upon reservoir characteristics and other factors.
Our decline rate may change when we drill additional wells, make acquisitions or under other circumstances. Our future cash flows
and income and our ability to resume, maintain and increase distributions to unitholders are highly dependent on our success in
efficiently developing and exploiting our current reserves and economically finding or acquiring additional recoverable reserves.
We may not be able to develop, find or acquire additional reserves to replace our current and future production at acceptable costs,
which would adversely affect our business, financial condition and results of operations. Factors that may hinder our ability to
acquire additional reserves include competition, access to capital, prevailing oil, natural gas and natural gas liquids prices
and the number and attractiveness of properties for sale.
Our estimated reserve quantities and
future production rates are based on many assumptions that may prove to be inaccurate. Any material inaccuracies in these reserve
estimates or the underlying assumptions will materially affect the quantities and present value of our reserves.
Numerous
uncertainties are inherent in estimating quantities of our reserves. Our estimates of our net proved reserve quantities are based
upon reports from Cawley Gillespie and Wright, independent petroleum engineering firms used by us. The process of estimating oil,
natural gas and natural gas liquids reserves is complex, requiring significant decisions and assumptions in the evaluation of available
geological, engineering and economic data for each reservoir, and these reports rely upon various assumptions, including assumptions
regarding future oil, natural gas and natural gas liquids prices, production levels, and operating and development costs. As a
result, estimated quantities of proved reserves and projections of future production rates and the timing of development expenditures
may prove to be inaccurate. Over time, we may make material changes to reserve estimates taking into account the results of actual
drilling and production. Any significant variance in our assumptions and actual results could greatly affect our estimates of reserves,
the economically recoverable quantities of oil, natural gas and natural gas liquids attributable to any particular group of properties,
the classifications of reserves based on risk of recovery, and estimates of the future net cash flows. In addition, our wells are
characterized by low production rates per well. As a result, changes in future production costs assumptions could have a significant
effect on our proved reserve quantities.
The
standardized measure of discounted future net cash flows of our estimated net proved reserves is not necessarily the same as the
current market value of our estimated net proved reserves. We base the discounted future net cash flows from our estimated net
proved reserves on average prices for the 12 months preceding the date of the estimate. Actual prices received for production and
actual costs of such production will be different than these assumptions, perhaps materially.
The timing of both
our production and our incurrence of expenses in connection with the development and production of our properties will affect the
timing of actual future net cash flows from proved reserves, and thus their actual present value. In addition, the 10% discount
factor we use when calculating discounted future net cash flows may not be the most appropriate discount factor based on interest
rates in effect from time to time and risks associated with us or the oil and natural gas industry in general. Any material inaccuracy
in our reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves which
could adversely affect our business, results of operations and financial condition.
Our future acquisition
and development operations will require substantial capital expenditures. We may be unable to obtain needed capital or financing
on satisfactory terms, which could lead to a decline in our production and reserves.
The oil and natural gas
industry is capital intensive. We make and expect to continue to make substantial capital expenditures in our business for the
development, production and acquisition of reserves. As part of our exploration and development operations, we have expanded, and
expect to further expand, the application of horizontal drilling and multi-stage hydraulic fracture stimulation techniques. The
utilization of these techniques requires substantially greater capital expenditures as compared to the drilling of a vertical well,
sometimes more than three times the cost. The incremental capital expenditures are the result of greater measured depths and additional
hydraulic fracture stages in horizontal wellbores.
We
intend to finance our future capital expenditures with cash flows from operations, borrowings under our Exit Credit Facility, as
amended and restated upon approval of the Plan in the Chapter 11 Cases and the issuance of debt and equity securities. The incurrence
of debt will require that a portion of our cash flows from operations be used for the payment of interest and principal on our
debt, thereby reducing our ability to use cash flows to fund working capital, capital expenditures and acquisitions. Our cash flows
from operations and access to capital are subject to a number of variables, including:
|
·
|
the estimated quantities of our reserves;
|
|
·
|
the amount of oil, natural gas and natural gas liquids we produce from existing wells;
|
|
·
|
the prices at which we sell our production; and
|
|
·
|
our ability to acquire, locate and produce new reserves.
|
If our revenues or
the borrowing base under our credit facility decrease as a result of lower commodity prices, operating difficulties, declines in
reserves or for any other reason, we may have limited ability to obtain the capital necessary to sustain our operations at current
levels. Our credit facility may restrict our ability to obtain new financing. If additional capital is needed, we may not be able
to obtain debt or equity financing on terms favorable to us, or at all. If cash generated by operations or available under our
credit facility is not sufficient to meet our capital requirements, the failure to obtain additional financing could result in
a curtailment of our operations relating to development of our prospects, which in turn could lead to a possible decline in our
reserves and production, and could adversely affect our business, results of operation, financial conditions and ability to make
distributions to our unitholders. In addition, we may lose opportunities to acquire oil and natural gas properties and businesses.
We rely on development drilling to assist
in maintaining our levels of production. If our development drilling is unsuccessful, our cash available for servicing our debt
obligations and financial condition will be adversely affected.
Part
of our business strategy has focused on maintaining production levels by drilling development wells. Although we were successful
in development drilling in the past, we cannot assure you that we will continue to maintain production levels through development
drilling, particularly in the current commodity price environment. Our drilling involves numerous risks, including the risk that
we will not encounter commercially productive oil or natural gas reservoirs. We must incur significant expenditures to drill and
complete wells. Additionally, seismic technology does not allow us to know conclusively, prior to drilling a well, that oil or
natural gas is present or economically producible. The costs of drilling and completing wells are often uncertain, and it is possible
that we will make substantial expenditures on development drilling and not discover reserves in commercially viable quantities.
These expenditures will reduce cash available for servicing our debt obligations.
Our
drilling operations may be curtailed, delayed or cancelled as a result of a variety of factors, including:
|
·
|
unexpected drilling conditions;
|
|
·
|
facility or equipment failure or accidents;
|
|
·
|
shortages or delays in the availability of drilling rigs and equipment;
|
|
·
|
adverse weather conditions;
|
|
·
|
compliance with environmental and governmental requirements;
|
|
·
|
unusual or unexpected geological formations;
|
|
·
|
fires, blowouts, craterings and explosions; and
|
|
·
|
uncontrollable flows of oil or natural gas or well fluids.
|
Our business strategy involves the
use of the latest available horizontal drilling, completion and production technology, which involve risks and uncertainties in
their application.
Our
operations involve the use of the latest horizontal drilling, completion and production technologies, as developed by us and our
service providers, in an effort to improve efficiencies in recovery of hydrocarbons. Use of these new technologies may not prove
successful and could result in significant cost overruns or delays or reduction in production, and in extreme cases, the abandonment
of a well. The difficulties we face drilling horizontal wells include:
|
·
|
landing our wellbore in the desired drilling zone;
|
|
·
|
staying in the desired drilling zone while drilling horizontally through the formation;
|
|
·
|
running our production casing the entire length of the wellbore; and
|
|
·
|
running tools and other equipment consistently through the horizontal wellbore.
|
Difficulties
that we face while completing our wells include the following:
|
·
|
designing and executing the optimum fracture stimulation program for a specific target zone;
|
|
·
|
running tools the entire length of the wellbore during completion operations; and
|
|
·
|
cleaning out the wellbore after completion of the fracture stimulation.
|
In
addition, certain of the new techniques we are adopting may cause irregularities or interruptions in production due to offset wells
being shut in and the time required to drill and complete multiple wells before any such wells begin producing. Furthermore, the
application of technology developed in drilling, completing and producing in one productive formation may not be successful in
other prospective formations with little or no horizontal drilling history. If our use of the latest technologies does not prove
successful, our drilling and production results may be less than anticipated or we may experience cost overruns, delays in obtaining
production or abandonment of a well. As a result, the return on our investment will be adversely affected, we could incur material
write-downs of unevaluated properties or undeveloped reserves and the value of our undeveloped acreage and reserves could decline
in the future.
We could experience periods of higher
costs if oil and natural gas prices rise or as drilling activity otherwise increases in our area of operations. Higher costs could
reduce our profitability, cash flow and ability to pursue our drilling program as planned
.
Historically,
our capital and operating costs typically rise during periods of sustained increasing oil, natural gas and NGL prices. These cost
increases result from a variety of factors beyond our control as drilling activity increases, such as increases in the cost of
electricity, tubular goods, water, sand and other disposable materials used in fracture stimulation and other raw materials that
we and our vendors rely upon; and the cost of services and labor especially those required in horizontal drilling and completion.
Since late 2014, oil and natural gas prices declined substantially resulting in decreased levels of drilling activity in the US
oil and natural gas industry, including in our area of operations. This led to significantly lower costs of some drilling and completion
equipment, services, materials and supplies. As commodity prices rise or stabilize or drilling activity otherwise increases in
our area of operations, these lower cost levels may not be sustainable over long periods. As a result, such costs may rise thereby
negatively impacting our profitability, cash flow and causing us to possibly reconfigure or reduce our drilling program.
We may be unable
to compete effectively with larger companies, which may adversely affect our ability to generate sufficient revenue and our ability
to service our debt obligations.
The
oil and natural gas industry is intensely competitive, and we compete with other companies that have greater resources than us.
Our ability to acquire additional properties and to discover reserves in the future will be dependent upon our ability to evaluate
and select suitable properties and to consummate transactions in a highly competitive environment. Many of our larger competitors
not only drill for and produce oil, natural gas and natural gas liquids, but also carry on refining operations and market petroleum
and other products on a regional, national or worldwide basis. These companies may be able to pay more for oil and natural gas
properties and evaluate, bid for and purchase a greater number of properties than our financial or human resources permit. In addition,
these companies may have a greater ability to continue drilling activities during periods of low prices, to contract for drilling
equipment, to secure trained personnel, and to absorb the burden of present and future federal, state, local and other laws and
regulations. The oil and natural gas industry has periodically experienced shortages of drilling rigs, equipment, pipe and personnel,
which has delayed development drilling and other exploitation activities and has caused significant price increases. Competition
has been strong in hiring experienced personnel, particularly in the accounting and financial reporting, tax and land departments.
In addition, competition is strong for attractive oil and natural gas producing properties, oil and natural gas companies, and
undeveloped leases and drilling rights. We may be often outbid by competitors in our attempts to acquire properties or companies.
Our inability to compete effectively with larger companies could have a material adverse impact on our business activities, financial
condition and results of operations.
Our business is subject to operational
risks that will not be fully insured, which, if they were to occur, could adversely affect our financial condition or results of
operations and, as a result, our ability to service our debt obligations.
Our
business activities are subject to operational risks, including:
|
·
|
damages to equipment caused by adverse weather conditions, including hurricanes and flooding;
|
|
·
|
facility or equipment malfunctions;
|
|
·
|
pipeline ruptures or spills;
|
|
·
|
fires, blowouts, craterings and explosions;
|
|
·
|
uncontrollable flows of oil or natural gas or well fluids; and
|
|
·
|
surface spillage and surface or ground water contamination from petroleum constituents or hydraulic
fracturing chemical additives.
|
In
addition, a portion of our natural gas production is processed to extract natural gas liquids at processing plants that are owned
by others. If these plants were to cease operations for any reason, we would need to arrange for alternative transportation and
processing facilities. These alternative facilities may not be available, which could cause us to shut–in our natural gas
production, or the alternative facilities could be more expensive than the facilities we currently use.
Any of these events could
adversely affect our ability to conduct operations or cause substantial losses, including personal injury or loss of life, damage
to or destruction of property, natural resources and equipment, pollution or other environmental contamination, loss of wells,
regulatory penalties, suspension of operations, and attorneys’ fees and other expenses incurred in the prosecution or defense
of litigation.
As
is customary in the industry, we maintain insurance against some but not all of these risks. Additionally, we may elect not to
obtain insurance if we believe that the cost of available insurance is excessive relative to the perceived risks presented. Losses
could therefore occur for uninsurable or uninsured risks or in amounts in excess of existing insurance coverage. The occurrence
of an event that is not fully covered by insurance could have a material adverse impact on our business activities, financial condition,
results of operations and ability to pay distributions to our unitholders and service our debt obligations.
Our business depends on gathering and
compression facilities owned by third parties and transportation facilities owned by third-party transporters and we rely on third
parties to gather and deliver our oil, natural gas and NGLs to certain designated interconnects with third-party transporters.
Any limitation in the availability of those facilities or delay in providing interconnections to newly drilled wells would interfere
with our ability to market the oil, natural gas and natural gas liquids we produce and could reduce our revenues.
The marketability of our
oil, natural gas and natural gas liquids production depends in part on the availability, proximity and capacity of pipeline systems
owned by third parties in the respective operating areas. The amount of oil and natural gas that can be produced and sold is subject
to curtailment in certain circumstances, such as pipeline interruptions due to scheduled and unscheduled maintenance, excessive
pressure, physical damage to the gathering, compression or transportation system, or lack of contracted capacity on such systems.
The curtailments arising from these and similar circumstances may last from a few days to several months. In many cases, we are
provided only with limited, if any, notice as to when these circumstances will arise and their duration. In addition, some of our
wells are drilled in locations that are not serviced by gathering and transportation pipelines, or the gathering and transportation
pipelines in the area may not have sufficient capacity to transport the additional production. As a result, we may not be able
to sell the oil and natural gas production from these wells until the necessary gathering and transportation systems are constructed.
Any significant curtailment in gathering system or pipeline capacity, or significant delay in the construction of necessary gathering,
compression and transportation facilities, could reduce our revenues.
The third parties on whom we rely for
gathering, compression and transportation services are subject to complex federal, state and other laws and regulations that could
adversely affect the cost, manner or feasibility of doing business.
The operations of the third
parties on whom we rely for gathering, compression and transportation services are subject to complex and stringent laws and regulations
that require obtaining and maintaining numerous permits, approvals and certifications from various federal, state and local government
authorities. These third parties may incur substantial costs in order to comply with existing laws and regulations. If existing
laws and regulations governing such third-party services are revised or reinterpreted, or if new laws and regulations become applicable
to their operations, these changes may affect the costs that we pay for such services. Similarly, a failure to comply with such
laws and regulations by the third parties on whom we rely could have a material adverse effect on our business, financial condition
and results of operations.
Our financial condition
and results of operations may be materially adversely affected if we incur costs and liabilities due to a failure to comply with
environmental regulations or a release of hazardous substances into the environment.
We
may incur significant costs and liabilities as a result of environmental requirements applicable to the operation of our wells,
gathering systems and other facilities. These costs and liabilities could arise under a wide range of federal, state and local
environmental laws and regulations, including, for example:
|
·
|
the CAA and comparable state laws and regulations that
impose obligations related to emissions of air pollutants;
|
|
·
|
the Clean Water Act and comparable state laws and regulations
that impose obligations related to discharges of pollutants into regulated bodies of water;
|
|
·
|
the Resource Conservation and Recovery Act, or RCRA, and comparable state laws that impose requirements
for the handling and disposal of waste from our facilities;
|
|
·
|
the CERCLA and comparable state laws that regulate the cleanup of hazardous substances that may
have been released at properties currently or previously owned or operated by us or at locations to which we have sent waste for
disposal;
|
|
·
|
the Safe Drinking Water Act and state or local laws and regulations related to hydraulic fracturing;
|
|
·
|
the OPA which subjects responsible parties to liability for removal costs and damages arising from
an oil spill in waters of the US;
|
|
·
|
EPA community right to know regulations under the Title III of CERCLA and similar state statutes
require that we organize and/or disclose information about hazardous materials used or produced in our operations; and
|
|
·
|
the Endangered Species Act, which may restrict or prohibit operations in protected area.
|
Failure
to comply with these laws and regulations may trigger a variety of administrative, civil and criminal enforcement measures, including
the assessment of monetary penalties, the imposition of remedial requirements, and the issuance of orders enjoining future operations.
Certain environmental statutes, including the RCRA, CERCLA, OPA and analogous state laws and regulations, impose strict joint and
several liability for costs required to clean up and restore sites where hazardous substances or other waste products have been
disposed of or otherwise released. More stringent laws and regulations, including any related to climate change and greenhouse
gases, may be adopted in the future. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims
for personal injury and property damage allegedly caused by the release of hazardous substances or other waste products into the
environment.
We are subject to complex federal, state,
local and other laws and regulations that could adversely affect the cost, manner or feasibility of conducting our operations.
Our
operations are subject to complex and stringent laws and regulations, which are continuously being reviewed for amendment and/or
expansion. In order to conduct our operations in compliance with these laws and regulations, we must obtain and maintain numerous
permits, approvals and certificates from various federal, state and local governmental authorities. Failure or delay in obtaining
and maintaining regulatory approvals or drilling permits could have a material adverse effect on our ability to develop our properties,
and receipt of drilling permits with onerous conditions could increase our compliance costs. In addition, regulations regarding
resource conservation practices and the protection of correlative rights affect our operations by limiting the quantity of oil,
natural gas and natural gas liquids we may produce and sell.
We
are subject to, and may incur liabilities under, federal, state and local laws and regulations as interpreted and enforced by governmental
authorities possessing jurisdiction over various aspects of the exploration and production of oil, natural gas and natural gas
liquids.
For
example, several states have enacted Surface Damage Acts (“SDAs”) that are designed to compensate surface owners/users
for damages caused by mineral owners. Most SDAs contain entry notification and negotiation requirements to facilitate contact between
operators and surface owners/users. Most also contain binding requirements for payments by the operator to surface owners/users
in connection with exploration and operating activities. Costs and delays associated with SDAs could impair operational effectiveness
and increase development costs. In addition, many states, including Texas, impose a production, ad valorem or severance tax with
respect to the production and sale of oil and gas within their jurisdiction.
Other
activities subject to regulation are:
|
●
|
the location and spacing of wells;
|
|
●
|
the method of drilling and completing and operating wells;
|
|
●
|
the rate and method of production;
|
|
●
|
the surface use and restoration of properties upon which
wells are drilled and other exploration activities;
|
|
●
|
notice to surface owners and other third parties;
|
|
●
|
the venting or flaring of natural gas;
|
|
●
|
the plugging and abandoning of wells;
|
|
●
|
the discharge of contaminants into water and the emission
of contaminants into air;
|
|
●
|
the disposal of fluids used or other wastes obtained in
connection with operations;
|
|
●
|
the marketing, transportation and reporting of production;
and
|
|
●
|
the valuation and payment of royalties.
|
While
the cost of compliance with these laws has not been material to our operations in the past, the possibility exists that new laws,
regulations or enforcement policies could be more stringent and significantly increase our compliance costs. If we are not able
to recover the resulting costs through insurance or increased revenues, our ability to service our debt obligations could be adversely
affected.
Climate change legislation or regulations
restricting emissions of GHGs could result in increased operating costs and reduced demand for the oil, natural gas and natural
gas liquids we produce.
The EPA requires the reporting
of GHG emissions from specified large GHG emission sources, including onshore and offshore oil and natural gas production facilities
and onshore oil and natural gas processing, transmission, storage and distribution facilities, which may include facilities we
operate. We began reporting emissions in 2012 for emissions occurring in 2011 and continue to report as required on an annual basis.
More
stringent laws and regulations relating to climate change and GHGs may be adopted and could cause us to incur material expenses
to comply.
Both houses of Congress
previously considered legislation to reduce emissions of GHGs and many states have adopted or considered measures to reduce GHG
emission reduction levels, often involving the planned development of GHG emission inventories and/or cap and trade programs. Most
of these cap and trade programs work by requiring major sources of emissions or major producers of fuels to acquire and surrender
emission allowances. The adoption and implementation of any legislation or regulatory programs imposing reporting obligations on,
or limiting emissions of GHGs from, our equipment and operations could require us to incur costs to reduce emissions of GHGs associated
with our operations or could adversely affect demand for the oil, natural gas and natural gas liquids that we produce.
In the absence of comprehensive
federal legislation on GHG emission control, the EPA attempted to require the permitting of GHG emissions; although the Supreme
Court struck down the permitting requirements, it upheld EPA’s authority to control GHG emissions when a permit is required
due to emissions of other pollutants. The EPA has adopted rules to regulate methane emissions, including from new and modified
oil and gas production sources and natural gas processing and transmission sources, and has announced its intention to regulate
methane emissions from existing oil and gas sources, although it remains unclear the status of future rulemaking under the new
administration. This rule is also the subject of pending appeals. In late 2016, BLM adopted rules governing flaring and venting
of methane from existing wells and other facilities on public and tribal lands, which could require additional equipment and emissions
controls as well as inspection requirements. These rules have been challenged in court and remain in litigation. Additionally,
the US House of Representatives has passed a resolution under the Congressional Review Act disapproving the rules; Senate action
remains pending. As noted elsewhere in this report, both the EPA and BLM have proposed regulatory changes that would reduce the
burdens of the above-described GHG emission regulations on new and existing sources, but it is too recent an event to know for
certain the impact of these proposed rule changes.
Significant physical effects of climatic
change have the potential to damage our facilities, disrupt our production activities and cause us to incur significant costs in
preparing for or responding to those effects.
Climate change could have
an effect on the severity of weather (including hurricanes and floods), sea levels, the arability of farmland, and water availability
and quality. If such effects were to occur, our exploration and production operations have the potential to be adversely affected.
Potential adverse effects could include damages to our facilities from powerful winds or rising waters in low lying areas, disruption
of our production activities either because of climate related damages to our facilities in our costs of operation potentially
arising from such climatic effects, less efficient or non–routine operating practices necessitated by climate effects or
increased costs for insurance coverages in the aftermath of such effects. Significant physical effects of climate change could
also have an indirect effect on our financing and operations by disrupting the transportation or process related services provided
by midstream companies, service companies or suppliers with whom we have a business relationship. We may not be able to recover
through insurance some or any of the damages, losses or costs that may result from potential physical effects of climate change.
Federal legislation and state and local
legislative and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating
restrictions or delays.
Hydraulic fracturing is
an important and common practice that is used to stimulate production of hydrocarbons, particularly natural gas, from dense rock
formations. The hydraulic fracturing process involves the injection of water, sand and chemicals under pressure into the formation
to fracture the surrounding rock and stimulate production. We routinely use hydraulic fracturing techniques in most of our drilling
and completion programs. Hydraulic fracturing is typically regulated by state oil and natural gas commissions but the EPA has asserted
federal regulatory authority pursuant to the Safe Drinking Water Act over certain hydraulic fracturing activities involving the
use of diesel. In addition, in past sessions, legislation was introduced before Congress to provide for federal regulation of hydraulic
fracturing under the Safe Drinking Water Act and to require disclosure of the chemicals used in the fracturing process. At the
state level, some states, including Pennsylvania, Louisiana and Texas, where we operate, have adopted, and other states are considering
adopting, requirements that could impose more stringent permitting, public disclosure or well construction requirements on hydraulic
fracturing activities including such things as restrictions on drilling and completion operations, including requirements regarding
casing and cementing of wells; testing of nearby water wells; restrictions on access to, and usage of, water; and restrictions
on the type of chemical additives that may be used in hydraulic fracturing operations. Additionally, some states, localities and
local regulatory districts have adopted or have considered adopting regulations to limit, and in some cases impose a moratorium
on, hydraulic fracturing. In the event that new or more stringent federal, state, or local legal restrictions relating to the hydraulic
fracturing process are adopted in areas where we operate, we could incur potentially significant added costs to comply with such
requirements, experience delays or curtailment in the pursuit of exploration, development, or production activities, and perhaps
even be precluded from drilling wells.
In addition, certain governmental
reviews are either underway or being proposed that focus on environmental aspects of hydraulic fracturing practices.
The
EPA has issued final rules outlining its position on the federal jurisdictional reach over waters of the United States. This interpretation
by the EPA may constitute an expansion of federal jurisdiction over waters of the United States. Litigation surrounding this rule
is ongoing
. Further, the EPA has published guidance on hydraulic fracturing using diesel and also published an effluent
limit guideline final rule prohibiting the discharge of wastewater from onshore unconventional oil and natural gas extraction facilities
to publicly owned wastewater treatment plants. This ongoing scrutiny of hydraulic fracturing, depending on the degree of pursuit
and any meaningful results obtained, could result in further regulation of hydraulic fracturing under the federal Safe Drinking
Water Act or other regulatory programs.
We are now subject to regulation under
NSPS and NESHAPS programs, which could result in increased operating costs.
On April 17, 2012, the
EPA issued final rules that subject oil and natural gas production, processing, transmission and storage operations to regulation
under the NSPS and the NESHAP programs. The EPA rules include NSPS standards for completions of hydraulically fractured natural
gas wells. Beginning January 1, 2015, operators must capture the natural gas and make it available for use or sale, which can be
done through the use of green completions. The standards are applicable to newly fractured wells and also existing wells that are
refractured. Further, the finalized regulations also establish specific new requirements, effective in 2012, for emissions from
compressors, controllers, dehydrators, storage tanks, natural gas processing plants and certain other equipment. These rules may
require changes to our operations, including the installation of new equipment to control emissions. We continuously evaluate the
effect of new rules on our business.
Changes in interest rates could adversely
impact our ability to issue additional debt.
Interest
rates on future credit facilities and debt offerings could be higher than current levels, causing our financing costs to increase
accordingly. As with other yield oriented securities, our unit price is impacted by the level of our cash distributions and implied
distribution yield. The distribution yield is often used by investors to compare and rank related yield oriented securities for
investment decision-making purposes. Therefore, changes in interest rates, either positive or negative, may affect the yield requirements
of investors who invest in our units, and a rising interest rate environment could have an adverse impact on our unit price and
our ability to issue additional equity to make acquisitions, incur debt or for other purposes.
We may encounter obstacles to marketing
our oil, natural gas and natural gas liquids, which could adversely impact our revenues.
The
marketability of our production will depend in part upon the availability and capacity of natural gas gathering systems, pipelines
and other transportation facilities owned by third parties. Transportation space on the gathering systems and pipelines we utilize
is occasionally limited or unavailable due to repairs or improvements to facilities or due to space being utilized by other companies
that have priority transportation agreements. Our access to transportation options can also be affected by US federal and
state regulation of oil and natural gas production and transportation, general economic conditions and changes in supply and demand.
The availability of markets is beyond our control. If market factors dramatically change, the impact on our revenues could be substantial
and could adversely affect our ability to produce and market oil, natural gas and natural gas liquids, the value of our units and
our ability to pay distributions on our units and service our debt obligations.
We may experience a temporary decline
in revenues and production if we lose one of our significant customers.
To the extent any significant
customer reduces the volume of its oil or natural gas purchases from us, we could experience a temporary interruption in sales
of, or a lower price for, our production and our revenues which could adversely affect our ability to service our debt obligations.
We may incur
substantial debt in the future to enable us to maintain or increase our production levels and to otherwise pursue our business
plan.
Our
business requires a significant amount of capital expenditures to maintain and grow production levels. Commodity prices have historically
been volatile, and we cannot predict the prices we will receive in the future. If prices were to decline for an extended period
of time, if the costs of our acquisition and development operations were to increase substantially, or if other events were to
occur which reduced our revenues or increased our costs, we may be required to borrow significant amounts in the future to enable
us to finance the expenditures necessary to replace the reserves we produce.
Oil and gas exploration and production
activities are complex and involves risks that could lead to legal proceedings resulting in the incurrence of substantial liabilities.
Like many oil and gas companies,
we are from time to time involved in various legal and other proceedings in the ordinary course our business, such as title, royalty
or contractual disputes, regulatory compliance matters and personal injury or property damage matters, in the ordinary course of
our business. Such legal proceedings are inherently uncertain and their results cannot be predicted. Regardless of the outcome,
such proceedings could have an adverse impact on us because of legal costs, diversion of management and other personnel and other
factors. In addition, it is possible that a resolution of one or more such proceedings could result in liability, penalties or
sanctions, as well as judgments, consent decrees or orders requiring a change in our business practices, which could materially
and adversely affect our business, operating results and financial condition. Accruals for such liabilities, penalties or sanctions
may be insufficient, and judgments and estimates to determine accruals or range of losses related to legal and other proceedings
could change from one period to the next, and such changes could be material.
Loss of our information and computer
systems could adversely affect our business.
We
are heavily dependent on our information systems and computer based programs, including our well operations information, seismic
data, electronic data processing and accounting data. If any of such programs or systems were to fail or create erroneous information
in our hardware or software network infrastructure, possible consequences include our loss of communication links, inability to
find, produce, process and sell oil and natural gas and inability to automatically process commercial transactions or engage in
similar automated or computerized business activities. Any such consequence could have a material adverse effect on our business.
A cyber incident could result in information
theft, data corruption, operational disruption and/or financial loss.
The oil and gas industry
has become increasingly dependent on digital technologies to conduct day-to-day operations including certain exploration, development
and production activities. For example, software programs are used to interpret seismic data, manage drilling rigs, production
equipment and gathering and transportation systems, conduct reservoir modeling and reserves estimation, and for compliance reporting.
The use of mobile communication devices has increased rapidly. Industrial control systems such as SCADA (supervisory control and
data acquisition) now control large scale processes that can include multiple sites and long distances, such as power generation
and transmission, communications and oil and gas pipelines.
We depend on digital technology,
including information systems and related infrastructure as well as cloud applications and services, to process and record financial
and operating data, communicate with our employees, vendors and service providers, analyze seismic and drilling information, estimate
quantities of oil and gas reserves as well as other activities related to our business. Our vendors, service providers, purchasers
of our production, and financial institutions, are also dependent on digital technology. The technologies needed to conduct oil
and gas exploration and development activities and global competition for oil and gas resources make certain information the target
of theft or misappropriation.
As dependence on digital
technologies has increased, cyber incidents, including deliberate attacks or unintentional events, also have increased. A cyber
attack could include gaining unauthorized access to digital systems for purposes of misappropriating assets or sensitive information,
corrupting data, or causing operational disruption, or result in denial-of-service on websites. SCADA-based systems are potentially
vulnerable to targeted cyber attacks due to their critical role in operations.
Our technologies, systems,
networks, and those of our vendors and service providers may become the target of cyber attacks or information security breaches
that could result in the unauthorized release, gathering, monitoring, misuse, loss or destruction of proprietary and other information,
or other disruption of our business operations. In addition, certain cyber incidents, such as surveillance, may remain undetected
for an extended period.
A cyber incident involving
our information systems and related infrastructure, or that of our vendors and service providers, could disrupt our business plans
and negatively impact our operations in the following ways, among others:
|
●
|
unauthorized access to seismic data, reserves information or other sensitive or proprietary information
could have a negative impact on our ability to compete for oil and gas resources;
|
|
●
|
data corruption, communication interruption, or other operational disruption during drilling activities
could result in failure to reach the intended target or a drilling incident;
|
|
●
|
data corruption or operational disruption of production infrastructure could result in loss of
production, or accidental discharge;
|
|
●
|
a cyber attack on a vendor or service provider could result in supply chain disruptions which could
delay or halt a development project, effectively delaying the start of cash flows from the project;
|
|
●
|
a cyber attack on a third party gathering or pipeline service provider could prevent us from marketing
our production, resulting in a loss of revenues;
|
|
●
|
a cyber attack involving commodities exchanges or financial institutions could slow or halt commodities
trading, thus preventing us from marketing our production or engaging in hedging activities, resulting in a loss of revenues;
|
|
●
|
a cyber attack on a communications network or power grid could cause operational disruption resulting
in loss of revenues;
|
|
●
|
a deliberate corruption of our financial or operational data could result in events of non-compliance
which could lead to regulatory fines or penalties; and
|
|
●
|
business interruptions could result in expensive remediation efforts, distraction of management,
damage to our reputation, or a negative impact on the price of our common stock.
|
Our implementation of
various controls and processes to monitor and mitigate security threats and to increase security for our information, facilities
and infrastructure is costly and labor intensive. Moreover, there can be no assurance that such measures will be sufficient to
prevent security breaches from occurring. As cyber threats continue to evolve, we may be required to expend significant additional
resources to continue to modify or enhance our protective measures or to investigate and remediate any information security vulnerabilities.
Risks Inherent in an Investment in Us
EnerVest controls our general partner,
which has sole responsibility for conducting our business and managing our operations. EnerVest, EV Investors, L.P. (“EV
Investors”) and EnCap Investments, L.P. (“EnCap”), which are limited partners of our general partner, have conflicts
of interest, which may permit them to favor their own interests to your detriment.
EnerVest
owns and controls our general partner, and EnCap owns a 23.75% limited partnership interest in our general partner. Conflicts of
interest may arise between EnerVest, EnCap and their respective affiliates, including our general partner, on the one hand, and
us, our unitholders and the holders of our debt obligations, on the other hand. In resolving these conflicts of interest, our general
partner may favor its own interests and the interests of its owners over the interests of our unitholders and the holders of our
debt obligations. These conflicts include, among others, the following situations:
|
·
|
we have acquired oil and natural gas properties from partnerships formed by EnerVest and partnerships
and companies in which EnerVest and EnCap have an interest, and we may do so in the future;
|
|
·
|
neither our partnership agreement nor any other agreement requires EnerVest or EnCap to pursue
a business strategy that favors us or to refer any business opportunity to us;
|
|
·
|
our general partner is allowed to take into account the interests of parties other than us, such
as EnerVest and EnCap, in resolving conflicts of interest;
|
|
·
|
our general partner determines the amount and timing of our drilling program and related capital
expenditures, asset purchases and sales, borrowings, issuance of additional partnership securities and reserves, each of which
can affect the amount of cash that is distributed to unitholders and used to service our debt obligations;
|
|
·
|
our partnership agreement does not restrict our general partner from causing us to pay it or its
affiliates for any services rendered to us or entering into additional contractual arrangements with any of these entities on our
behalf;
|
|
·
|
our general partner controls the enforcement of obligations owed to us by our general partner and
its affiliates; and
|
|
·
|
our general partner decides whether to retain separate counsel, accountants or others to perform
services for us.
|
Many of the directors and officers who
have responsibility for our management have significant duties with, and will spend significant time serving, entities that compete
with us in seeking out acquisitions and business opportunities and, accordingly, may have conflicts of interest in allocating time
or pursuing business opportunities.
In
order to maintain and increase our levels of production, we will need to acquire oil and natural gas properties. Several of the
officers and directors of EV Management, the general partner of our general partner, who have responsibilities for managing our
operations and activities hold similar positions with other entities that are in the business of identifying and acquiring oil
and natural gas properties. For example, Mr. John B. Walker is Executive Chairman of EV Management and Chief Executive Officer
of EnerVest, which is in the business of acquiring oil and natural gas properties and managing the EnerVest partnerships that are
in that business. We cannot assure you that these conflicts will be resolved in our favor. Mr. Gary R. Petersen, a director
of EV Management, is also a senior managing director of EnCap, which is in the business of investing in oil and natural gas companies
with independent management which in turn is in the business of acquiring oil and natural gas properties. Mr. Petersen is
also a director of several oil and natural gas producing entities that are in the business of acquiring oil and natural gas properties.
The existing positions of these directors and officers may give rise to fiduciary obligations that are in conflict with fiduciary
obligations owed to us. The EV Management officers and directors may become aware of business opportunities that may be appropriate
for presentation to us as well as the other entities with which they are or may be affiliated. Due to these existing and potential
future affiliations with these and other entities, they may have fiduciary obligations to present potential business opportunities
to those entities prior to presenting them to us, which could cause additional conflicts of interest. They may also decide that
the opportunities are more appropriate for other entities which they serve and elect not to present them to us.
Neither EnerVest
nor EnCap is limited in its ability to compete with us for acquisition or drilling opportunities. This could cause conflicts of
interest and limit our ability to acquire additional assets or businesses which in turn could adversely affect our ability to replace
reserves, results of operations and cash available for servicing our debt obligations.
Neither
our partnership agreement nor the omnibus agreement between EnerVest and us prohibits EnerVest, EnCap and their affiliates from
owning assets or engaging in businesses that compete directly or indirectly with us. For instance, EnerVest, EnCap and their respective
affiliates may acquire, develop or dispose of additional oil or natural gas properties or other assets in the future, without any
obligation to offer us the opportunity to purchase or develop any of those assets. Each of these entities is a large, established
participant in the energy business, and each has significantly greater resources and experience than we have, which factors may
make it more difficult for us to compete with these entities with respect to commercial activities as well as for acquisition candidates.
As a result, competition from these entities could adversely impact our results of operations and accordingly cash available for
servicing our debt obligations.
Cost reimbursements due to our general
partner and its affiliates for services provided may be substantial and will reduce our cash available for servicing our debt obligations.
Pursuant
to the omnibus agreement between EnerVest and us, EnerVest will receive reimbursement for the provision of various general and
administrative services for our benefit. In addition, we entered into contract operating agreements with a subsidiary of EnerVest
pursuant to which the subsidiary will be the contract operator of all of the wells for which we have the right to appoint an operator.
Payments for these services will be substantial. In addition, under Delaware partnership law, our general partner has unlimited
liability for our obligations, such as our debts and environmental liabilities, except for our contractual obligations that are
expressly made without recourse to our general partner. To the extent our general partner incurs obligations on our behalf, we
are obligated to reimburse or indemnify it. If we are unable or unwilling to reimburse or indemnify our general partner, our general
partner may take actions to cause us to make payments of these obligations and liabilities. Any such payments could reduce the
amount of cash otherwise available for distribution to our unitholders.
Our partnership agreement limits our
general partner’s fiduciary duties to holders of our common units.
Although
our general partner has a fiduciary duty to manage us in a manner beneficial to us and our unitholders, the directors and officers
of EV Management, the general partner of our general partner, have a fiduciary duty to manage our general partner in a manner beneficial
to its owners. Our partnership agreement contains provisions that reduce the standards to which our general partner and its affiliates
would otherwise be held by state fiduciary duty laws. For example, our partnership agreement permits our general partner and its
affiliates to make a number of decisions either in their individual capacities, as opposed to in its capacity as our general partner,
or otherwise free of fiduciary duties to us and our unitholders. This entitles our general partner and its affiliates to consider
only the interests and factors that they desire, and they have no duty or obligation to give any consideration to any interest
of, or factors affecting, us, our affiliates or any limited partner. Examples include:
|
·
|
whether or not to exercise its right to reset the target distribution levels of its incentive distribution
rights at higher levels and receive, in connection with this reset, a number of Class B units that are convertible at any
time following the first anniversary of the issuance of these Class B units into common units;
|
|
·
|
whether or not to exercise its limited call right;
|
|
·
|
how to exercise its voting rights with respect to the units it owns;
|
|
·
|
whether or not to exercise its registration rights; and
|
|
·
|
whether or not to consent to any merger or consolidation of the partnership or amendment to the
partnership agreement.
|
Our partnership agreement restricts the
remedies available to holders of our common units for actions taken by our general partner that might otherwise constitute breaches
of fiduciary duty.
Our
partnership agreement contains provisions restricting the remedies available to unitholders for actions taken by our general partner
or its affiliates that might otherwise constitute breaches of fiduciary duty. For example, our partnership agreement:
|
·
|
provides that our general partner will not have any liability to us or our unitholders for decisions
made in its capacity as a general partner so long as it acted in good faith, meaning it believed the decision was in the best interests
of our partnership;
|
|
·
|
generally provides that affiliated transactions and resolutions of conflicts of interest not approved
by the conflicts committee of the board of directors of the general partner of our general partner and not involving a vote of
unitholders must be on terms no less favorable to us than those generally being provided to or available from unrelated third parties
or must be “fair and reasonable” to us, as determined by our general partner in good faith and that, in determining
whether a transaction or resolution is “fair and reasonable,” our general partner may consider the totality of the
relationships between the parties involved, including other transactions that may be particularly advantageous or beneficial to
us; and
|
|
·
|
provides that our general partner and its officers and directors will not be liable for monetary
damages to us, our limited partners or assignees for any acts or omissions unless there has been a final and non-appealable judgment
entered by a court of competent jurisdiction determining that the general partner or those other persons acted in bad faith or
engaged in fraud or willful misconduct or, in the case of a criminal matter, acted with knowledge that the conduct was criminal.
|
Holders of our
common units have limited voting rights and are not entitled to elect our general partner or the board of directors of its general
partner.
Unlike
the holders of common stock in a corporation, unitholders have only limited voting rights on matters affecting our business and,
therefore, limited ability to influence management’s decisions regarding our business. Unitholders will not elect our general
partner, its general partner or the members of its board of directors, and will have no right to elect our general partner, its
general partner or its board of directors on an annual or other continuing basis. The board of directors of EV Management is chosen
by EnerVest, the sole member of EV Management. Furthermore, if the unitholders were dissatisfied with the performance of our general
partner, they will have only a limited ability to remove our general partner. As a result of these limitations, the price at which
the common units will trade could be diminished because of the absence or reduction of a takeover premium in the trading price.
Control of our general partner may be
transferred to a third party without unitholder consent.
Our
general partner may transfer its general partner interest to a third party in a merger or in a sale of all or substantially all
of its assets without the consent of the unitholders. Furthermore, our partnership agreement does not restrict the ability of the
owners of our general partner or EV Management, from transferring all or a portion of their respective ownership interest in our
general partner or EV Management to a third party. The new owners of our general partner or EV Management would then be in a position
to replace the board of directors and officers of EV Management with its own choices and thereby influence the decisions taken
by the board of directors and officers.
Your liability may not be limited if
a court finds that unitholder action constitutes control of our business.
A
general partner of a partnership generally has unlimited liability for the obligations of the partnership, except for those contractual
obligations of the partnership that are expressly made without recourse to the general partner. Our partnership is organized under
Delaware law, and we conduct business in a number of other states. The limitations on the liability of holders of limited partner
interests for the obligations of a limited partnership have not been clearly established in some of the other states in which we
do business. You could be liable for any and all of our obligations as if you were a general partner if:
|
·
|
a court or government agency determined that we were conducting business in a state but had not
complied with that particular state’s partnership statute; or
|
|
·
|
your right to act with other unitholders to remove or replace the general partner, to approve some
amendments to our partnership agreement or to take other actions under our partnership agreement constitutes “control”
of our business.
|
Unitholders may have liability to repay
distributions that were wrongfully distributed to them.
Under
certain circumstances, unitholders may have to repay amounts wrongfully returned or distributed to them. Under Section 17–607
of the Delaware Revised Uniform Limited Partnership Act, we may not make a distribution to you if the distribution would cause
our liabilities to exceed the fair value of our assets. Delaware law provides that for a period of three years from the date of
the impermissible distribution, limited partners who received the distribution and who knew at the time of the distribution that
it violated Delaware law will be liable to the limited partnership for the distribution amount. Substituted limited partners are
liable for the obligations of the assignor to make contributions to the partnership that are known to the substituted limited partner
at the time it became a limited partner and for unknown obligations if the liabilities could be determined from the partnership
agreement. Liabilities to partners on account of their partnership interest and liabilities that are non–recourse to the
partnership are not counted for purposes of determining whether a distribution is permitted.
If we fail to maintain an effective
system of internal controls, we may not be able to accurately report our financial results or prevent fraud. As a result, current
and potential unitholders could lose confidence in our financial reporting, which would harm our business and the trading price
of our units.
Effective
internal controls are necessary for us to provide reliable financial reports, prevent fraud and operate successfully as a public
company. If we cannot provide reliable financial reports or prevent fraud, our reputation and operating results would be harmed.
We cannot be certain that our efforts to maintain our internal controls will be successful, that we will be able to maintain adequate
controls over our financial processes and reporting in the future or that we will be able to continue to comply with our obligations
under Section 404 of the Sarbanes-Oxley Act of 2002. Any failure to maintain effective internal controls, or difficulties
encountered in implementing or improving our internal controls, could harm our operating results or cause us to fail to meet our
reporting obligations. Ineffective internal controls could also cause investors to lose confidence in our reported financial information,
which would likely have a negative effect on the trading price of our units.
Tax Risks to Common Unitholders
An IRS contest of our US federal income
tax positions may adversely affect the market for our common units, and the cost of any IRS contest may be substantial.
We
have not requested a ruling from the IRS with respect to our treatment as a partnership for federal income tax purposes or any
other matter affecting us. It may be necessary to resort to administrative or court proceedings to sustain some or all of our counsel’s
conclusions or the positions we take. A court may not agree with all of our counsel’s conclusions or positions we take. Any
contest with the IRS may materially and adversely impact the market for our common units and the price at which they trade.
You may be required to pay taxes on income
from us even if you do not receive any cash distributions from us.
Because
our unitholders will be treated as partners to whom we will allocate taxable income which could be different in amount than the
cash we distribute, you will be required to pay any federal income taxes and, in some cases, state and local income taxes on your
share of our taxable income even if you receive no cash distributions from us. You may not receive cash distributions from us equal
to your share of our taxable income or even equal to the tax liability that results from that income.
Tax gain or loss on disposition of common
units could be more or less than expected.
If
you sell your common units, you will recognize a gain or loss equal to the difference between the amount realized and your tax
basis in those common units. Prior distributions to you in excess of the total net taxable income you were allocated for a common
unit, which decreased your tax basis in that common unit, will, in effect, become taxable income to you if the common unit is sold
at a price greater than your tax basis in that common unit, even if the price is less than your original cost. A substantial portion
of the amount realized, whether or not representing gain, may be ordinary income. In addition, if you sell your units, you may
incur a tax liability in excess of the amount of cash you receive from the sale.
Tax–exempt entities and foreign
persons face unique tax issues from owning common units that may result in adverse tax consequences to them.
Investment
in common units by tax–exempt entities, such as individual retirement accounts (known as IRAs), other retirement plans and
non–US persons raises issues unique to them. For example, virtually all of our income allocated to organizations that
are exempt from federal income tax, including IRAs and other retirement plans, will be unrelated business taxable income and will
be taxable to them. Distributions to non–US persons will be reduced by withholding taxes at the highest applicable effective
tax rate, and non–US persons will be required to file US federal tax returns and pay tax on their share of our taxable
income.
We will treat each purchaser of our common
units as having the same tax benefits without regard to the actual common units purchased. The IRS may challenge this treatment,
which could adversely affect the value of the common units.
Because
we cannot match transferors and transferees of common units and because of other reasons, we will take depreciation and amortization
positions that may not conform to all aspects of existing Treasury regulations. A successful IRS challenge to those positions could
adversely affect the amount of tax benefits available to you. It also could affect the timing of these tax benefits or the amount
of gain from the sale of common units and could have a negative impact on the value of our common units or result in audit adjustments
to your tax returns.
Unitholders
may be subject to state and local taxes and tax return filing requirements in states where they do not live as a result of investing
in our common units.
In
addition to federal income taxes, you will likely be subject to other taxes, including Medicare, state and local taxes, unincorporated
business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we do business
or own property, even if you do not live in any of those jurisdictions. You will likely be required to file state and local income
tax returns and pay state and local income taxes in some or all of these jurisdictions. Further, you may be subject to penalties
for failure to comply with those requirements. We own assets and do business in the states of Texas, Louisiana, Oklahoma, Arkansas,
New Mexico, Colorado, Kansas, Michigan, Ohio, West Virginia and Pennsylvania. Each of these states, other than Texas, currently
imposes a personal income tax. As we make acquisitions or expand our business, we may own assets or do business in additional states
that impose a personal income tax. It is your responsibility to file all US federal, foreign, state and local tax returns.
The tax treatment of publicly traded
partnerships or an investment in our common units could be subject to potential legislative, judicial or administrative changes
and differing interpretations, possibly on a retroactive basis.
The present federal income
tax treatment of publicly traded partnerships, including us, or an investment in our common units may be modified by legislative,
judicial or administrative changes and differing interpretations at any time. Specifically, from time to time, members of Congress
propose and consider substantive changes to the existing federal income tax laws that affect publicly traded partnerships. If successful,
such a proposal could eliminate the qualifying income exception to the treatment of all publicly traded partnerships as corporations
upon which we rely for our treatment as a partnership for US federal income tax purposes. Any modification to the US federal income
tax laws may be applied retroactively and could make it more difficult or impossible for us to meet the exception for certain publicly
traded partnerships to be treated as partnerships for US federal income tax purposes. We are unable to predict whether any of these
changes or other proposals will ultimately be enacted. Any such changes could negatively impact the value of an investment in our
common units.