Attached files

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EX-99.1 - EXHIBIT 99.1 - EP Energy LLCepenergy-12312019ex991.htm
EX-32.2 - EXHIBIT 32.2 - EP Energy LLCepenergyllc-12312019xex322.htm
EX-32.1 - EXHIBIT 32.1 - EP Energy LLCepenergyllc-12312019xex321.htm
EX-31.2 - EXHIBIT 31.2 - EP Energy LLCepenergyllc-12312019xex312.htm
EX-31.1 - EXHIBIT 31.1 - EP Energy LLCepenergyllc-12312019xex311.htm
EX-23.1 - EXHIBIT 23.1 - EP Energy LLCepenergyllc-12312019xex231.htm

 
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
 
Form 10-K
 (Mark One)
 
x      ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 
For the fiscal year ended December 31, 2019
 
OR
 
o         TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 
For the transition period from                  to                  .
 
Commission File Number 333-183815
 
EP Energy LLC
(Exact Name of Registrant as Specified in Its Charter)
Delaware
 
45-4871021
(State or Other Jurisdiction of
 
(I.R.S. Employer
Incorporation or Organization)
 
Identification No.)
 
 
 
1001 Louisiana Street
Houston, Texas
 
77002
(Address of Principal Executive Offices)
 
(Zip Code)
Telephone Number: (713) 997-1200
 Internet Website: www.epenergy.com 

Securities registered pursuant to Section 12(b) of the Act:  None
 Securities registered pursuant to Section 12(g) of the Act:  None
 Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.  Yes o No x.
 
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.  Yes x No o.
 
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.  Yes o No x.
 
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).  Yes x No o.
 
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. x
 
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and "emerging growth company" in Rule 12b-2 of the Exchange Act.
Large accelerated filer o
 
Accelerated filer o
Non-accelerated filer x
 
Smaller reporting company x
Emerging Growth Company o
 
 
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. o
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).  Yes o  No x.
 
EP ENERGY LLC MEETS THE CONDITIONS OF GENERAL INSTRUCTION I(1)(a) AND (b) TO FORM 10-K AND IS THEREFORE FILING THIS REPORT WITH A REDUCED DISCLOSURE FORMAT AS PERMITTED BY SUCH INSTRUCTION.
 
Documents Incorporated by Reference:  None
 



EP ENERGY LLC
TABLE OF CONTENTS 
Caption
 
Page
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Item 10. Directors, Executive Officers and Corporate Governance
 
*
 
 
 
Item 11. Executive Compensation
 
*
 
 
 
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
 
*
 
 
 
Item 13. Certain Relationships and Related Transactions, and Director Independence
 
*
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
*
We have not included a response to this item in this document since no response is required pursuant to the reduced disclosure format permitted by General Instruction I to Form 10-K.

i


Below is a list of terms that are common to our industry and used throughout this document:
/d
=
per day
Bbl
=
barrel
Bcf
=
billion cubic feet
Boe
=
barrel of oil equivalent
LLS
=
light Louisiana sweet crude oil
MBoe
=
thousand barrels of oil equivalent
MBbls
=
thousand barrels
Mcf
=
thousand cubic feet
MMBtu
=
million British thermal units
MMBoe
=
million barrels of oil equivalent
MMBbls
=
million barrels
MMcf
=
million cubic feet
Mt. Belvieu
=
natural gas liquids pricing index at the processing and storage hub in Mont Belvieu, TX
NGLs
=
natural gas liquids
NYMEX
=
New York Mercantile Exchange
TBtu
=
trillion British thermal units
Waha
=
natural gas pricing index at the Waha header system/vicinity in the Permian basin in West Texas
WTI
=
West Texas intermediate
When we refer to oil and natural gas in “equivalents,” we are doing so to compare quantities of oil with quantities of natural gas or to express these different commodities in a common unit. Equivalent volumes are computed with natural gas converted to barrels at a ratio of six Mcf to one Bbl. Also, when we refer to cubic feet measurements, all measurements are at a pressure of 14.73 pounds per square inch.
When we refer to “us”, “we”, “our”, “ours”, “the Company”, or “EP Energy”, we are describing EP Energy LLC and/or its subsidiaries.

ii


CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS
This report contains forward-looking statements that involve risks and uncertainties, many of which are beyond our control. These forward-looking statements are based on assumptions or beliefs that we believe to be reasonable; however, assumed facts almost always vary from the actual results and such variances can be material. Where we express an expectation or belief as to future results, that expectation or belief is expressed in good faith and is believed to have a reasonable basis. We cannot assure you, however, that the stated expectation or belief will occur. The words “believe”, “expect”, “estimate”, “anticipate”, "plan", “intend”, "could" and “should” and similar expressions will generally identify forward-looking statements. All of our forward-looking statements are expressly qualified by these and the other cautionary statements in this Annual Report, including those set forth in Item 1A. "Risk Factors". Important factors that could cause our actual results to differ materially from the expectations reflected in our forward-looking statements include, among others:
our ability to negotiate, execute and consummate the transactions contemplated by a plan of reorganization;
risks and uncertainties relating to the voluntary petitions (the “Chapter 11 Cases”) filed in the United States Bankruptcy Court, including: our ability to obtain Bankruptcy Court approval with respect to our motions, including maintaining strategic control as debtor in possession, risks associated with third-party motions, Bankruptcy Court rulings and the outcome of the Chapter 11 Cases in general, the length of time we will operate under the Chapter 11 Cases;
the potential adverse effects of disruption from the Chapter 11 Cases on us, our liquidity and/or results of operations, and on the interests of our various constituents making it more difficult to maintain business and operational relationships, retain key executives and maintain various licenses and approvals necessary for us to conduct our business;
increased advisory costs to execute our reorganization;
risk and uncertainties relating to: our ability to complete definitive documentation in connection with any    financing and the amount, terms and conditions of any such financing; and our ability to obtain requisite support for a chapter 11 restructuring plan from various stakeholders and confirm and consummate such restructuring plan;
risks associated with our ability to continue as a going concern;
risks related to the trading of our securities on the OTC Pink Market;
the volatility of and potential for sustained low oil, natural gas, and NGLs prices;
the supply and demand for oil, natural gas and NGLs;
risks relating to the recent announcements by Saudi Arabia and Russia;
risks related to epidemics, outbreaks or other public health events, such as the Coronavirus Disease 2019 (or COVID-19);
changes in commodity prices and basis differentials for oil and natural gas;
our ability to meet production volume targets;
the uncertainty of estimating proved reserves and unproved resources;
our ability to develop proved undeveloped reserves;
the future level of operating and capital costs;
the availability and cost of financing to fund future exploration and production operations;
the success of drilling programs with regard to proved undeveloped reserves and unproved resources;
our ability to comply with the covenants in various financing documents or to obtain any necessary consents, waivers or forbearance thereunder;
our ability to generate sufficient cash flow to meet our debt obligations and commitments;
our limited ability to borrow under existing debt agreements to fund our operations;

iii


our ability to obtain necessary governmental approvals for proposed exploration and production projects and to successfully construct and operate such projects;
actions by credit rating agencies, including potential downgrades;
credit and performance risks of our lenders, trading counterparties, customers, vendors, suppliers and third party operators;
general economic and weather conditions in geographic regions or markets we serve, or where operations are located, including the risk of a global recession and negative impact on demand for oil and/or natural gas;
the uncertainties associated with governmental regulation, including any potential changes in federal and state tax laws and regulations;
competition; and
the other factors described under Item 1A. “Risk Factors,” on pages 5 through 26 of this Annual Report on Form 10-K, and any updates to those factors set forth in our subsequent Quarterly Reports on Form 10-Q or Current Reports on Form 8-K.
In light of these risks, uncertainties and assumptions, the events anticipated by these forward-looking statements may not occur, and, if any of such events do occur, we may not have anticipated the timing of their occurrence or the extent of their impact on our actual results.  Accordingly, you should not place any undue reliance on any of these forward-looking statements.  These forward-looking statements speak only as of the date made, and we undertake no obligation, other than as required by applicable law, to update or revise its forward-looking statements, whether as a result of new information, subsequent events, anticipated or unanticipated circumstances or otherwise.
EXPLANATORY NOTE
EP Energy LLC is a wholly-owned subsidiary of EP Energy Corporation (OTC Pink Sheets: EPEGQ), which is a reporting company under the Securities and Exchange Act of 1934, as amended. Pursuant to General Instruction I of Form 10-K, EP Energy LLC has elected to furnish abbreviated disclosure in this Annual Report as set forth in such Instruction.

iv


PART I
ITEM 1. BUSINESS
Overview
EP Energy LLC (EP Energy), a wholly-owned subsidiary of EP Energy Corporation, is a Delaware limited liability company formed in 2012.  Our strategy is to invest in opportunities that provide the highest return across our asset base, continually seek out operating and capital efficiencies, effectively manage costs, and identify accretive acquisition opportunities and divestitures, all with the objective of enhancing our portfolio, growing asset value, improving cash flow and increasing financial flexibility.
We operate through a diverse base of producing assets and are focused on the development of our drilling inventory located in three areas: the Eagle Ford Shale in South Texas, Northeastern Utah (“NEU”) in the Uinta basin, and the Permian basin in West Texas. As of December 31, 2019, we had proved reserves of 189.7 MMBoe (49% oil and 70% liquids) and for the year ended December 31, 2019, we had average net daily production of 70,898 Boe/d (54% oil and 73% liquids).
Each of our areas is characterized by a long-lived reserve base and high drilling success rates. We have established significant contiguous leasehold positions in each area, representing approximately 465,000 net (609,000 gross) acres in total.
In addition to opportunities in our current portfolio, strategic acquisitions of leasehold acreage or acquisitions of producing assets can allow us to leverage existing expertise in our operating areas, balance our exposure to regions, basins and commodities, help us achieve or enhance risk-adjusted returns competitive with those available in our existing programs and increase our reserves. We also continuously evaluate our asset portfolio and will sell oil and natural gas properties if they no longer meet our long-term objectives.
Reorganization and Chapter 11 Cases
Formation of Special Committee. In the second quarter 2019, our Board of Directors (the “Board”) appointed a special committee (the “Special Committee”) of three independent directors that are not affiliated with the Sponsors (affiliates of Apollo Global Management, Inc. (“Apollo”), Riverstone Holdings LLC, Access Industries, Inc. (“Access”) and Korea National Oil Corporation, collectively, the “Sponsors”), and we engaged financial and legal advisors to consider a number of potential actions and evaluate certain strategic alternatives to address our liquidity and balance sheet issues.

Covenant Violations, Forbearance, and Chapter 11 Cases. On August 15, 2019, we did not make the approximately $40 million cash interest payment due and payable with respect to the 8.000% Senior Secured Notes due 2025 (the “2025 1.5 Lien Notes”). On September 3, 2019, we did not make the approximately $7 million cash interest payment due and payable with respect to the 7.750% Senior Notes due 2022 (the “2022 Unsecured Notes”). Our failure to make these interest payments within thirty days after they were due and payable resulted in an event of default under the respective indentures governing the 2025 1.5 Lien Notes and 2022 Unsecured Notes. Each event of default under the indentures noted above also resulted in a cross-default under the Prepetition Reserve-Based Facility (“RBL Facility”).

On September 14, 2019, we entered into forbearance agreements, extending through October 3, 2019, with (i) certain beneficial owners and/or investment advisors or managers of discretionary accounts for the beneficial owners of greater than 70% of the aggregate principal amount of the outstanding 2025 1.5 Lien Notes (collectively, the “Noteholders”) and (ii) certain lenders holding greater than a majority of the revolving commitments under our RBL Facility and the administrative agent and collateral agent under the RBL Facility (collectively, the “RBL Forbearing Parties”) pursuant to which each Noteholder and RBL Forbearing Party temporarily agreed to forbear from exercising any rights or remedies they may have occurred in respect of the failure to make the $40 million cash interest payment.

On October 3, 2019, we and certain of our direct and indirect subsidiaries (collectively with the Company, the “Debtors”) filed voluntary petitions (the “Chapter 11 Cases”) in the United States Bankruptcy Court for the Southern District of Texas (the “Bankruptcy Court”) seeking relief under chapter 11 of title 11 of the United States Code (the “Bankruptcy Code”). To ensure ordinary course operations, the Debtors obtained approval from the Bankruptcy Court for a variety of “first day” motions, including motions to obtain customary relief intended to assure our ability to continue our ordinary course operations after the filing date. In addition, the Debtors received authority to use cash collateral of the lenders under the RBL Facility.

The commencement of the Chapter 11 Cases constituted an immediate event of default, and caused the automatic and immediate acceleration of all debt outstanding under or in respect of a number of our instruments and agreements relating to our direct financial obligations, including our RBL Facility and indentures governing the 2025 1.5 Lien Notes, 7.750% Senior Secured Notes due 2026, 8.000% Senior Secured Notes due 2024 (the “2024 1.25 Lien Notes”), 9.375% Senior Secured Notes due 2024 (the “2024 1.5 Lien Notes”), 9.375% Senior Notes due 2020, 2022 Unsecured Notes and 6.375% Senior Notes due

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2023 (collectively, the “Senior Notes”). Any efforts to enforce such payment obligations were automatically stayed as a result of the filing of the Chapter 11 Cases and the creditors’ rights of enforcement in respect of the Senior Notes and the RBL Facility are subject to the applicable provisions of the Bankruptcy Code.

Plan Support Agreement and Backstop Commitment Agreement. On October 18, 2019, the Debtors entered into a plan support agreement (the “PSA”) to support a restructuring on the terms of a chapter 11 plan of reorganization (as defined below, the “Plan”) with holders of approximately 52.0% of the 2024 1.25 Lien Notes and approximately 79.3% of the 2024 1.5 Lien Notes and the 2025 1.5 Lien Notes issued, in each case, by EP Energy LLC and Everest Acquisition Finance Inc. The holders of these notes include affiliates of, or funds managed by, Elliott Management Corporation (“Elliott”), Apollo (together with Elliott, the “Initial Supporting Noteholders”), Access, and Avenue Capital Group (collectively, with the Initial Supporting Noteholders and Access, the “Supporting Noteholders”), to support a restructuring on the terms of a chapter 11 plan described therein. On October 18, 2019, the Debtors also entered into a backstop commitment agreement (the “BCA”) with the Supporting Noteholders, pursuant to which the Supporting Noteholders agreed to backstop $463 million (to consist of $325 million in cash and $138 million in exchanged reinstated 1.25L Notes) of the Rights Offering. For additional information, see Termination of Plan Support Agreement and Backstop Commitment Agreement below.

Plan of Reorganization. On November 18, 2019, the Debtors filed a proposed Joint Chapter 11 Plan and a proposed Disclosure Statement for Joint Chapter 11 Plan of Reorganization describing the Plan and the solicitation of votes to approve the same from certain of the Debtors’ creditors with respect to the Chapter 11 Cases. The Debtors subsequently filed various amendments to the Plan and Disclosure Statement and on January 13, 2020, filed an updated Fourth Amended Joint Chapter 11 Plan of EP Energy Corporation and its Affiliated Debtors (as amended from time to time, the “Plan”) and an updated Disclosure Statement (as amended from time to time, the “Disclosure Statement”). On March 6, 2020, after a hearing to confirm the Plan, the Bankruptcy Court stated that it would confirm the Plan. On March 12, 2020, pursuant to its ruling on March 6, 2020, the Bankruptcy Court entered an order confirming the Plan (ECF No. 1049).

Termination of Plan Support Agreement and Backstop Commitment Agreement. Commodity prices for oil, natural gas and NGLs historically have been volatile and may continue to be volatile in the future, especially given current global geopolitical and economic conditions. As a result of a decrease in global demand for oil and natural gas due to the recent coronavirus outbreaks, in March 2020, members of the Organization of the Petroleum Exporting Countries (“OPEC”) and Russia considered extending their agreed oil production cuts and making additional oil production cuts. However, negotiations to date have been unsuccessful. Saudi Arabia announced a significant increase in its maximum crude oil production capacity, targeting to supply 12.3 million barrels per day, an increase of 2.5 million barrels per day, effective immediately, and Russia announced that all agreed oil production cuts between members of OPEC and Russia will expire on April 1, 2020. Following these announcements, within one day, global oil prices declined to their lowest levels since 2016 and partially recovered, but may continue to decline. In addition, coronavirus outbreaks have resulted in delays, supply chain disruptions and travel restrictions that have impacted the oil and gas industry.

Subsequent to these events, on March 18, 2020, the Debtors and the Supporting Noteholders under the PSA and in their capacities as the Commitment Parties under the BCA, mutually agreed to amend and terminate the PSA and the BCA pursuant to the terms of a Stipulation of Settlement Regarding Backstop Agreement and Plan Support Agreement (as may be amended or modified from time to time, the “Stipulation”). Among other things, the Stipulation provides that (i) the PSA and BCA are terminated consensually by the parties pursuant to Section 9.1 of the BCA and Section 7(f) of the PSA, (ii) the Termination Fee (as defined in the BCA) shall not be payable to the Commitment Parties, (iii) the Debtors will reimburse all fees, costs and expenses of the Supporting Noteholders, and the Commitment Parties through the date on which the Bankruptcy Court approves the Stipulation, and (iv) through November 25, 2020 the Supporting Noteholders and Commitment Parties will not interfere, directly or indirectly, with any further restructuring of the Debtors, that treats their applicable claims no less favorably than other similarly situated claims. The Debtors and the Supporting Noteholders and Commitment Parties also agreed to mutual waivers and releases of certain claims relating to, or arising from, the Chapter 11 Cases, the BCA, the PSA, and the termination of the BCA and the PSA, against the other as described in the Stipulation.

On March 23, 2020, the Bankruptcy Court approved the Stipulation. The Debtors are working with their constituents to explore various alternatives.

Debtor-in-Possession Agreement. On November 25, 2019, EPE Acquisition, LLC and EP Energy LLC entered into a Senior Secured Superpriority Debtor-In-Possession Credit Agreement (as amended or modified from time to time, the “DIP Credit Agreement”) with JPMorgan Chase Bank, N.A., as administrative agent, collateral agent and an issuing bank (the “DIP Agent”) and the RBL Lenders which are party thereto as lenders (in such capacity, the “DIP Lenders”). Under the DIP Credit Agreement and the order of the Bankruptcy Court entered on November 25, 2019 (the “DIP Order”), a portion of the RBL Facility was converted into revolving commitments under the DIP Credit Agreement which provides for an approximately $315

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million debtor-in-possession senior secured superpriority revolving credit facility (the “DIP Facility”, and the loans thereunder, the “DIP Loans”), and which includes a letter of credit sublimit of $50 million. As of December 31, 2019, we had $150 million capacity remaining with approximately $17 million of letters of credit issued and $148 million outstanding under the DIP Facility. For a further discussion of the additional terms of the DIP Facility, see Part II, Item 7. “Management's Discussion and Analysis of Financial Condition and Results of Operations— Liquidity and Capital Resources” and Part II, Item 8. “Financial Statements and Supplementary Data”, Note 8.

EP Energy LLC will use the proceeds of the DIP Facility for, among other things, (i) the acquisition, development and exploration of oil and gas properties, for working capital and general corporate purposes, (ii) the payment of professional fees as provided for in the DIP Order, (iii) the payment of expenses incurred in the administration of the Chapter 11 Cases or as permitted by the certain orders and (iv) payments due thereunder or under the DIP Order. The maturity date of the DIP Facility is the earlier of (a) November 25, 2020, (b) the effective date of an “Acceptable Plan of Reorganization” (as defined in the DIP Credit Agreement), (c) the closing of a sale of substantially all of the equity or assets of EP Energy LLC (unless consummated pursuant to an Acceptable Plan of Reorganization), or (d) the termination of the DIP Facility during the continuation of an event of default thereunder.

On March 12, 2020, EP Energy LLC, EPE Acquisition, LLC, the agent and certain of the lenders under the RBL Facility, the DIP Agent and certain of the DIP Lenders entered into that certain Waiver of Credit Agreements which waived the occurrence of any event of default triggered under the credit agreement governing the RBL Facility (the “RBL Credit Agreement”) and the DIP Credit Agreement as a result of a going concern or like qualification or exception to the audited financials for the year ending December 31, 2019.

Exit Facility. The Debtors have received an underwritten commitment from the DIP Lenders to convert their DIP Loans and their remaining claims under the RBL Facility into an approximately $629 million exit senior secured reserve-based revolving credit facility (the “Exit Facility”) subject to certain conditions set forth therein, which will be evidenced by a senior secured revolving credit agreement, by and among EP Energy LLC, as borrower, EPE Acquisition, LLC, as holdings, the lenders party thereto from time to time, and JPMorgan Chase Bank, N.A., as administrative agent, collateral agent and an issuing bank (the “Exit Credit Agreement”).

For a further discussion of the Chapter 11 Cases and related matters, see Item 1A. “Risk Factors,” Part II, Item 7. “Management's Discussion and Analysis of Financial Condition and Results of Operations— Liquidity and Capital Resources” and Part II, Item 8. “Financial Statements and Supplementary Data”, Notes 1A, 7 and 8.

Reserves Summary

The following table provides a summary of oil, natural gas and NGLs reserves as of December 31, 2019 and production data for the year ended December 31, 2019 for each of our areas of operation.
 
 
Estimated Proved Reserves(1)
 
 
 
 
 
 
Oil
(MMBbls)
 
NGLs
(MMBbls)
 
Natural Gas
(Bcf)
 
Total
(MMBoe)
 
Liquids
(%)
 
Proved Developed (%)(2)
 
Average
Net Daily
Production
(MBoe/d)
Eagle Ford Shale
 
53.5

 
15.5

 
88.2

 
83.8

 
82
%
 
100
%
 
33.7

Northeastern Utah
 
24.7

 

 
97.3

 
40.9

 
60
%
 
100
%
 
15.7

Permian
 
14.7

 
24.0

 
158.3

 
65.0

 
59
%
 
100
%
 
21.5

Total
 
92.9

 
39.5

 
343.8

 
189.7

 
70
%
 
100
%
 
70.9

 
(1)
Proved reserves were evaluated based on the average first day of the month spot price for the preceding 12-month period of $55.69 per Bbl (WTI), $2.58 per MMBtu
(Henry Hub) and $13.37 per Bbl of NGLs.
(2)
As of December 31, 2019, we have no recorded proved undeveloped reserves due to uncertainty regarding the Company's availability of capital prior to emerging from bankruptcy that would be required to develop the PUD reserves (see Part II, Item 8. "Financial Statements and Supplementary Data", Note 1A).


Approximately 190 MMBoe, or 100%, of our total proved reserves are proved developed producing assets, which generated average production of 70.9 MBoe/d in 2019 from approximately 1,806 wells. As of December 31, 2019, we had approximately 93 MMBbls of proved oil reserves, 40 MMBbls of proved NGLs reserves and 344 Bcf of proved natural gas reserves, representing 49%, 21% and 30%, respectively, of our total proved reserves. For the year ended December 31, 2019, 73% of our production was related to oil and NGLs. 

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As of December 31, 2019, we operated 95% of our producing wells. This control provides us with flexibility around the amount and timing of capital spending and has allowed us to improve our capital and operating efficiencies. We also employ a function-based organizational structure to accelerate knowledge sharing, innovation, evaluation and target efficiencies across our drilling, completion and operating activities across our operating areas. In 2019, we completed 67 wells and as of December 31, 2019, we had a total of 41 wells drilled, but not completed across our programs.
Available Information
Our website is http://www.epenergy.com. We make available, free of charge on or through our website, our annual, quarterly and current reports, and any amendments to those reports, including related exhibits and supplemental schedules, as soon as is reasonably possible after these reports are filed or furnished with the Securities and Exchange Commission (“SEC”). The SEC maintains a website that contains reports, proxy and information statements and other information regarding issuers that file electronically with the SEC. All of our SEC filings are also available on the SEC's website at www.sec.gov. Information about each of the Board members, each of the Board’s standing committee charters, and the Corporate Governance Guidelines of our parent, EP Energy Corporation, as well as a copy of our Code of Conduct are also available, free of charge, through our website. Information contained on our website is not part of this report.

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ITEM 1A.    RISK FACTORS
Risks Related to Our Chapter 11 Cases
We are subject to risks and uncertainties associated with the Chapter 11 Cases filed with the Bankruptcy Court on October 3, 2019.
In 2019, we 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 PSA and commencement of the Chapter 11 Cases in the Bankruptcy Court on October 3, 2019.
On March 6, 2020, after a hearing to confirm the Plan, the Bankruptcy Court stated that it would confirm the Plan. On March 12, 2020, pursuant to its ruling on March 6, 2020, the Bankruptcy Court entered an order confirming the Plan (ECF No. 1049).
Commodity prices for oil, natural gas and NGLs historically have been volatile and may continue to be volatile in the future, especially given current global geopolitical and economic conditions. As a result of a decrease in global demand for oil and natural gas due to the recent coronavirus outbreaks, in March 2020, members of the Organization of the Petroleum Exporting Countries (“OPEC”) and Russia considered extending their agreed oil production cuts and making additional oil production cuts. However, negotiations to date have been unsuccessful. Saudi Arabia announced a significant increase in its maximum crude oil production capacity, targeting to supply 12.3 million barrels per day, an increase of 2.5 million barrels per day, effective immediately, and Russia announced that all agreed oil production cuts between members of OPEC and Russia will expire on April 1, 2020. Following these announcements, within one day, global oil prices declined to their lowest levels since 2016, recovered some of the losses, and may continue to decline. In addition, coronavirus outbreaks have resulted in delays, supply chain disruptions and travel restrictions that have impacted the oil and gas industry. Subsequent to these events, on March 18, 2020, the Debtors and the Supporting Noteholders under the PSA and in their capacities as the Commitment Parties under the BCA, mutually agreed to amend and terminate the PSA and the BCA pursuant the terms of the Stipulation. Among other things, the Stipulation provides that (i) the PSA and BCA are terminated consensually by the parties pursuant to Section 9.1 of the BCA and Section 7(f) of the PSA, (ii) the Termination Fee (as defined in the BCA) shall not be payable to the Commitment Parties, (iii) the Debtors will reimburse all fees, costs and expenses of the Supporting Noteholders, and the Commitment Parties through the date on which the Bankruptcy Court approves the Stipulation, and (iv) through November 25, 2020 the Supporting Noteholders and Commitment Parties will not interfere, directly or indirectly, with any further restructuring of the Debtors, that treats their applicable claims no less favorably than other similarly situated claims. The Debtors and the Supporting Noteholders and Commitment Parties also agreed to mutual waivers and releases of certain claims relating to, or arising from, the Chapter 11 Cases, the BCA, the PSA, and the termination of the BCA and the PSA, against the other as described in the Stipulation.

On March 23, 2020, the Bankruptcy Court approved the Stipulation. The Debtors are working with their constituents to explore various alternatives.
Our operations, our ability to develop and execute our business plan and our continuation as a going concern are subject to the risks and uncertainties associated with bankruptcy proceedings, including, among others: our ability to negotiate and execute another restructuring plan with respect to the Chapter 11 Cases; the high costs of bankruptcy proceedings and related fees; our ability to obtain sufficient financing to allow us to emerge from bankruptcy and execute our business plan post-emergence, and our ability to comply with terms and conditions of that financing; our ability to maintain our relationships with our lenders, counterparties, employees and other third parties; our ability to maintain contracts that are critical to our operations on reasonably acceptable terms and conditions; our ability to attract, motivate and retain key employees; the ability of third parties to use certain limited safe harbor provisions of the Bankruptcy Code to terminate contracts without first seeking Bankruptcy Court approval; the ability of third parties to seek and obtain court approval to convert the Chapter 11 Cases to Chapter 7 Cases; and the actions and decisions of our creditors and other third parties who have interests in our Chapter 11 Cases that may be inconsistent with our operational and strategic plans.
Delays in our Chapter 11 Cases increase the risks of our being unable to emerge from bankruptcy and may increase our costs associated with the bankruptcy process. These risks and uncertainties could affect our business and operations in various ways. For example, negative events associated with our Chapter 11 Cases could adversely affect our relationships with our lenders, counterparties, employees and other third parties, which in turn could adversely affect our operations and financial condition. Also, we need the prior approval of the Bankruptcy Court for transactions outside the ordinary course of business, which may limit our ability to respond timely to certain events or take advantage of certain opportunities. Because of the risks and uncertainties associated with our Chapter 11 Cases, we cannot accurately predict or quantify the ultimate impact of events that occur during our Chapter 11 Cases that may be inconsistent with our plans.

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Even if a restructuring transaction is consummated, we will continue to face a number of risks, including our ability to reduce expenses, implement any strategic initiatives, and generally maintain favorable relationships with and secure the confidence of our counterparties. Accordingly, we cannot guarantee when or on what terms a financial restructuring will be consummated or whether such plan will achieve our stated goals nor can we give any assurance of our ability to continue as a going concern.
Trading in our securities is highly speculative and poses substantial risks.

Trading in our securities is highly speculative and the market price of our common stock has been and may continue to be volatile. Any such volatility may affect the ability to sell our common stock at an advantageous price or at all.

Our anticipated emergence from the Chapter 11 Cases could adversely affect our business and relationships.

It is possible that our having filed for bankruptcy and our anticipated emergence from the Chapter 11 Cases could adversely affect our business and relationships with vendors, suppliers, service providers, customers, employees and other third parties. Due to uncertainties, many risks exist, including the following:

key suppliers or vendors could terminate their relationship with us or require additional financial assurances or enhanced performance from us;

the ability to renew existing contracts and compete for new business may be adversely affected;

the ability to attract, motivate and/or retain key executives and employees may be adversely affected;

the ability to attract, motivate and/or retain employees may be adversely affected;

employees may be distracted from performance of their duties or more easily attracted to other employment opportunities; and
competitors may take business away from us, and our ability to attract and retain customers may be negatively impacted.
The occurrence of one or more of these events could have a material and adverse effect on our operations, financial condition and reputation. We cannot assure you that having been subject to bankruptcy protection will not adversely affect our business or operations in the future.

In connection with the Disclosure Statement, and the hearing to consider confirmation of the Plan, we prepared a liquidation analysis and financial projections (collectively, “Analysis and Projections”) to demonstrate to the Bankruptcy Court the feasibility of the Plan and our ability to continue operations upon our anticipated emergence from bankruptcy. The Analysis and Projections were not prepared with a view toward compliance with the published guidelines of the SEC or the guidelines established by the Public Company Accounting Oversight Board and should not be relied upon to make an investment decision with respect to the Company. The Analysis and Projections do not purport to present the Company’s financial condition in accordance with GAAP. The Company’s independent registered public accounting firm has not examined, compiled or otherwise applied procedures to the Analysis and Projections and, accordingly, does not express an opinion or any other form of assurance with respect to the Analysis and Projections. Any financial projections or forecasts therein or as otherwise in the Disclosure Statement and the exhibits thereto reflect numerous assumptions with respect to financial condition, business and industry performance, general economic, market and financial conditions, and other matters, all of which are difficult to predict, and many of which are beyond the Company’s control. Accordingly, there can be no assurance that the assumptions made in preparing such Analysis and Projections will prove to be accurate. It is expected that there will be differences between actual and projected results, and the differences may be material, including due to the occurrence of unforeseen events occurring subsequent to the preparation of any financial projections or forecasts. The disclosure of the Analysis and Projections should not be regarded as an indication that the Company or its affiliates or representatives consider the Analysis and Projections to be a reliable prediction of future events, and the Analysis and Projections should not be relied upon as such. The Analysis and Projections are only estimates and actual results may vary considerably from the Analysis and Projections. The statements in the Analysis and Projections speak only as of the date such statements were made, or any earlier date indicated therein. The Company does not undertake any obligation to publicly update the Analysis and Projections to reflect circumstances existing after the date when the Analysis and Projections were filed with the Bankruptcy Court or to reflect the occurrence of future events, even in the event that any or all of the assumptions underlying the Analysis and Projections are shown to be in error.

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The implementation of a chapter 11 plan of reorganization will likely reduce or eliminate our federal income tax net operating loss carryforwards, and is expected to impair our ability to utilize any remaining net operating loss carryforwards and certain other tax attributes during the current year and in future years. Moreover, subsequent transfers of our equity, or issuances of equity, could further impair our ability to utilize our tax attributes.
Under federal income tax law, a corporation is generally permitted to offset some or all net taxable income in a given year with net operating losses carried forward from prior years. Our ability to utilize our net operating loss carryforwards, substantial tax basis in assets and other tax attributes to offset future taxable income and to reduce our federal income tax liability is subject to certain requirements and restrictions. In connection with the implementation of a chapter 11 plan of reorganization, we expect our net operating losses to be significantly reduced or eliminated due to discharge of indebtedness arising in our Chapter 11 Cases under section 108 of the Internal Revenue Code. In addition, the implementation of such a plan of reorganization is likely to result in an “ownership change” within the meaning of section 382 of the Internal Revenue Code. In general, an “ownership change” occurs if one or more stockholders owning 5% or more of a corporation’s common stock have aggregate increases in their ownership of such stock of more than 50 percentage points over a prescribed three-year testing period. Under section 382 and section 383 of the Internal Revenue Code, absent an applicable exception, if a corporation undergoes an “ownership change,” the amount of its net operating losses and other tax attributes that may be utilized to offset future taxable income generally is subject to an annual limitation. Based on information collected to date, we believe that we have not experienced an “ownership change” within the prior three years that impairs our ability to utilize our net operating loss carryforwards and other tax attributes. Also a stock trading restrictions order, which imposes notification procedures and trading restrictions on substantial stockholders, was approved and entered by the Bankruptcy Court on October 4, 2019, and is intended to reduce the likelihood of an ownership change occurring prior to the effective date of such a plan of reorganization.
In connection with an “ownership change” pursuant to a chapter 11 plan of reorganization, we expect that our ability to utilize our net operating losses and certain other tax attributes (other than tax basis) will be severely restricted by the resulting annual limitation, which could have a negative impact on our financial position and results of operations. Although an exception to the imposition of an annual limitation can apply in certain chapter 11 cases under section 382(l)(5) of the Internal Revenue Code, it is currently unknown if a chapter 11 plan of reorganization, once implemented will meet the requirements of such section or if we will elect out of the application of such section. Moreover, if we experience a subsequent “ownership change,” any remaining net operating losses and other tax attributes, including the substantial tax basis in our assets, could be subject to additional and more severe limitations. In addition, the Internal Revenue Service has proposed regulations that, depending on the rules ultimately adopted, could further substantially limit our ability to utilize our tax attributes in the event of an ownership change. As amended, the proposed regulations would not apply to an ownership change pursuant to a chapter 11 plan of reorganization, but could apply to a subsequent ownership change thereafter.
The Sponsors and other legacy investors own more than 75 percent of the equity interests in us and may have conflicts of interest with us and/or public investors.
Investment funds affiliated with, and one or more co-investment vehicles controlled by, our Sponsors (affiliates of Apollo Global Management LLC, Riverstone Holdings LLC, Access Industries and Korea National Oil Corporation, collectively, the “Sponsors”) and other legacy investors collectively own more than 75 percent of our equity interests and such persons or their designees hold substantially all of the seats on our board of directors. We are aware that certain of our Sponsors, in addition to other persons, also have significant holdings of our debt securities. As a result, the Sponsors and other large investors in our debt and equity securities, in their capacity as holders of our debt and/or equity securities, have the ability to prevent or significantly influence any transaction, including restructuring transactions, that would require the approval of stockholders or a class of our debt securities in which they have an influential position.
As noted above, however, a Special Committee consisting of independent members of the Board who are not affiliated with our Sponsors was appointed by the Board and is authorized to, among other things, consider, evaluate and approve strategic alternatives including financings, refinancings, amendments, waivers, forbearances, asset sales, debt issuances, exchanges and purchases, out-of-court or in-court restructurings (pursuant to which we may seek relief under the Bankruptcy Code) and/or similar transactions involving the Company. In connection with the Chapter 11 Cases, the Special Committee approved our entry into the PSA and BCA, as to which certain of our Sponsors are parties. Certain of our Sponsors may also take positions in the Chapter 11 Cases that may compete directly or indirectly with, or may be complementary to (or competitive with), our interests. On March 18, 2020, the Debtors and the Supporting Noteholders under the PSA and in their capacities as the Commitment Parties under the BCA, mutually agreed to amend and terminate the PSA and the BCA pursuant the terms of the Stipulation. Among other things, the Stipulation provides that through November 25, 2020 the Supporting Noteholders and Commitment Parties will not interfere, directly or indirectly, with any further restructuring of the Debtors, that treats their applicable claims no less favorably than other similarly situated claims. On March 23, 2020, the Bankruptcy Court approved the Stipulation.

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Additionally, the Sponsors and other legacy investors and the Initial Supporting Noteholders are in the business of making investments in companies and may from time to time acquire and hold interests in businesses that compete directly or indirectly with us or that supply us with goods and services. These persons may also pursue acquisition opportunities that may be complementary to (or competitive with) our business, and as a result those acquisition opportunities may not be available to us. In addition, the Sponsors’, the Initial Supporting Noteholders' and other investors’ interests in other portfolio companies could impact our ability to pursue acquisition opportunities.

On June 7, 2019, the NYSE filed a Form 25 to delist our common stock and now our common stock is quoted only in the over-the-counter market.
Our common stock was previously listed on the NYSE, but on June 7, 2019, the NYSE filed a Form 25 to delist our common stock and now our common stock is quoted only in the over-the-counter market. The delisting of our common stock from the NYSE has likely reduced the liquidity and market price of our common stock, reduced the number of investors willing to hold or acquire our common stock, reduced our ability to access equity markets to obtain financing, and reduced our ability to attract and retain personnel by means of equity compensation. Furthermore, as a result of our common stock being delisted, we saw decreases in analyst coverage, market making activity and information available concerning trading prices and volume, and fewer broker-dealers willing to execute trades with respect to our common stock.

Risks Related to Our Business and Industry
Events outside of our control, including an epidemic or outbreak of an infectious disease, such as the Coronavirus Disease 2019 (or COVID-19), may materially adversely affect our business.
We face risks related to epidemics, outbreaks or other public health events that are outside of our control, and could significantly disrupt our operations and adversely affect out financial condition. For example, the recent outbreak in Wuhan, China of COVID-19, which has spread across the globe and impacted financial markets and worldwide economic activity, may adversely affect out operations or the health of our workforce by rendering employees or contractors unable to work or unable to access our facilities for an indefinite period of time. In addition, the effects of COVID-19 and concerns regarding its global spread could negatively impact the domestic and internal demand for crude oil and natural gas, which could contribute to price volatility, impact the price we receive for oil and natural gas and materially and adversely affect the demand for and marketability of our production. As the potential impact from COVID-19 is difficult to predict, the extent to which it may negatively affect our operating results or the duration of any potential business disruption is uncertain. Any potential impact will depend on future developments and new information that may emerge regarding the severity and duration of COVID-19 and the actions taken by authorities to contain it or treat its impact, all of which are beyond our control. These potential impacts, while uncertain, could adversely affect our operating results.
The prices for oil, natural gas and NGLs are highly volatile and sustained lower prices have adversely affected, and may continue to adversely affect, our business, results of operations, cash flows and financial condition.
Our success depends upon the prices we receive for our oil, natural gas and NGLs. These commodity prices historically have been highly volatile and are likely to continue to be volatile in the future, especially given current global geopolitical and economic conditions. For example, during the period January 1, 2017 through December 31, 2019, the NYMEX WTI crude oil price per Bbl ranged from a low of $45.18 to a high of $70.98, and the NYMEX natural gas price per MMBtu ranged from a low of $2.22 to a high of $4.09. Commodity prices have experienced significant further declines during the first quarter of 2020, with prices for NYMEX WTI crude oil and NYMEX natural gas, respectively, reaching lows of $20.37 per Bbl and $1.60 per MMBtu during the period from January 1, 2020 through March 20, 2020. Commodity prices could also remain depressed for a sustained period. The prices for oil, natural gas and NGLs are subject to a variety of factors that are outside of our control, which include, among others:
regional, domestic and international supply of, and demand for, oil, natural gas and NGLs;
oil, natural gas and NGLs inventory levels in the United States;
political and economic conditions domestically and in other oil and natural gas producing countries, including the current conflicts in the Middle East and conditions in Africa, Russia and South America;
actions of OPEC and state-controlled oil companies relating to oil, natural gas and NGLs price and production controls;
wars, terrorist activities and other acts of aggression;

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weather conditions and weather patterns;
technological advances affecting energy consumption and energy supply;
adoption of various energy efficiency and conservation measures and alternative fuel requirements;
the price and availability of supplies of, and consumer demand for, alternative energy sources;
the price and quantity of U.S. imports and exports of oil, natural gas, including liquefied natural gas, and NGLs;
volatile trading patterns in capital and commodity-futures markets;
the strengthening and weakening of the U.S. dollar relative to other currencies;
changes in domestic governmental regulations, administrative and/or agency actions, and taxes, including potential restrictive regulations associated with hydraulic fracturing operations;
changes in the costs of exploring for, developing, producing, transporting, processing and marketing oil, natural gas and NGLs;
availability, proximity and cost of commodity processing, gathering and transportation and refining capacity;
perceptions of customers on the availability and price volatility of our products, particularly customers' perception of the volatility of oil and natural gas prices over the longer term; and
variations between product prices at sales points and applicable index prices.
Governmental actions may also affect oil, natural gas and NGLs prices.
The negative impact of low commodity prices on our cash flows could limit our cash available for capital expenditures and ultimately reduce our (i) drilling opportunities, (ii) future production volumes and operating revenues, and (iii) oil and gas reserves. Any resulting decreases in production could result in an additional shortfall in our expected cash flows and require us to further reduce our capital spending or borrow funds to cover any such shortfall. In addition to reducing our cash flows, a prolonged and substantial decline in commodity prices could negatively impact our proved oil and natural gas reserves, which in turn, may result in a significant write-down of the carrying value of our proved properties through a corresponding impairment charge on our income statement. For example, in the third quarter of 2019 we incurred non-cash impairment charges of approximately $458 million on our proved properties in NEU. In the fourth quarter of 2018, we incurred non-cash impairment charges of approximately $1,044 million and $59 million on our proved and unproved properties, respectively in the Permian basin. In addition to the impairment charges recorded in the third quarter of 2019 and fourth quarter of 2018, the continuation of current depressed commodity prices and future commodity price declines may cause changes to our capital spending levels, production rates, levels of proved reserves and development plans, which may result in a further impairment of the carrying value of our proved properties in the future.
We have significant capital programs in our business that may require us to access capital markets, and any inability to obtain access to the capital markets in the future at competitive rates, or any negative developments in the capital markets, could have a material adverse effect on our business.

We have significant capital programs in our business, which may require us to access the capital markets in order to continue the development of our properties. Since we are rated below investment grade and are highly levered, our ability to access the capital markets or the cost of capital could be negatively impacted, which could require us to forego opportunities or could make us less competitive in our pursuit of growth opportunities, especially in relation to many of our competitors that are larger than us or have greater financial resources. There is a risk that our non-investment grade credit rating may be further lowered in the future in light of the sustained lower commodity price environment as well as our substantial leverage, limited liquidity, undesirable credit profile and other factors. Reductions in our credit rating could have a negative impact on us. For example, a lower credit rating could limit our available liquidity if we are required to post incremental collateral on transportation contract obligations or other contractual commitments.
In addition, the turmoil in recent years in the credit markets for companies in the energy sector with volatile commodity prices has led to reduced credit availability, tighter lending standards and higher interest rates on loans for energy companies, especially non-investment grade companies. While we cannot predict the future condition of the credit markets, future turmoil in the credit markets could have a material adverse effect on our business, liquidity, financial condition and cash

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flows, particularly if our ability to borrow money from lenders or access the capital markets to finance our operations were to be impaired.
Our primary source of liquidity beyond cash flow from operations is our debtor-in-possession, or DIP Facility. At February 28, 2020, we had $130 million outstanding under the DIP Facility. We have also received an underwritten commitment from the DIP Lenders to convert their DIP Loans and their remaining claims under the RBL Facility into an approximately $629 million exit senior secured reserve-based revolving credit facility (the “Exit Facility”).
Although we believe that the banks participating in the DIP and Exit Facilities have adequate capital and resources, we can provide no assurance that all of those banks will continue to operate as going concerns in the future, or continue to participate in the facility. If any of the banks in our lending group were to fail, or choose not to participate, it is possible that the borrowing capacity under the Exit Facility would be reduced. In the event of such reduction, we could be required to obtain capital from alternate sources or find additional Exit Facility participants in order to finance our capital needs. Our options for addressing such capital constraints would include, but not be limited to, obtaining commitments from the remaining banks in the lending group and accessing the public and private capital markets. In addition, we may delay certain capital expenditures to ensure that we maintain appropriate levels of liquidity. If it became necessary to access additional capital, any such alternatives could have terms less favorable than the current terms under the DIP and Exit Facilities, which could have a material adverse effect on our business, results of operations, financial condition and cash flows.
Our substantial indebtedness and high leverage could adversely affect our ability to operate our business, we may not be able to generate sufficient cash flows to service our indebtedness and we may be forced to take actions to satisfy our debt obligations that may not be successful.
As of December 31, 2019, our total debt was approximately $4.6 billion including approximately $315 million of Prepetition RBL Facility, $688 million primarily comprised of senior unsecured notes due in 2020, 2022 and 2023, and $3.6 billion in senior secured notes due in 2024, 2025 and 2026. For the year ended December 31, 2019, we incurred $419 million in interest expense. The commencement of the Chapter 11 Cases constituted an immediate event of default, and caused the automatic and immediate acceleration of all debt outstanding under or in respect of a number of our instruments and agreements relating to our direct financial obligations, including our RBL Facility and indentures governing the 2025 1.5 Lien Notes, 7.750% Senior Secured Notes due 2026, 2024 1.25 Lien Notes, 2024 1.5 Lien Notes, 9.375% Senior Notes due 2020, 2022 Unsecured Notes and 6.375% Senior Notes due 2023. Nevertheless, there is no guarantee that we will be able to successfully achieve sufficient reductions in our debt and debt service costs or otherwise meet our planned continuing obligations. Failure to achieve substantial interest cost reduction and other cost savings upon emergence could materially hamper our ability to operate profitably after emergence, and could result in our inability to continue as a going concern in the future.
To the extent we are not able to discharge a substantial portion of our indebtedness through the Chapter 11 Cases, a substantial level of indebtedness could have material consequences for our business, results of operations and financial condition, including:
requiring us to dedicate a substantial portion of our cash flow from operations to debt service payments thereby reducing the availability of cash for working capital, capital expenditures, acquisitions or general corporate purposes;
limiting our ability to borrow money for our working capital, capital expenditures (including the development of reserves), debt service requirements, strategic initiatives or other purposes;
exposing us to more liquidity risks, including breach of covenants and default risks, especially during times of financial and commodity price volatility;
making us more vulnerable to downturns in our business or the economy;
limiting our flexibility in planning for, or reacting to, changes in our operations or business;
increasing our leverage relative to our competitors, which may place us at a competitive disadvantage;
restricting us from making strategic acquisitions, engaging in development activities, introducing new technologies or exploiting business opportunities;
causing us to make non-strategic divestitures;
requiring us to secure additional sources of liquidity, which may or may not be available to us; or

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causing us to issue equity thereby diluting existing stockholders.
Our ability to restructure or refinance our indebtedness will depend on our financial condition and the terms of our existing debt agreements and the condition of the capital markets at that time, and our financial condition at such time, and any refinancing of our debt could be at higher interest rates and may require us to comply with more onerous covenants, which could further restrict our business and operations. 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 and results of operations.
In addition, any failure to make payments of interest and principal on our outstanding indebtedness on a timely basis would likely result in a default under that indebtedness, which would likely cause cross defaults under our other indebtedness, which could force us into bankruptcy or liquidation. 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. These alternative measures may not be successful and may not permit us to meet our scheduled debt service obligations.

The success of our business depends upon our ability to find and replace reserves that we produce.
Similar to our competitors, we have a reserve base that is depleted as it is produced. Unless we successfully replace the reserves that we produce, our reserves will decline, which will eventually result in a decrease in oil and natural gas production and lower revenues and cash flows from operations. We historically have replaced reserves through both drilling and acquisitions. The business of exploring for, developing or acquiring reserves requires substantial capital expenditures. If we do not continue to make significant capital expenditures (for any reason, including our access to capital resources becoming limited) or if our exploration, development and acquisition activities are unsuccessful, we may not be able to replace the reserves that we produce, which would negatively impact us. As a result, our future oil and natural gas reserves and production, and therefore our cash flow and results of operations, are highly dependent upon our success in efficiently developing and exploiting our current properties 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 or at all. If we are unable to replace our current and future production, the value of our reserves will decrease, and our business, results of operations and financial condition would be materially adversely affected. As of December 31, 2019, we have not recorded any PUD’s due to uncertainty regarding the ability to continue as a going concern (see Part II, Item 8. “Financial Statements and Supplementary Data,” Note 1A) and the availability of capital that would be required to develop the PUD reserves. See Item 1. “Business” under the heading Oil and Natural Gas Properties for further discussion on our proved reserves.
Our oil and natural gas drilling and producing operations involve many risks, and our production forecasts may differ from actual results.
Our success will depend on our drilling results which are subject to the risk that (i) we may not encounter commercially productive reservoirs or (ii) if we encounter commercially productive reservoirs, we either may not fully recover our investments or our rates of return will be less than expected. Our past performance should not be considered indicative of future drilling performance. As a result, there remains uncertainty on the results of our drilling programs, including our ability to realize proved reserves or to earn acceptable rates of return on our drilling programs. From time to time, we provide forecasts of expected quantities of future production. These forecasts are based on a number of estimates, including expectations of production from existing wells and the outcome of future drilling activity. Our forecasts could be different from actual results and such differences could be material.
Our decisions to purchase, explore, develop or otherwise exploit prospects or properties will depend in part on the evaluation of data obtained through geophysical and geological analyses, production data and engineering studies, the results of which are often inconclusive or subject to varying interpretations. In addition, the results of our exploratory drilling in new or emerging areas are more uncertain than drilling results in areas that are developed and have established production. Our cost of drilling, completing, equipping and operating wells is often uncertain before drilling commences. Overruns in budgeted expenditures are common risks that can make a particular project uneconomical or less economic than forecasted. Further, many factors may increase the cost of, or curtail, delay or cancel drilling operations, including the following:
unexpected drilling conditions;
delays imposed by or resulting from compliance with regulatory and contractual requirements, including requirements on sourcing of materials;

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unexpected pressure or irregularities in geological formations;
equipment failures or accidents;
fracture stimulation accidents or failures;
adverse weather conditions;
declines in oil and natural gas prices;
surface access restrictions with respect to drilling or laying pipelines;
shortages (or increases in costs) of water used in hydraulic fracturing, especially in arid regions or regions that have been experiencing severe drought conditions;
shortages or delays in the availability of, increases in the cost of, or increased competition for, drilling rigs and crews, fracture stimulation crews, equipment, pipe, chemicals and supplies and transportation, gathering, processing, treating or other midstream services; and
limitations or reductions in the market for oil and natural gas.
Additionally, the occurrence of certain of these events, particularly equipment failures or accidents, could impact third parties, including persons living in proximity to our operations, our employees and employees of our contractors, leading to possible injuries or death or significant property damage. As a result, we face the possibility of liabilities from these events that could materially adversely affect our business, results of operations and financial condition.
In addition, uncertainties associated with enhanced recovery methods may not allow for the extraction of oil and natural gas in a manner or to the extent that we anticipate and we may be unable to realize an acceptable return on our investments in certain of our projects. The additional production and reserves, if any, attributable to the use of enhanced recovery methods are inherently difficult to predict.
Our drilling locations are scheduled to be drilled over a number of years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling.
Our management has identified and scheduled potential drilling locations as an estimate of our future multi-year drilling activities on our existing acreage. All of our potential drilling locations, particularly our potential drilling locations for oil, represent a significant part of our strategy. Our ability to drill and develop these locations is subject to a number of uncertainties, including the availability of capital, seasonal conditions, regulatory approvals, oil, natural gas and NGLs prices, costs and drilling results. If our capital resources are insufficient to support our drilling activities or other risks materialize, we may be unable to drill and develop these locations. Because of these uncertainties, we do not know if the drilling locations we have identified will ever be drilled or if we will be able to produce oil, natural gas or NGLs from these or any other potential drilling locations. Pursuant to existing SEC rules and guidance, subject to limited exceptions, proved undeveloped reserves may only be booked if they relate to wells where a final investment decision has been made to drill within five years of the date of booking. As of December 31, 2019, we have not recorded any PUD’s due to uncertainty regarding the ability to continue as a going concern (see Part II, Item 8. “Financial Statements and Supplementary Data”, Note 1A) and the availability of capital that would be required to develop the PUD reserves.
Certain of our undeveloped leasehold acreage is subject to leases that will expire in several years unless production is established on units containing the acreage.
Although many of our reserves are located on leases that are held-by-production or held by continuous development, we do have provisions in a number of our leases that provide for the lease to expire unless certain conditions are met, such as drilling having commenced on the lease or production in paying quantities having been obtained within a defined time period. If commodity prices remain lower or we are unable to allocate sufficient capital to meet these obligations, there is a risk that some of our existing proved reserves and some of our unproved inventory/acreage could be subject to lease expiration or a requirement to incur additional leasehold costs to extend the lease. This could result in impairment of remaining costs and a reduction in our reserves and our growth opportunities (or the incurrence of significant costs) and therefore could have a material adverse effect on our financial results.
Drilling locations that we decide to drill may not yield oil, natural gas or NGLs in commercially viable quantities.
Our future drilling locations are in various stages of evaluation, ranging from a location which is ready to drill to a location that will require substantial additional interpretation. There is no way to predict in advance of drilling and testing

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whether any particular location will yield oil, natural gas or NGLs in sufficient quantities to recover drilling or completion costs or to be economically viable. The use of technologies and the study of producing fields in the same area will not enable us to know conclusively, prior to drilling, whether oil, natural gas or NGLs will be present or, if present, whether oil, natural gas or NGLs will be present in sufficient quantities to be economically viable. Even if sufficient amounts of oil, natural gas or NGLs exist, we may damage the potentially productive hydrocarbon-bearing formation or experience mechanical difficulties while drilling or completing the well, resulting in a reduction in production from the well or abandonment of the well. We cannot assure you that the analogies we draw from available data from other wells, more fully explored locations or producing fields will be applicable to our other identified drilling locations. Further, initial production rates reported by us or other operators may not be indicative of future or long-term production rates.  The cost of drilling, completing and operating any well is often uncertain, and new wells may not be productive.
We require substantial capital expenditures to conduct our operations, engage in acquisition activities and replace our production, and we may be unable to obtain needed financing on satisfactory terms necessary to execute our operating strategy.
We require substantial capital expenditures to conduct our exploration, development and production operations, engage in acquisition activities and increase our proved reserves and production. In 2019, we spent total capital of $517 million (not including approximately $19 million in acquisition capital). For a discussion of liquidity, see Part II, Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources and Production Volumes and Drilling Summary”. We also may engage in asset sale transactions to, among other things, fund capital expenditures when market conditions permit us to complete monetization transactions on terms we find acceptable. There can be no assurance that such sources will be available to us or sufficient to fund our exploration, development and acquisition activities. If our revenues and cash flows continue to decrease in the future as a result of declines in commodity prices or a reduction in production levels, and we are unable to obtain additional equity or debt financing in the capital markets or access alternative sources of funds, we may be required to reduce the level of our capital expenditures and may lack the capital necessary to increase or even maintain our reserves and production levels.
Interest rates could negatively affect our financing costs and ability to access capital. We have near-term exposure to interest rates from outstanding indebtedness indexed to variable interest rates, and we have exposure to potentially rising interest rates in the future to the extent we seek to raise debt in the capital markets to meet maturing debt obligations and fund our operations. Disruptions in capital and credit markets in the past have resulted in higher interest rates on new publicly issued debt and increased costs for variable interest rate debt.

Due to these factors, we cannot be certain that funding, if needed, will be available to the extent required, or on acceptable terms. If we are unable to access funding when needed on acceptable terms, we may not be able to fully implement our business plans, take advantage of business opportunities, respond to competitive pressures or refinance our debt obligations as they come due, any of which could have a material adverse effect on our business, financial condition, cash flows and results of operations.

Our acquisition attempts may not be successful or may result in completed acquisitions that do not perform as anticipated.
We have made and may continue to make acquisitions of businesses and properties. However, suitable acquisition candidates may not continue to be available on terms and conditions we find acceptable or at all. Additionally, any acquisition involves potential risks, including (i) the inability to integrate acquired businesses successfully and produce revenues, reserves, earnings or cash flow at anticipated levels or could have environmental, permitting or other problems for which contractual protections prove inadequate, (ii) the assumption of liabilities that were not disclosed to us and for which contractual protections prove inadequate or that exceed our estimates; and (iii) the potential loss of key customers and/or employees. Any of the above risks could significantly impair our ability to manage our business, complete or effectively integrate acquisitions and may have a material adverse effect on our business, results of operations and financial condition.
Retained liabilities associated with businesses or assets that we have sold could exceed our estimates and we could experience difficulties in managing these liabilities.
We have sold various assets and either retained certain liabilities or indemnified certain purchasers against future liabilities relating to businesses and assets sold, including breaches of warranties, environmental expenditures, asset retirements and other representations that we have provided.  We may also be subject to retained liabilities with respect to certain divested assets by operation of law.  For example, the recent and sustained decline in commodity prices has created an environment where there is an increased risk that owners and/or operators of assets purchased from us may no longer be able to satisfy plugging or abandonment obligations that attach to such assets. In that event, due to operation of law, we may be required to assume these plugging or abandonment obligations on assets no longer owned and operated by us. Although we believe that we

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have established appropriate reserves for any such liabilities, we could be required to accrue additional amounts in the future and these amounts could be material.
Our use of derivative financial instruments could result in financial losses or could reduce our income.
We use fixed price financial options and swaps to mitigate our commodity price and basis exposures. However, we do not typically hedge all of these exposures, and typically do not hedge any of these exposures beyond several years. Our derivative contracts (primarily fixed price derivatives) as of December 31, 2019, will allow us to realize a weighted average price of $55.89 and $55.52 per barrel on 13,561 MBbls and 90 MBbls of oil in 2020 and 2021, respectively. Subsequent to December 31, 2019, we unwound 4,026 MBbls of 2020 WTI oil three-way collars with a ceiling price of $64.97, a floor price of $55.00 and a sub-floor price of $45.00 per barrel of oil and replaced it with 4,148 MBbls of 2020 WTI oil fixed price swaps with an average price of $59.98 per barrel of oil. In addition, we entered into derivative contracts on 90 MBbls of 2021 WTI oil fixed price swaps with an average price of $55.05 per barrel of oil and 900 MBbls of 2021 WTI oil three-way collars with a ceiling price of $60.51, a floor price of $55.00 and a sub-floor price of $45.00 per barrel of oil. We have no price protection currently past this timeframe. As a result, we have substantial commodity price and basis exposure since our business has multi-year drilling programs for our proved reserves and unproved resources, particularly as our existing hedges roll off.
The derivative contracts we enter into to mitigate commodity price risk are not designated as accounting hedges and are therefore marked to market. As a result, we experience volatility in our revenues and net income as a result of changes in commodity prices, counterparty non-performance risks, correlation factors and changes in the liquidity of the market. Furthermore, the valuation of these financial instruments involves estimates based on assumptions that could prove to be incorrect and result in financial losses. Although we have internal controls in place that impose restrictions on the use of derivative instruments, there is a risk that such controls will not be complied with or will not be effective, and we could incur substantial losses on our derivative transactions. The use of derivatives, to the extent they require collateral posting with our counterparties, could impact our working capital and liquidity when commodity prices or change.
To the extent we enter into derivative contracts to manage our commodity price and basis exposures, we may forego the benefits we could otherwise experience if such prices were to change favorably and we could experience losses to the extent that these prices were to increase above the fixed price.  In addition, these hedging arrangements also expose us to the risk of financial loss in the following circumstances, among others:
when production is less than expected or less than we have hedged;
when the counterparty to the hedging instrument defaults on its contractual obligations;
when there is an increase in the differential between the underlying price in the hedging instrument and actual prices received; and
when there are issues with respect to legal enforceability of such instruments.
Our derivative counterparties are typically large financial institutions. We are subject to the risk of loss on our derivative instruments as a result of non-performance by our counterparties, especially when there is a significant decline in commodity prices. The ability of our counterparties to meet their obligations to us on hedge transactions could reduce our revenue from hedges at a time when we are also receiving a lower price for our oil and natural gas sales. As a result, our business, results of operations and financial condition could be materially adversely affected.
In 2010, the Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”) provided for federal oversight of the over-the-counter derivatives market and entities that participate in that market. The Dodd-Frank Act mandated that the Commodity Futures Trading Commission (the “CFTC”), the SEC and certain federal regulators of financial institutions (the Prudential Regulators) adopt rules or regulations to implement the Dodd-Frank Act and provide definitions of terms. Among other things, the Dodd-Frank Act and associated rules established margin requirements and required clearing and trade execution practices for certain market participants and resulted in certain market participants curtailing and/or ceasing their derivatives activities. The Dodd-Frank Act and associated rules also place limitations on our ability to enforce remedies against our swap counterparties who are regulated by the Prudential Regulators, and proposed rules would impose position limits on some market participants and also modify the capital reserve requirements applicable to our swap counterparties. While we qualify for various exceptions under the Dodd-Frank Act and associated rules as well as similar foreign regulations enacted by the European Union and other non-U.S. jurisdictions, most if not all of our hedge counterparties are subject to various provisions of these regulations and proposed regulations, which could significantly increase the cost of our derivative contracts, materially alter the terms of our derivative contracts, reduce the availability of derivatives to us that we have historically used to protect against risks that we encounter in our business, reduce our ability to monetize or restructure our existing derivative contracts, and increase our exposure to less creditworthy counterparties. If we reduce our use of derivatives

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as a result of the Dodd-Frank Act and related rules and/or similar foreign regulations, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures. Finally, the Dodd-Frank Act was intended, in part, to reduce the volatility of oil and natural gas prices, which some legislators attributed to speculative trading in derivatives and commodity contracts related to oil and natural gas. Our revenues could therefore be adversely affected if a consequence of the Dodd-Frank Act and regulations is to lower commodity prices. Any of these consequences could have a material adverse effect on us, our financial condition, and our results of operations.

Estimating our reserves involves uncertainty, our actual reserves will likely vary from our estimates, and negative revisions to our reserve estimates in the future could result in decreased earnings and/or losses and impairments.

All estimates of proved reserves are determined according to the rules prescribed by the SEC. Our reserve information is evaluated and prepared by an independent petroleum engineering consultant. There are numerous uncertainties involved in estimating proved reserves, which may result in our estimates varying considerably from actual results. Estimating quantities of proved reserves is complex and involves significant interpretation and assumptions with respect to available geological, geophysical and engineering data, including data from nearby producing areas. It also requires us to estimate future economic factors, such as commodity prices, production costs, plugging and abandonment costs, severance, ad valorem and excise taxes, capital expenditures, workover and remedial costs, and the assumed effect of governmental regulation. Due to a lack of substantial production data, there are greater uncertainties in estimating proved undeveloped reserves, proved developed non-producing reserves and proved developed reserves that are early in their production life. As a result, our reserve estimates are inherently imprecise. Furthermore, estimates are subject to revision based upon a number of factors, including many factors beyond our control such as reservoir performance, prices (including commodity prices and the cost of oilfield services), economic conditions and government restrictions and regulations. In addition, results of drilling, testing and production subsequent to the date of an estimate may justify revision of that estimate. Therefore, our reserve information represents an estimate and is often different from the quantities of oil and natural gas that are ultimately recovered or proven recoverable.
The SEC rules require the use of a 10% discount factor for estimating the value of our future net cash flows from reserves and the use of a historical 12-month average price. This discount factor may not necessarily represent the most appropriate discount factor, given our costs of capital, actual interest rates and risks faced by our exploration and production business, and the average historical price will not generally represent the future market prices for oil and natural gas over time. Any significant change in commodity prices could cause the estimated quantities and net present value of our reserves to differ and these differences could be material. You should not assume that the present values referred to in this Annual Report on Form 10-K represent the current market value of our estimated oil and natural gas reserves. Finally, the timing of the production and the expenses related to the development and production of oil and natural gas properties will affect both the timing of actual future net cash flows from our proved reserves and their present value.
We account for our activities under the successful efforts method of accounting. Changes in the estimated fair value of these reserves could result in a write-down in the carrying value of our oil and natural gas properties, which could be substantial and could have a material adverse effect on our net income and stockholders’ equity. Lower estimated fair value of these reserves could also result in lower recorded reserves, which would increase our depreciation, depletion and amortization rates and decrease earnings.
A portion of our proved reserves are undeveloped. Recovery of undeveloped reserves requires significant capital expenditures and successful drilling operations. As of December 31, 2019, we have not recorded any PUD’s due to uncertainty regarding the ability to continue as a going concern (see Part II, Item 8. “Financial Statements and Supplementary Data,” Note 1A) and the availability of capital that would be required to develop the PUD reserves.
In addition, because our proved reserve base consists primarily of unconventional resources, the costs of finding, developing and producing those reserves may require capital expenditures that are greater than more conventional resource plays. Our estimates of proved reserves assume that we can and will make these expenditures and conduct these operations successfully. However, future events, including commodity price changes and our ability to access capital markets, may cause these assumptions to change.
Our business is subject to competition from third parties, which could negatively impact our ability to succeed.
The oil, natural gas and NGLs businesses are highly competitive. We compete with third parties in the search for and acquisition of leases, properties and reserves, as well as the equipment, materials and services required to explore for and produce our reserves. There has been intense competition for the acquisition of leasehold positions, particularly in many of the oil and natural gas shale plays. 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 fund and consummate transactions in a highly

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competitive environment. In addition, because we have fewer financial and human resources than many companies in our industry, we may be at a disadvantage in bidding for exploratory prospects and producing oil properties. Similarly, we compete with many third parties in the sale of oil, natural gas and NGLs to customers, some of which have substantially larger market positions, marketing staff and financial resources than us. Our competitors include major and independent oil and natural gas companies, as well as financial services companies and investors, many of which have financial and other resources that are substantially greater than those available to us. Many of these companies not only explore for and produce oil and natural gas, 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 productive oil and natural gas properties and exploratory prospects or define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit. In addition, these companies may have a greater ability to continue exploration activities during periods of low oil and natural gas market prices.
Furthermore, there is significant competition between the oil and natural gas industry and other industries producing energy and fuel, which may be substantially affected by various forms of energy legislation and/or regulation considered from time to time by federal, state and local governments. It is not possible to predict the nature of any such legislation or regulation that may ultimately be adopted or its effects upon our future operations. Such laws and regulations may substantially increase the costs of exploring for, developing or producing oil and natural gas and may prevent or delay the commencement or continuation of a given operation. Our larger competitors may be able to absorb the burden of existing, and any changes to, federal, state and local laws and regulations more easily than we can, which could negatively impact our competitive position.
Our industry is cyclical, and at certain times historically there have been shortages of drilling rigs, equipment, supplies or qualified personnel. A sustained decline in commodity prices can also reduce the number of service providers for such drilling rigs, equipment, supplies or qualified personnel, contributing to or also resulting in the shortages. Alternatively, during periods of high prices, the cost of rigs, equipment, supplies and personnel can fluctuate widely, significant cost inflation may occur, and availability may be limited. These services may not be available on commercially reasonable terms or at all. We cannot predict the extent to which these conditions will exist in the future or their timing or duration. The high cost or unavailability of drilling rigs, equipment, supplies, personnel and other oil field services could significantly decrease our profit margins, cash flows and operating results and could restrict our ability to drill the wells and conduct the operations that we currently have planned and budgeted or that we may plan in the future. Any of these outcomes could have a material adverse effect on our business, results of operations and financial condition.
Our business is subject to operational hazards and uninsured risks that could have a material adverse effect on our business, results of operations and financial condition.
Our oil and natural gas exploration and production activities are subject to all of the inherent risks associated with drilling for and producing natural gas and oil, including the possibility of:
Adverse weather conditions, natural disasters, and/or other climate related matters—including extreme cold or heat, lightning and flooding, severe drought, fires, earthquakes, hurricanes, tropical storms, tornadoes and other natural disasters. Although the potential effects of climate change on our operations (such as hurricanes, flooding, etc.) are uncertain at this time, changes in climate patterns could also have a negative impact upon our operations in the future, particularly with regard to any of our facilities that are located in or near coastal regions;
Acts of aggression on critical energy infrastructure—including terrorist activity or “cyber security” events. We are subject to the ongoing risk that one of these incidents may occur which could significantly impact our business operations and/or financial results. Should one of these events occur in the future, it could impact our ability to operate our drilling and exploration processes, our operations could be disrupted, and/or property could be damaged resulting in substantial loss of revenues, increased costs to respond or other financial loss, damage to reputation, increased regulation and litigation and/or inaccurate information reported from our exploration and production operations to our financial applications, to our customers and to regulatory entities; and
Other hazards—including the collision of third-party equipment with our infrastructure; explosions, equipment malfunctions, mechanical and process safety failures, well blowouts, formations with abnormal pressures and collapses of wellbore casing or other tubulars; events causing our facilities to operate below expected levels of capacity or efficiency; uncontrollable flows of natural gas, oil, brine or well fluids, release of pollution or contaminants (including hydrocarbons) into the environment (including discharges of toxic gases or substances) and other environmental hazards.

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Each of these risks could result in (i) damage to and destruction of our facilities; (ii) damage to and destruction of property, natural resources and equipment; (iii) injury or loss of life; (iv) business interruptions while damaged energy infrastructure is repaired or replaced; (v) pollution and other environmental damage; (vi) regulatory investigations and penalties; and (vii) repair and remediation costs. Any of these results could cause us to suffer substantial losses.
While we maintain insurance against some of these risks in amounts that we believe are reasonable, our insurance coverages have material deductibles, self-insurance levels and limits on our maximum recovery and do not cover all risks. For example, from time to time, we may not carry, or may be unable to obtain, on terms that we find acceptable and/or reasonable, insurance coverage for certain exposures, including, but not limited to certain environmental exposures (including potential environmental fines and penalties), business interruption and named windstorm/hurricane exposures and, in limited circumstances, certain political risk exposures. The premiums and deductibles we pay for certain insurance policies are also subject to the risk of substantial increases over time that could negatively impact our financial results. In addition, we may not be able to renew existing insurance policies or procure desirable insurance on commercially reasonable terms. There is also a risk that our insurers may default on their insurance coverage obligations or that amounts for which we are insured, or that the proceeds of such insurance, will not compensate us fully for our losses. Any of these outcomes could have a material adverse effect on our business, results of operations and financial condition.
Some of our operations are subject to joint ventures or operations by third parties, which could negatively impact our control over these operations and have a material adverse effect on our business, results of operations, financial condition and prospects.
A small portion of our operations and interests are operated by third-party working interest owners.  In such cases, (i) we have limited ability to influence or control the day-to-day operation of such properties, including compliance with environmental, safety and other regulations, (ii) we cannot control the amount of capital expenditures that we are required to fund with respect to properties, (iii) we are dependent on third parties to fund their required share of capital expenditures and (iv) we may have restrictions or limitations on our ability to sell our interests in these jointly owned assets.
The insolvency, failure to perform and/or breach its obligations by an operator of our properties could reduce our production and revenue and result in our liability to governmental authorities for compliance with environmental, safety and other regulatory requirements, to the operator's suppliers and vendors and to royalty owners under oil and gas leases jointly owned with the operator or another insolvent owner. As a result, the success and timing of our drilling and development activities on properties operated by others and the economic results derived therefrom depends upon a number of factors outside of our control, including the operator’s timing and amount of capital expenditures, expertise and financial resources, inclusion of other participants in drilling wells and use of technology. Finally, an operator of our properties may have the right, if another non-operator fails to pay its share of costs, to require us to pay our proportionate share of the defaulting party's share of costs.
We currently sell most of our oil production to a limited number of significant purchasers. The loss of one or more of these purchasers, if not replaced, could reduce our revenues and have a material adverse effect on our financial condition or results of operations.
For the year ended December 31, 2019, nine purchasers accounted for approximately 89% of our oil revenues. We depend upon a limited number of significant purchasers for the sale of most of our production. The loss of any of these customers, should we be unable to replace them, could adversely affect our revenues and have a material adverse effect on our financial condition and results of operations. We cannot assure you that any of our customers will continue to do business with us or that we will continue to have access to suitably liquid markets for our future production.
We are subject to a complex set of laws and regulations that regulate the energy industry for which we have to incur substantial compliance and remediation costs.
Our operations, and the energy industry in general, are subject to a complex set of federal, state and local laws and regulations over the following activities, among others:
the location of wells;
methods of drilling and completing wells;
allowable production from wells;
unitization or pooling of oil and gas properties;
spill prevention plans;

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limitations on venting or flaring of natural gas;
disposal of fluids used and wastes generated in connection with operations;
access to, and surface use and restoration of, well properties;
plugging and abandoning of wells, even if we no longer own and/or operate such wells;
air quality and emissions, noise levels and related permits;
gathering, transportation and marketing of oil and natural gas (including NGLs);
taxation;
protection of threatened or endangered species;
operations conducted on lands lying within wilderness, wetlands, and ecologicially or seismically sensitive areas;
competitive bidding rules on federal and state lands; and
the sourcing and supply of materials needed to operate.
Generally, the regulations have become more stringent and have imposed more limitations on our operations and, as a result, have caused us to incur more costs to comply. Many required approvals are subject to considerable discretion by the regulatory agencies with respect to the timing and scope of approvals and permits issued. If permits are not issued, or if unfavorable restrictions or conditions are imposed on our drilling activities, we may not be able to conduct our operations as planned or at all. Delays in obtaining regulatory approvals or permits, the failure to obtain a drilling permit for a well, or the receipt of a permit with excessive conditions or costs could have a material negative impact on our operations and financial results. We may also incur substantial costs in order to maintain compliance with these existing laws and regulations, including costs to comply with new and more extensive reporting and disclosure requirements. Failure to comply with such requirements may result in the suspension or termination of operations, may subject us to criminal as well as civil and administrative penalties, and may expose us to fines and penalties. In addition, our costs of compliance may increase if existing laws and regulations are revised or reinterpreted, or if new laws and regulations become applicable to our operations. Such costs could have a material adverse effect on our business, financial condition and results of operations.
Also, some of our assets are located and operate on federal, state, local or tribal lands and are typically regulated by one or more federal, state or local agencies. For example, we have drilling and production operations that are located on federal lands, which are regulated by the DOI, particularly by the Bureau of Land Management (“BLM”). We also have operations on Native American tribal lands, which are regulated by the DOI, particularly by the Bureau of Indian Affairs (“BIA”), as well as local tribal authorities. Operations on these properties are often subject to additional regulations and compliance obligations, which can delay our access to such lands and impose additional compliance costs. There are also various laws and regulations that regulate various market practices in the industry, including antitrust laws and laws that prohibit fraud and manipulation in the markets in which we operate. The authority of the Federal Trade Commission and the CFTC to impose penalties for violations of laws or regulations has generally increased over the last few years.
We are exposed to the credit risk of our counterparties, contractors and suppliers.
We have significant credit exposure related to our sales of physical commodities, payments to contractors and suppliers, hedging activities and to the non-operating working interest owners who are counterparties to our operating agreements.  If our counterparties become insolvent or otherwise fail to make payments/or perform within the time required under our contracts, our results of operations and financial condition could be materially adversely affected.  Although we maintain strict credit policies and procedures and credit insurance in some cases, they may not be adequate to fully eliminate the credit risk associated with our counterparties, contractors and suppliers.
We are exposed to the performance risk of our key contractors and suppliers.
We rely on contractors for certain construction, drilling and completion operations and we rely on suppliers for key materials, supplies and services, including steel mills, pipe and tubular manufacturers and oil field service providers. We also rely upon the services of other third parties to explore or analyze our prospects to determine a method in which the prospects may be developed in a cost-effective manner. There is a risk that such contractors and suppliers may experience credit and performance issues triggered by a sustained low or a volatile commodity price environment that could adversely impact their ability to perform their contractual obligations with us, including their performance and warranty obligations. This could result

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in delays or defaults in performing such contractual obligations and increased costs to seek replacement contractors, each of which could negatively impact us. We could also be exposed to liability that we would otherwise be indemnified for by these counterparties should they become insolvent or are otherwise unable to satisfy their obligations under their indemnities.
Our strategy involves drilling in shale plays using some of the latest available horizontal drilling and completion techniques, the results of which are subject to drilling and completion technique risks, and drilling results may not meet our expectations for reserves or production.
Our operations involve utilizing the latest horizontal drilling and completion techniques in order to maximize cumulative recoveries and therefore optimize our returns. Drilling risks that we face include, but are not limited to, landing our well bore in the desired drilling zone, staying in the desired drilling zone while drilling horizontally through the formation, running our casing the entire length of the well bore and being able to run tools and other equipment consistently through the horizontal well bore. Risks that we face while completing our wells include, but are not limited to, being able to fracture stimulate the planned number of stages, being able to run tools the entire length of the well bore during completion operations and successfully cleaning out the well bore after completion of the final fracture stimulation stage.
Ultimately, the success of these drilling and completion techniques can only be evaluated over time as more wells are drilled and production profiles are established over a sufficiently longer period. If our drilling results are less than anticipated, the return on our investment for a particular project may not be as attractive as we anticipated and we could incur material write-downs of unevaluated properties and the value of our undeveloped acreage could decline in the future.
New technologies may cause our current exploration and drilling methods to become obsolete.
The oil and natural gas industry is subject to rapid and significant advancements in technology, resulting in new products and services. As competitors use or develop new technologies, we may be placed at a competitive disadvantage, and competitive pressures may force us to implement new technologies at a substantial cost. In addition, competitors may have greater financial, technical and personnel resources that may allow them now or in the future to enjoy technological advantages before we can. One or more of the technologies that we currently use or that we may implement in the future may become obsolete. We cannot be certain that we will be able to implement technologies on a timely basis or at a cost that is acceptable to us. If we are unable to maintain technological advancements consistent with industry standards, our business, results of operations and financial condition may be materially adversely affected.
Our business depends on access to oil, natural gas and NGLs processing, gathering and transportation systems and facilities.
The marketability of our oil, natural gas and NGLs production depends in large part on the operation, availability, proximity, capacity and expansion of processing, gathering and transportation facilities owned by third parties. We can provide no assurance that sufficient processing, gathering and/or transportation capacity will exist or that we will be able to obtain sufficient processing, gathering and/or transportation capacity on economic terms. A lack of available capacity on processing, gathering and transportation facilities or delays in their planned expansions could result in the shut-in of producing wells or the delay or discontinuance of drilling plans for properties. A lack of availability of these facilities for an extended period of time could negatively impact our revenues. In addition, we have entered into contracts for firm transportation and any failure to renew those contracts on the same or better commercial terms could increase our costs and our exposure to the risks described above.
Our operations are substantially dependent on the availability of water. Restrictions on our ability to obtain water may have an adverse effect on our financial condition, results of operations and cash flows.
Water currently is an essential component of deep shale oil and natural gas production during both the drilling and hydraulic fracturing processes. Historically, we have been able to purchase water from local land owners for use in our operations. In times of drought, we may be subject to local or state restrictions on the amount of water we procure to help protect local water supply. If we are unable to obtain water to use in our operations from local sources, we may be unable to economically produce our reserves, which could have an adverse effect on our financial condition, results of operations and cash flows.
We may face unanticipated water and other waste disposal costs.
We may be subject to regulation that restricts our ability to discharge water produced as part of our operations. Productive zones frequently contain water that must be removed in order for the oil and natural gas to produce, and our ability to remove and dispose of sufficient quantities of water from the various zones will determine whether we can produce oil and natural gas in commercial quantities. The produced water must be transported from the lease and injected into disposal wells.

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The availability of disposal wells with sufficient capacity to receive all of the water produced from our oil and natural gas wells may affect our ability to produce our oil and natural gas wells. Also, the cost to transport and dispose of that water, including the cost of complying with regulations concerning water disposal, may reduce our profitability.
Where water produced from our projects fails to meet the quality requirements of applicable regulatory agencies, our wells produce water in excess of the applicable volumetric permit limits, the disposal wells fail to meet the requirements of all applicable regulatory agencies, or we are unable to secure access to disposal wells with sufficient capacity to accept all of the produced water, we may have to shut in wells, reduce drilling activities, or upgrade facilities for water handling or treatment. The costs to dispose of this produced water may increase if any of the following occur:
we cannot obtain future permits from applicable regulatory agencies;
water of lesser quality or requiring additional treatment is produced;
our wells produce excess water;
new laws and regulations require water to be disposed in a different manner; or
costs to transport the produced water to the disposal wells increase.
If commodity prices decrease and/or development capital is significantly reduced, we may be required to take write-downs of the carrying values of our properties, which could result in a material adverse effect on our results of operations and financial condition.
Accounting rules require that we review periodically the carrying value of our oil and natural gas properties for impairment. Under the successful efforts method of accounting, we review our oil and natural gas properties upon a triggering event (such as a significant and sustained decline in forward commodity prices or a significant change in current and anticipated allocated capital) to determine if impairment of such properties is necessary. Significant undeveloped leasehold costs are assessed for impairment at a lease level or resource play level based on our current exploration plans, while leasehold acquisition costs associated with prospective areas that have limited or no previous exploratory drilling are generally assessed for impairment by major prospect area. Proved oil and natural gas property values are reviewed when circumstances suggest the need for such a review and may occur if actual discoveries in a field are lower than anticipated reserves, reservoirs produce below original estimates, capital allocated for development is significantly reduced, and/or if commodity prices fall to a level that significantly affects anticipated future cash flows on the property. If required, the proved properties are written down to their estimated fair market value based on proved reserves and other market factors. These impairment charges could have a material adverse effect on our results of operations and financial condition for the periods in which such charges are taken.
For example, we incurred non-cash impairment charges of approximately $458 million on our proved properties in NEU in the third quarter of 2019. In the fourth quarter of 2018, we incurred non-cash impairment charges of approximately $1,044 million and $59 million on our proved and unproved properties, respectively in the Permian basin. In addition to the impairment charges recorded in the third quarter of 2019 and fourth quarter of 2018, the continuation of current depressed commodity prices and future commodity price declines may cause changes to our capital spending levels, production rates, levels of proved reserves and development plans, which may result in a further impairment of the carrying value of our proved properties in the future. See Part II, Item 8. “Financial Statements and Supplementary Data”, Note 3, for further information.
Our operations are subject to governmental laws and regulations relating to environmental matters, which may expose us to significant costs and liabilities and/or significant delays that could exceed current expectations.
Our business is subject to environmental laws and regulations. These regulations include compliance obligations for air emissions, water quality, wastewater discharge and solid and hazardous waste disposal, spill prevention, control and countermeasures, as well as regulations designed for the protection of threatened or endangered species. Accordingly, there is inherent risk of incurring significant environmental liabilities due to these matters as a result of historical industry operations and waste disposal practices by us or third parties not under our control. Additionally, these proposed and/or implemented regulations could materially impact the costs of exploration and production operations and cause substantial delays in the receipt of regulatory approvals from both an environmental and safety perspective. It is possible that more stringent regulations might be enacted or delays in receiving permits may occur in other areas, including drilling operations on other federal or state lands.
In the course of our exploration and production operations, we and/or other owners and operators of these facilities may have generated or disposed of wastes that polluted the soil, surface water or groundwater at our facilities and adjacent properties. As such, we could be subject to claims for personal injury and/or natural resource and property damage (including site clean-up and restoration costs) related to the environmental, health or safety impacts of our oil and natural gas production

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activities, and we have been from time to time, and currently are, named as a defendant in litigation related to such matters. Under certain laws, we also could be subject to strict liability (i.e., no showing of “fault” is required) that, in some circumstances, may be joint and several for the costs of removing or remediating contamination regardless of whether such contamination was the result of our activities, even if the operations were in compliance with all applicable laws at the time the contamination occurred and even if we no longer own and/or operate on the properties. We may also be subject to litigation from private parties (e.g. property owners, facility owners) who may pursue legal actions to enforce compliance, as well as to seek damages for non-compliance with environmental laws and regulations or for personal injury or property damage. While to date none of these remediation obligations or claims have involved costs that have materially and adversely affected our business, we cannot predict with certainty whether future costs of newly discovered or new contamination might result in a materially adverse impact on our business or operations.
Legislation and regulatory initiatives intended to address pipeline safety could increase our operating costs.
Some pipelines are subject to construction, installation, operation and safety regulation by the U.S. Department of Transportation (“DOT”), and/or various other federal, state and local agencies. Congress has enacted several pipeline safety acts over the years. Currently, the Pipeline and Hazardous Materials Safety Administration (“PHMSA”) under DOT administers pipeline safety requirements for natural gas and hazardous liquid pipelines. These regulations, among other things, address pipeline integrity management and pipeline operator qualification rules. In June 2016, Congress approved new pipeline safety legislation, the “Protecting Our Infrastructure of Pipelines and Enhancing Safety Act of 2016” (the “PIPES Act”), which provides the PHMSA with additional authority to address imminent hazards by imposing emergency restrictions, prohibitions, and safety measures on owners and operators of gas or hazardous liquids pipeline facilities. Significant expenses could be incurred in the future if additional safety measures are required or if safety standards are raised and exceed the current pipeline control system capabilities.
Recently, the PHMSA has proposed additional regulations for gas pipeline safety. For example, in March 2016, the PHMSA proposed a rule that would expand integrity management requirements beyond High Consequence Areas to gas pipelines in newly defined Moderate Consequence Areas. The public comment period closed in July 2016. Also, in January 2017, the PHMSA released an advance copy of its final rules to expand its safety regulations for hazardous liquid pipelines by, among other things, expanding the required use of leak detection systems, requiring more frequent testing for corrosion and other flaws, and requiring companies to inspect pipelines in areas affected by extreme weather or natural disasters. The final rule was withdrawn by the PHMSA in January 2017, and it is unclear whether and to what extend the PHMSA will move forward with its regulatory reforms.

Regulation relating to climate change and energy conservation could result in increased operating costs and reduced demand for oil and natural gas we produce.
In recent years, federal, state and local governments have taken steps to reduce emissions of greenhouse gases (“GHGs”). The EPA has finalized a series of GHG monitoring, reporting and emission control rules for the oil and natural gas industry, and the U.S. Congress has, from time to time, considered adopting legislation to reduce emissions. Almost one-half of the states have already taken measures to reduce emissions of GHGs primarily through the development of GHG emission inventories and/or regional GHG cap-and-trade programs.
Additionally on November 15, 2016, the BLM finalized a waste prevention rule for oil and gas facilities on onshore federal and Indian leases to prohibit venting, limit flaring, require leak detection, and allow adjustment of royalty rates for new leases. The rule went into effect in January 2017 and could have required installation of tank vapor controls at certain existing well sites in the NEU area at a then-estimated cost of approximately $5 million. However, on September 28, 2018, the BLM published final amendments to the waste prevention rule that eliminated certain air quality provisions, including those that would require us to install tank vapor controls. Litigation filed by state and environmental groups to challenge the amended final rule is on-going at this time.
At the international level, 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 text of the resulting Paris Agreement calls for nations to undertake “ambitious efforts” to “hold the increase in global average temperatures to well below 2 ºC above preindustrial levels and pursue efforts to limit the temperature increase to 1.5 ºC above pre-industrial levels;” reach global peaking of GHG emissions as soon as possible; and take action to conserve and enhance sinks and reservoirs of GHGs, among other requirements. The Paris Agreement went into effect in November 2016. However, in June 2017, the President announced that the United States would withdraw from the Paris Agreement, and began negotiations to either re-enter or negotiate an entirely new agreement with more favorable terms for the United States. The Paris Agreement sets forth a specific exit process, whereby a party may not provide notice of its withdrawal until three years from the effective date, with such withdrawal taking

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effect one year from such notice. It is not clear what steps the Presidential 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. Furthermore, in response to the announcement, many state and local leaders have stated their intent to intensify efforts to uphold the commitments set forth in the international accord.
Regulation of GHG emissions could result in reduced demand for our products, as oil and natural gas consumers seek to reduce their own GHG emissions. As our operations also emit GHGs directly, current and future laws or regulations limiting such emissions could increase our own costs. Any regulation of GHG emissions, including through a cap-and-trade system, technology mandate, emissions tax, reporting requirement or other program, could have a material adverse effect on our business, results of operations and financial condition.
Further, there have been various legislative and regulatory proposals at the federal and state levels to provide incentives and subsidies to (i) shift more power generation to renewable energy sources and (ii) support technological advances to drive less energy consumption. These incentives and subsidies could have a negative impact on oil, natural gas and NGLs consumption. In addition, there have also been efforts in recent years to influence the investment community, including investment advisors and certain sovereign wealth, pension and endowment funds promoting divestment of fossil fuel equities and pressuring lenders to limit funding to companies engaged in the extraction of fossil fuel reserves. Such environmental activism and initiatives aimed at limiting climate change and reducing air pollution could interfere with our business activities, operations and ability to access capital. Furthermore, claims have been made against certain energy companies alleging that GHG emissions from oil and natural gas operations constitute a public nuisance under federal and/or state common law. As a result, private individuals or public entities may seek to enforce environmental laws and regulations against us and could allege personal injury, property damages, or other liabilities. While our business is not a party to any such litigation, we could be named in actions making similar allegations. An unfavorable ruling in any such case could significantly impact our operations and could have an adverse impact on our financial condition.
In addition, to the extent climate change results in more severe weather and significant physical effects, such as increased frequency and severity of storms, floods, droughts and other climatic effects, our own, our counterparties’ or our customers’ operations may be disrupted, which could result in a decrease in our available products or reduce our customers’ demand for our products.
Any of the above risks could impair our ability to manage our business and have a material adverse effect on our operations, cash flows and financial position.
Our operations could result in an equipment malfunction or oil spill that could expose us to significant liability.
Despite the existence of various procedures and plans, there is a risk that we could experience well control problems in our operations. As a result, we could be exposed to regulatory fines and penalties, as well as landowner lawsuits resulting from any spills or leaks that might occur. Any of these outcomes could have a material adverse effect on our business, results of operations and financial condition to the extent we are not fully covered by our insurance, which we maintain against some of these risks in amounts that we believe are reasonable, as described above.
Although we might also have remedies against our contractors or vendors or our joint working interest owners with regard to any losses associated with unintended spills or leaks, the ability to recover from such parties will depend on the indemnity provisions in our contracts as well as the facts and circumstances associated with the causes of such spills or leaks. As a result, our ability to recover associated costs from insurance coverages or other third parties is uncertain.
Legislation and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays.
We use hydraulic fracturing extensively in our operations. The hydraulic fracturing process is typically regulated by state oil and natural gas commissions. Hydraulic fracturing involves the injection of water, sand and chemicals under pressure into formations to fracture the surrounding rock and stimulate production. The Safe Drinking Water Act (“SDWA”) regulates the underground injection of substances through the Underground Injection Control (“UIC”) program. While hydraulic fracturing generally is exempt from regulation under the UIC program, Congress has in recent legislative sessions considered legislation to amend the SDWA, including legislation that would repeal the exemption for hydraulic fracturing from the definition of “underground injection” and require federal permitting and regulatory control of hydraulic fracturing, as well as legislative proposals to require disclosure of the chemical constituents of the fluids used in the fracturing process. In addition, the EPA has taken the position that hydraulic fracturing with fluids containing diesel fuel is subject to regulation under the UIC program as “Class II” UIC wells. Also, in June 2016, EPA published a final rule prohibiting the discharge of wastewater from onshore unconventional oil and gas extraction facilities to publicly owned wastewater treatment plants. The EPA is also conducting a study of private wastewater treatment facilities (also known as centralized waste treatment, or CWT, facilities)

22


accepting oil and gas extraction wastewater. The EPA is collecting data and information related to the extent to which CWT facilities accept such wastewater, available treatment technologies (and their associated costs), discharge characteristics, financial characteristics of CWT facilities, and the environmental impacts of discharges from CWT facilities.
In August 2012, the EPA published final regulations under the Clean Air Act (“CAA”) that establish new air emission controls for oil and natural gas production and natural gas processing operations. Specifically, the EPA promulgated New Source Performance Standards establishing emission limits for sulfur dioxide (SO2) and volatile organic compounds (“VOCs”). The final rules require a 95% reduction in VOCs emitted by mandating the use of reduced emission completions or “green completions” on all hydraulically-fractured gas wells constructed or refractured after January 1, 2015. Until this date, emissions from fractured and refractured gas wells were to be reduced through reduced emission completions or combustion devices. The rules also establish new requirements regarding emissions from compressors, controllers, dehydrators, storage tanks and other production equipment. In response to numerous requests for reconsideration and litigation challenging these rules from both industry and the environmental community, the EPA has issued, and will likely continue to issue, revised rules responsive to some of the requests for reconsideration. In particular, in May 2016, the EPA amended its regulations to impose new standards for methane and VOC emissions for certain new, modified, and reconstructed equipment, processes, and activities across the oil and natural gas sector. However, in a March 28, 2017 executive order, the President directed the EPA to review the 2016 regulations and, if appropriate, to initiate a rulemaking to rescind or revise them consistent with the stated policy of promoting clean and safe development of the nation’s energy resources, while at the same time avoiding regulatory burdens that unnecessarily encumber energy production. In June 2017, the EPA published a proposed rule to stay for two years certain requirements of the 2016 regulations, including fugitive emission requirements. Also, in October 2018, the EPA published a proposed rule to significantly reduce regulatory burdens imposed by the 2016 regulations, including, for example, reducing the monitoring frequency for fugitive emissions and revising the requirements for pneumatic pumps at well sites. The above standards, to the extent implemented, as well as any future laws and their implementing regulations, may require us to obtain pre-approval for the expansion or modification of existing facilities or the construction of new facilities expected to produce air emissions, impose stringent air permit requirements, or mandate the use of specific equipment or technologies to control emissions.
In March 2015, the BLM published a final rule governing hydraulic fracturing on federal and Indian lands. The rule requires public disclosure of chemicals used in hydraulic fracturing, implementation of a casing and cementing program, management of recovered fluids, and submission to the BLM of detailed information about the proposed operation, including wellbore geology, the location of faults and fractures, and the depths of all usable water. On March 28, 2017, the President signed an executive order directing the BLM to review the rule and, if appropriate, to initiate a rulemaking to rescind or revise it. In December 2017, the BLM published a final rule to rescind the 2015 hydraulic fracturing rule; however, a coalition of environmentalists, tribal advocates and the state of California filed lawsuits challenging the rule rescission. At this time, it is uncertain when, or if, the rules will be implemented, and what impact they would have on our operations.

Furthermore, there are certain governmental reviews either underway or being proposed that focus on environmental aspects of hydraulic fracturing practices. In December 2016, the EPA released a study examining the potential for hydraulic fracturing activities to impact drinking water resources, finding that, under some circumstances, the use of water in hydraulic fracturing activities can impact drinking water resources. Also, in February 2015, the EPA released a report with findings and recommendations related to public concern about induced seismic activity from disposal wells. The report recommends strategies for managing and minimizing the potential for significant injection-induced seismic events. Other governmental agencies, including the U.S. Department of Energy, the U.S. Geological Survey, and the U.S. Government Accountability Office, have evaluated or are evaluating various other aspects of hydraulic fracturing. These studies, when final and depending on their results, could spur initiatives to regulate hydraulic fracturing under the SDWA or otherwise.
Several states and local jurisdictions in which we operate have adopted, or are considering adopting, regulations that could restrict or prohibit hydraulic fracturing in certain circumstances, impose more stringent operating standards and/or require the disclosure of the composition of hydraulic fracturing fluids. For example, Texas enacted a law requiring oil and natural gas operators to publicly disclose the chemicals used in the hydraulic fracturing process, effective as of September 1, 2011. The Texas Railroad Commission adopted rules and regulations applicable to all wells for which the Texas Railroad Commission issues an initial drilling permit on or after February 1, 2012. The regulations require that well operators disclose the list of chemical ingredients subject to the requirements of the Occupational Safety and Health Administration (OSHA) for disclosure on an internet website and also file the list of chemicals with the Texas Railroad Commission with the well completion report. The total volume of water used to hydraulically fracture a well must also be disclosed to the public and filed with the Texas Railroad Commission. Furthermore, in May 2013, the Texas Railroad Commission issued an updated “well integrity rule,” addressing requirements for drilling, casing and cementing wells, which took effect in January 2014. In addition, Utah’s Division of Oil, Gas and Mining passed a rule in October 2012 requiring all oil and gas operators to disclose the amount and type of chemicals used in hydraulic fracturing operations using the national registry FracFocus.org.

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A number of lawsuits and enforcement actions have been initiated across the country alleging that hydraulic fracturing practices have induced seismic activity and adversely impacted drinking water supplies, use of surface water, and the environment generally. If new laws or regulations that significantly restrict hydraulic fracturing, such as amendments to the SDWA, are adopted, such laws could make it more difficult or costly for us to perform fracturing to stimulate production from tight formations as well as make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings based on allegations that specific chemicals used in the fracturing process could adversely affect groundwater. In addition, if hydraulic fracturing is further regulated at the federal or state level, our fracturing activities could become subject to additional permitting and financial assurance requirements, more stringent construction specifications, increased monitoring, reporting and recordkeeping obligations, plugging and abandonment requirements and also to attendant permitting delays and potential increases in costs. Such changes could cause us to incur substantial compliance costs, and compliance or the consequences of any failure to comply by us could have a material adverse effect on our financial condition and results of operations. Until such laws are finalized and implemented, it is not possible to estimate their impact on our business. At this time, no adopted laws or regulations have imposed a material impact on our hydraulic fracturing operations.
Any of the above risks could impair our ability to manage our business and have a material adverse effect on our operations, cash flows and financial position.
Legislation or regulatory initiatives intended to address seismic activity could restrict our drilling and production activities, as well as our ability to dispose of produced water gathered from such activities, which could have a material adverse effect on our business.
State and federal regulatory agencies have recently focused on a possible connection between hydraulic fracturing related activities, particularly the underground injection of wastewater into disposal wells, and the increased occurrence of seismic activity, and regulatory agencies at all levels are continuing to study the possible linkage between oil and gas activity and induced seismicity. In addition, a number of lawsuits have been filed in some states, alleging that disposal well operations have caused damage to neighboring properties or otherwise violated state and federal rules regulating waste disposal. In response to these concerns, regulators in some states are seeking to impose additional requirements, including requirements regarding the permitting of produced water disposal wells or otherwise to assess the relationship between seismicity and the use of such wells. For example, in October 2014, the Texas Railroad Commission adopted disposal well rule amendments designed to among other things, require applicants for new disposal wells that will receive non-hazardous produced water or other oil and gas waste to conduct seismic activity searches utilizing the U.S. Geological Survey. The searches are intended to determine the potential for earthquakes within a circular area of 100 square miles around a proposed new disposal well. If the permittee or an applicant of a disposal well permit fails to demonstrate that the produced water or other fluids are confined to the disposal zone or if scientific data indicates such a disposal well is likely to be or determined to be contributing to seismic activity, then the agency may deny, modify, suspend or terminate the permit application or existing operating permit for that well. The Commission has used this authority to deny permits for waste disposal wells.
Tax laws and regulations may change over time, including the elimination of federal income tax deductions currently available with respect to oil and gas exploration and development.
Tax laws and regulations are highly complex and subject to interpretation, and the tax laws and regulations to which we are subject may change over time. Our tax filings are based upon our interpretation of the tax laws in effect in various jurisdictions at the time that the filings were made. If these laws or regulations change, or if the taxing authorities do not agree with our interpretation of the effects of such laws and regulations, it could have a material adverse effect on our business and financial condition.
For example, on December 22, 2017, the President signed into law Public Law No. 115-97, a comprehensive tax reform bill commonly referred to as the Tax Cuts and Jobs Act (the Act) that significantly reformed the Internal Revenue Code of 1986, as amended (the Code). Among other changes, the Act (i) permanently reduced the U.S. corporate income tax rate, (ii) repealed the corporate alternative minimum tax, (iii) eliminated the deduction for certain domestic production activities, (iv) imposed new limitations on the utilization of net operating losses generated after 2017, and (v) provided for more general changes to the taxation of corporations, including changes to cost recovery rules and to the deductibility of interest expense, which may impact the taxation of oil and gas companies. The passage of the Act had no effect on our financial statements; however, in past years, legislation has been proposed that, if enacted into law, would make significant changes to U.S. federal and state income tax laws, including:
the repeal of the percentage depletion allowance for oil and gas properties;
the elimination of current expensing of intangible drilling and development costs; and
an extension of the amortization period for certain geological and geophysical expenditures.

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While these specific changes are not included in the Act, no accurate prediction can be made as to whether any such legislative changes will be proposed or enacted in the future or, if enacted, what the specific provisions or the effective date of any such legislation would be. The elimination of such U.S. federal tax deductions, as well as any other changes to or the imposition of new federal, state, local or non-U.S. taxes (including the imposition of, or increases in production, severance or similar taxes) could have a material adverse effect on our business, results of operations and financial condition.
Our debt agreements contain restrictions that limit our flexibility in operating our business.
Our existing debt agreements contain, and the debt agreements that we expect to be in effect upon emergence from the Chapter 11 cases will contain, and any other existing or future indebtedness of ours would likely contain, a number of covenants that impose operating and financial restrictions on us, including restrictions on our and our subsidiaries ability to, among other things:
incur additional debt, guarantee indebtedness or issue certain preferred shares;
pay dividends on or make distributions in respect of, or repurchase or redeem, our capital stock or make other restricted payments;
prepay, redeem or repurchase certain debt;
make loans or certain investments;
sell certain assets;
create liens on certain assets;
consolidate, merge, sell or otherwise dispose of all or substantially all of our assets;
enter into certain transactions with our affiliates;
alter the businesses we conduct;
enter into agreements restricting our subsidiaries’ ability to pay dividends; and
designate our subsidiaries as unrestricted subsidiaries.
In addition, the availability of borrowings under the DIP Facility and Exit Facility is subject to various financial and non-financial covenants and restrictions.
As a result of these covenants, we may be limited in the manner in which we conduct our business, and we may be unable to engage in favorable business activities or finance future operations or capital needs.
A failure to comply with the covenants under these facilities or any of our other indebtedness could result in an event of default, which, if not cured or waived, could have a material adverse effect on our business, financial condition and results of operations. In the event of any such default, the lenders thereunder:
will not be required to lend any additional amounts to us;
could elect to declare all borrowings outstanding, together with accrued and unpaid interest and fees, to be due and payable and terminate all commitments to extend further credit; or
could require us to apply all of our available cash to repay these borrowings.
Such actions by the lenders could cause cross defaults under our other indebtedness. If we were unable to repay those amounts, the lenders or holders under these facilities and our other secured indebtedness could proceed against the collateral granted to them to secure that indebtedness and we could be forced into bankruptcy or liquidation. We pledge a substantial portion of our assets as collateral under our credit facilities, our senior secured term loans and our secured notes.
Our business could be negatively impacted by security threats, including cyber-security threats and other disruptions of electronic and information technology systems.
As an oil and natural gas exploration and production company, we use computers and information technology systems to conduct our exploration, development and production activities, and they have become an integral part of our business. We use these systems to analyze and store financial and operating data and to communicate within our company and with outside business partners. We are subject to various security attacks and threats, including attempts to gain unauthorized access to

25


sensitive information or to render data or systems unusable, threats to the safety of our employees, threats to the security of our facilities and infrastructure or third-party facilities and infrastructure, such as processing plants and pipelines, and threats from terrorist acts. Cyber-security attacks on businesses have escalated in recent years and are becoming more sophisticated. These attacks may be perpetrated by third parties or insiders. A cyber-security attack, or failure of any of our computer or electronic programs or systems resulting in erroneous information in our hardware or software network infrastructure, could lead to disruptions in critical systems, unauthorized release of confidential or otherwise protected information and/or corruption of data, loss of communication links, inability to find, produce, process and sell oil, natural gas and NGLs, and inability to automatically process commercial transactions or engage in similar automated or computerized business activities. For example, unauthorized access to seismic data, reserves information, strategic information, or other sensitive or proprietary information could lead to data corruption, communication interruption, or other disruption to our operations and could have a negative impact on our ability to compete for oil and natural gas resources. Although we utilize various procedures and controls to monitor and protect against these threats, as well as to mitigate our exposure to such threats, there can be no assurance that these procedures and controls will be sufficient to prevent cyber-security breaches, and we cannot eliminate the risk of human error or employee or vendor malfeasance. Certain cyber-security incidents, such as surveillance, may remain undetected for an extended period. A cyber-security breach or failure could have a material adverse effect on our business, reputation, financial position, results of operations or cash flows.

In addition, a cyber-security attack directed at oil and gas distribution systems, which are necessary to transport and market our production and many of which are controlled by external technologies, could damage critical distribution and storage assets or the environment, delay or prevent delivery of production to markets, and make it difficult or impossible to accurately account for production and settle transactions. We also have no control over the technology systems of the third parties with whom we do business. Our vendors, midstream providers and other business partners may separately suffer disruptions or cyber-security breaches, which, in turn, could adversely impact our operations and compromise our information. Although we have not suffered material breaches, disruptions or losses related to cyber-security attacks to date, we have experienced and will continue to experience attempts by external parties to penetrate and attack our networks and systems. If we were successfully attacked, we could incur substantial remediation and other costs or suffer other negative consequences, including exposure to potential liability, in addition to the consequences noted above. As cyber-security threats continue to evolve, we may be required to expend additional resources to continue to modify or enhance our protective measures or to investigate or remediate any cyber-security or information technology infrastructure vulnerabilities.

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ITEM 1B.    UNRESOLVED STAFF COMMENTS
None.
ITEM 2.    PROPERTIES
A description of our properties is included in Item 1. “Business”.
ITEM 3.    LEGAL PROCEEDINGS
A description of our material legal proceedings is included in Part II, Item 8. “Financial Statements and Supplementary Data”, Note 8, and is incorporated herein by reference.
For information on the Company’s Chapter 11 Cases, see Item 1. “Business - Reorganization and Chapter 11 Cases” contained herein, which information is incorporated herein by reference.

ITEM 4.    MINE SAFETY DISCLOSURES
Not applicable.

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PART II
ITEM 5.    MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES.
Our equity securities are privately held by our sole member and thus there is no established public trading market for our membership interests.
ITEM 6.    SELECTED FINANCIAL DATA
      Item 6, Selected Financial Data, has been omitted from this report pursuant to the reduced disclosure format permitted by Item 301 of Regulation S-K and Article 8 of Regulation S-X.

ITEM 7.    MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Our Management’s Discussion and Analysis of Financial Condition and Results of Operations (“MD&A”) should be read in conjunction with the financial statements and the accompanying notes presented in Item 8 of this Annual Report on Form 10-K. This discussion contains forward-looking statements and involves numerous risks and uncertainties, including, but not limited to, those described in “Risk Factors”.  Actual results may differ materially from those contained in any forward-looking statements. See “Cautionary Statement Regarding Forward-Looking Statements” in the front of this report. Unless otherwise indicated or the context otherwise requires, references in this MD&A section to “we”, “our”, “us” and “the Company” refer to EP Energy LLC and each of its consolidated subsidiaries.
Our Business
Overview.  We are an independent exploration and production company engaged in the acquisition and development of unconventional onshore oil and natural gas properties in the United States. We operate through a diverse base of producing assets through the development of our drilling inventory located in three areas: the Eagle Ford Shale in South Texas, Northeastern Utah (NEU) in the Uinta basin, and the Permian basin in West Texas. Below are summary descriptions of each of our programs:
Eagle Ford Shale. The Eagle Ford Shale continues to provide the highest economic returns in our oil portfolio. We are currently not running any rigs in this program.
Northeastern Utah.  In NEU, we are gaining operational efficiencies as we develop this oil field. Our acreage in this area is largely held-by-production. We are currently running two rig in this program. 
Permian. In our Permian basin, we are focused on optimizing our drilling, completion and artificial lift systems. We are currently not running any rigs in this program. 
Chapter 11 Cases. On October 3, 2019, we and certain of our direct and indirect subsidiaries filed voluntary petitions in the United States Bankruptcy Court for the Southern District of Texas seeking relief under chapter 11 of title 11 of the United States Code as further described in Part I, Item 1. “Business” and Liquidity and Capital Resources.

Strategy. Our strategy is to invest in opportunities that provide the highest return across our asset base, continually seek out operating and capital efficiencies, effectively manage costs, and identify accretive acquisition opportunities and divestitures, all with the objective of enhancing our portfolio, growing asset value, improving cash flow and increasing financial flexibility. We evaluate opportunities in our portfolio that are aligned with this strategy and our core competencies and that offer a competitive advantage. In addition to opportunities in our current portfolio, strategic acquisitions of leasehold acreage or acquisitions of producing assets allow us to leverage existing expertise in our areas, balance our exposure to regions, basins and commodities, help us to achieve or enhance risk-adjusted returns competitive with those available in our existing programs and increase our reserves. We also continuously evaluate our asset portfolio and will sell oil and natural gas properties if they no longer meet our long-term objectives.
Factors Influencing Our Profitability.  Our profitability is dependent on the prices we receive for our oil and natural gas, the costs to explore, develop, and produce our oil and natural gas, and the volumes we are able to produce, among other factors. Our profitability is and will continue to be influenced primarily by:

growing our proved reserve base and production volumes through the successful execution of our drilling programs or through acquisitions;

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finding and producing oil and natural gas at reasonable costs;
managing operating and capital costs;
managing commodity price risks on our oil and natural gas production; and
managing debt levels and related interest costs.
In addition to these factors, our profitability and performance is affected by volatility in the financial and commodity markets. Commodity price changes may affect our future capital spending levels, production rates and/or related operating revenues (net of any associated royalties), levels of proved reserves and development plans, all of which impact performance and profitability.
Forward commodity prices play a significant role in determining the recoverability of proved property costs on our balance sheet. Future price declines, along with changes to our future capital spending levels, production rates, levels of proved reserves and development plans may result in an impairment of the carrying value of our proved properties in the future, and such charges could be significant.

Derivative Instruments.  Our realized prices from the sale of our oil, natural gas and NGLs are affected by (i) commodity price movements, including locational or basis price differences that exist between the commodity index price (e.g., WTI) and the actual price at which we sell our commodity and (ii) other contractual pricing adjustments contained in our underlying sales contracts.  In order to stabilize cash flows and protect the economic assumptions associated with our capital investment programs, we enter into financial derivative contracts to reduce the financial impact of downward commodity price movements and unfavorable movements in locational prices. Adjustments to our strategy and the decision to enter into new contracts or positions to alter existing contracts or positions are made based on the goals of the overall company. Because we apply mark-to-market accounting on our derivative contracts, our reported results of operations and financial position can be impacted significantly by commodity price movements from period to period.
    
The following table and discussion reflects the contracted volumes and the prices we will receive under derivative contracts we held as of December 31, 2019.
 
2020
 
2021
 
Volumes(1)
 
Average
Price(1)
 
Volumes(1)
 
Average
Price(1)
Oil
 
 
 
 
 
 
 
Fixed Price Swaps
 
 
 
 
 
 
 
WTI
1,849

 
$
55.80

 
90

 
$
55.52

Three Way Collars
 
 
 
 
 
 
 
Ceiling - WTI
11,712

 
$
65.11

 

 
$

Floors - WTI
11,712

 
$
55.90

 

 
$

Sub-Floor - WTI
11,712

 
$
45.00

 

 
$

Basis Swaps
 
 
 
 
 
 
 
Midland vs. Cushing(2)
1,464

 
$
0.46

 

 
$

 
(1)
Volumes presented are MBbls for oil and prices presented are per Bbl of oil.
(2)
EP Energy receives Cushing plus the basis spread listed and pays Midland.

For our three-way collar contracts in the tables above, the sub-floor prices represent the price below which we receive WTI plus a weighted average spread of $10.90 in 2020 on the indicated volumes. If WTI is above our sub-floor prices, we receive the noted floor price until WTI exceeds that floor price. Above the floor price, we receive WTI until prices exceed the noted ceiling price in our three-way collars, at which time we receive the fixed ceiling price. As of December 31, 2019, the average forward price of oil was $58.46 per barrel of oil for 2020 and $54.04 per barrel of oil for 2021.
During 2019, we (i) settled commodity index hedges on approximately 97% of our oil production, 73% of our total liquids production and 61% of our natural gas production at average floor prices of $55.93 per barrel of oil and $2.86 per MMBtu of natural gas, respectively. As of December 31, 2019, approximately 86% of our 2020 future crude oil contracts allow for upside participation (with a weighted average price of approximately $65.11 per barrel for 2020) while containing sub-floor prices (weighted average prices of $45.00 per barrel) that limit the amount of our derivative settlements under these three-way

29


contracts should prices drop below the sub-floor prices. To the extent our oil, natural gas and NGLs production is unhedged, either from a commodity index or locational price perspective, our operating revenues will be impacted from period to period.
For the period from January 1, 2020 through March 20, 2020, we unwound 4,026 MBbls of 2020 WTI oil three-way collars with a ceiling price of $64.97, a floor price of $55.00 and a sub-floor price of $45.00 per barrel of oil and replaced it with 4,148 MBbls of 2020 WTI oil fixed price swaps with an average price of $59.98 per barrel of oil. In addition, we entered into derivative contracts on 90 MBbls of 2021 WTI oil fixed price swaps with an average price of $55.05 per barrel of oil and 900 MBbls of 2021 WTI oil three-way collars with a ceiling price of $60.51, a floor price of $55.00 and a sub-floor price of $45.00 per barrel of oil.
Liquidity and Capital Resources
Overview. As of December 31, 2019, our primary sources of liquidity are cash generated by our operations and borrowings under our debtor-in-possession facility (“DIP Facility”). Our primary uses of cash are capital expenditures, debt service, including interest, and working capital requirements. The following table provides a summary of our total available liquidity as of December 31, 2019:
 
 
Year Ended 
 December 31, 
 2019
 
 
(in millions)
Cash and cash equivalents
 
$
32

Availability under DIP Facility
 
150

    Total available liquidity
 
$
182

    
Chapter 11 Cases. In the second quarter 2019, our Board of Directors appointed a Special Committee which engaged financial and legal advisors to consider a number of potential actions and evaluate certain strategic alternatives to address our liquidity and balance sheet issues. On August 15, 2019, we did not make the approximately $40 million cash interest payment due and payable with respect to the 8.000% Senior Secured Notes due 2025. On September 3, 2019, we did not make the approximately $7 million cash interest payment due and payable with respect to the 7.750% Senior Notes due 2022.

On October 3, 2019, we and certain of our direct and indirect subsidiaries (collectively with the Company, the “Debtors”) filed the Chapter 11 Cases in the United States Bankruptcy Court for the Southern District of Texas seeking relief under chapter 11 of title 11 of the United States Code. To ensure ordinary course operations, the Debtors obtained approval from the Bankruptcy Court for a variety of “first day” motions, including motions to obtain customary relief intended to assure our ability to continue our ordinary course operations after the filing date. In addition, the Debtors received authority to use cash collateral of the lenders under the Reserve-Based Facility (“RBL Facility”).

The commencement of the Chapter 11 Cases constituted an immediate event of default, and caused the automatic and immediate acceleration of all debt outstanding under or in respect of a number of our instruments and agreements relating to our direct financial obligations, including our RBL Facility and indentures governing the 8.000% Senior Secured Notes due 2025, 7.750% Senior Secured Notes due 2026, 8.000% Senior Secured Notes due 2024, 9.375% Senior Secured Notes due 2024, 9.375% Senior Notes due 2020, 7.750% Senior Notes due 2022 and 6.375% Senior Notes due 2023 (collectively, the “Senior Notes”). Any efforts to enforce such payment obligations were automatically stayed as a result of the filing of the Chapter 11 Cases and the creditors’ rights of enforcement in respect of the Senior Notes and the RBL Facility are subject to the applicable provisions of the Bankruptcy Code.

On October 18, 2019, the Debtors entered into the PSA with the Supporting Noteholders to support a restructuring on the terms of a chapter 11 plan described therein (the “Plan”). On October 18, 2019, the Debtors also entered into the BCA with the Supporting Noteholders, pursuant to which the Supporting Noteholders agreed to backstop $463 million (to consist of $325 million in cash and $138 million in exchanged reinstated 1.25L Notes) of the Rights Offering. On March 6, 2020, after a hearing to confirm the Plan, the Bankruptcy Court stated that it would confirm the Plan. On March 12, 2020, pursuant to its ruling on March 6, 2020, the Bankruptcy Court entered an order confirming the Plan (ECF No. 1049).

    On March 18, 2020, the Debtors and the Supporting Noteholders under the PSA and in their capacities as the Commitment Parties under the BCA, mutually agreed to amend and terminate the PSA and the BCA pursuant the terms of a Stipulation of Settlement Regarding Backstop Agreement and Plan Support Agreement (the “Stipulation”). On March 23, 2020, the Bankruptcy Court approved the Stipulation. The Debtors are working with their constituents to explore various alternatives.

30


Debtor-in-Possession Agreement. On November 25, 2019, EPE Acquisition, LLC and EP Energy LLC entered into a Senior Secured Superpriority Debtor-In-Possession Credit Agreement (as amended or modified from time to time, the “DIP Credit Agreement) with JPMorgan Chase Bank, N.A., as administrative agent, collateral agent and an issuing bank and the RBL Lenders which are party thereto as lenders (in such capacity, the “DIP Lenders”). Under the DIP Credit Agreement and the DIP Order, a portion of the RBL Facility was converted into revolving commitments under the DIP Credit Agreement which provides for an approximately $315 million debtor-in-possession senior secured superpriority revolving credit facility (the “DIP Facility”, and the loans thereunder, the “DIP Loans”), and which includes a letter of credit sublimit of $50 million. As of December 31, 2019, we had $150 million capacity remaining with approximately $17 million of letters of credit issued and $148 million outstanding under the DIP Facility. For a further discussion of the additional terms of the DIP Facility, see Part II, Item 8. “Financial Statements and Supplementary Data”, Note 7.

We will use the proceeds of the DIP Facility for, among other things, (i) the acquisition, development and exploration of oil and gas properties, for working capital and general corporate purposes, (ii) the payment of professional fees as provided for in the DIP Order, (iii) the payment of expenses incurred in the administration of the Chapter 11 Cases or as permitted by the certain orders and (iv) payments due thereunder or under the DIP Order. The maturity date of the DIP Facility is the earlier of (a) November 25, 2020, (b) the effective date of an “Acceptable Plan of Reorganization” (as defined in the DIP Credit Agreement), (c) the closing of a sale of substantially all of the equity or assets of EP Energy LLC (unless consummated pursuant to an Acceptable Plan of Reorganization), or (d) the termination of the DIP Facility during the continuation of an event of default thereunder.

On March 12, 2020, EP Energy LLC, EPE Acquisition, LLC, the agent and certain of the lenders under the RBL Facility, the DIP Agent and certain of the DIP Lenders entered into that certain Waiver of Credit Agreements which waived the occurrence of any event of default triggered under the RBL Credit Agreement and the DIP Credit Agreement as a result of a going concern or like qualification or exception to the audited financials for the year ending December 31, 2019.

Exit Facility. The Debtors have received an underwritten commitment from the DIP Lenders to convert their DIP Loans and their remaining claims under the RBL Facility into an approximately $629 million exit senior secured reserve-based revolving credit facility (the “Exit Facility”) subject to certain conditions set forth therein, which will be evidenced by a senior secured revolving credit agreement, by and among EP Energy LLC, as borrower, EPE Acquisition, LLC, as holdings, the lenders party thereto from time to time, and JPMorgan Chase Bank, N.A., as administrative agent, collateral agent and an issuing bank.

Ability to Continue as a Going Concern. The significant risks and uncertainties related to the Company’s liquidity and Chapter 11 Cases described above raise substantial doubt about the Company’s ability to continue as a going concern. Our operations and our ability to develop and execute our business plan are subject to a high degree of risks and uncertainty associated with the Chapter 11 Cases which are dependent upon factors that are outside of the Company’s control, including actions of the Bankruptcy Court and the Company’s creditors. Any plan of reorganization could materially change the amounts and classifications of assets and liabilities reported in the consolidated financial statements.

For a further discussion of all Chapter 11 related matters, see Part II, Item 8. “Financial Statements and Supplementary Data”, Notes 1A, 7 and 8.

31


Overview of Cash Flow Activities. Our cash flows are summarized as follows:
 
Year ended December 31,
 
2019
 
2018
 
(in millions)
Cash Inflows
 

 
 

Operating activities
 

 
 

Net loss
$
(943
)
 
$
(1,003
)
Impairment charges
458

 
1,103

Gain on sale of assets

 
(3
)
Gain on extinguishment/modification of debt
(10
)
 
(73
)
Write-off of debt discount and deferred issue costs
90

 

Reorganization items, net
24

 

Other income adjustments
441

 
537

Change in assets and liabilities
167

 
(150
)
Total cash flow from operations
$
227

 
$
411

 
 
 
 
Investing activities
 
 
 
Proceeds from the sale of assets
$

 
$
192

Cash inflows from investing activities
$

 
$
192

 
 
 
 
Financing activities
 
 
 
Proceeds from issuance of long-term debt
$
923

 
$
2,090

Proceeds from borrowing under DIP Facility
298

 

Contributions from parent

 
9

Cash inflows from financing activities
$
1,221

 
$
2,099

 
 
 
 
Total cash inflows
$
1,448

 
$
2,702

 
 
 
 
Cash Outflows
 
 
 
Investing activities
 
 
 
Cash paid for capital expenditures
$
497

 
$
690

Cash paid for acquisitions
21

 
292

Cash outflows from investing activities
$
518

 
$
982

 
 
 
 
Financing activities
 
 
 
Repayments and repurchases of long-term debt
$
765

 
$
1,654

Repayment of borrowings from DIP Facility
150

 

DIP Facility costs
6

 

Fees/costs on debt exchange

 
62

Other debt issue costs
2

 
22

Other
1

 

Cash outflows from financing activities
$
924

 
$
1,738

 
 
 
 
Total cash outflows
$
1,442

 
$
2,720

 
 
 
 
Net change in cash, cash equivalents and restricted cash
$
6

 
$
(18
)


32


Production Volumes and Drilling Summary
Production Volumes.  Below is a summary of our production volumes for the years ended December 31:
 
2019
 
2018
Equivalent Volumes (MBoe/d)
 

 
 

Eagle Ford Shale
33.7

 
37.1

Northeastern Utah
15.7

 
17.1

Permian
21.5

 
26.5

Total
70.9

 
80.7

 
 
 
 
Oil (MBbls/d)
 
 
 
Eagle Ford Shale
22.2

 
25.0

Northeastern Utah
10.2

 
11.7

Permian
6.2

 
9.1

Total
38.6

 
45.8

 
 
 
 
Natural Gas (MMcf/d)
 
 
 
Eagle Ford Shale(1)
34

 
36

Northeastern Utah
33

 
32

Permian
48

 
55

Total
115

 
123

 
 
 
 
NGLs (MBbls/d)
 
 
 
Eagle Ford Shale
5.8

 
6.1

Northeastern Utah

 

Permian
7.3

 
8.2

Total
13.1

 
14.3

 
(1)
Production volume excludes 8 MMcf/d of reinjected gas volumes used in operations during the year ended December 31, 2019.

Production Summary. For the year ended December 31, 2019 compared to the same period in 2018, (i) Eagle Ford equivalent volumes decreased 3.4 MBoe/d or (approximately 9%) due to fewer wells placed on production in the second half of 2018 through 2019, (ii) NEU equivalent volumes decreased 1.4 MBoe/d or (approximately 8%) due to reduced drilling activity in 2019, and (iii) Permian equivalent volumes decreased 5.0 MBoe/d or (approximately 19%) reflecting the slower pace of development due to a significant reduction in capital allocated to the Permian. In Eagle Ford and Permian, our 2019 production volumes were also negatively impacted by downstream third-party operational issues and constraints and more reinjected gas as compared to the same period in 2018.

Drilling Summary. During 2019, we (i) frac’d (wells fracture stimulated) 54 gross wells in Eagle Ford, all of which came online for a total of 847 net operated wells, and (ii) frac’d 14 gross wells in NEU, 13 of which came online for a total of 345 net operated wells. We did not frac any wells in the Permian during the year ended December 31, 2019, and currently operate 353 net wells in the area. As of December 31, 2019, we also had a total of 41 gross wells in progress, all of which were drilled, but not completed across our programs.


33


Capital Expenditures. Our capital expenditures and average drilling rigs for the twelve months ended December 31, 2019 were:
 
 
Capital
Expenditures(1)
(in millions)
 
Average Drilling
Rigs
Eagle Ford Shale
 
$
368

 
1.8

Northeastern Utah
 
144

 
1.7

Permian
 
5

 

Total
 
$
517

 
3.5

   Acquisition capital
 
$
19

 
 
Total capital expenditures
 
$
536

 
 
 
(1)
Represents accrual-based capital expenditures.




34


Results of Operations
The information below reflects financial results for EP Energy LLC for the years ended December 31, 2019 and 2018.
 
Year ended December 31,
 
2019
 
2018
 
(in millions)
Operating revenues:
 

 
 

Oil
$
790

 
$
1,045

Natural gas
49

 
75

NGLs
62

 
120

Total physical sales
901

 
1,240

Financial derivatives
(81
)
 
84

Total operating revenues
820

 
1,324

Operating expenses:
 

 
 

Oil and natural gas purchases

 
3

Transportation costs
93

 
100

Lease operating expense
138

 
158

General and administrative
123

 
89

Depreciation, depletion and amortization
418

 
507

Gain on sale of assets

 
(3
)
Impairment charges
458

 
1,103

Exploration and other expense
7

 
5

Taxes, other than income taxes
56

 
77

Total operating expenses
1,293

 
2,039

Operating loss
(473
)
 
(715
)
Other income
4

 
4

Gain on extinguishment/modification of debt
10

 
73

Interest expense
(419
)
 
(365
)
Reorganization items, net
(65
)
 

Loss before income taxes
(943
)
 
(1,003
)
Income tax expense

 

Net loss
$
(943
)
 
$
(1,003
)

35


Operating Revenues
The table below provides our operating revenues, volumes and prices per unit for the years ended December 31, 2019 and 2018. We present (i) average realized prices based on physical sales of oil, natural gas and NGLs as well as (ii) average realized prices inclusive of the impacts of financial derivative settlements and premiums which reflect cash received or paid during the respective period.
 
Year ended December 31,
 
2019
 
2018
 
(in millions)
Operating revenues:
 

 
 

Oil
$
790

 
$
1,045

Natural gas
49

 
75

NGLs
62

 
120

Total physical sales
901

 
1,240

Financial derivatives
(81
)
 
84

Total operating revenues
$
820

 
$
1,324

Volumes:
 

 
 

Oil (MBbls)
14,083

 
16,726

Natural gas (MMcf)
42,059

 
44,913

NGLs (MBbls)
4,785

 
5,227

Equivalent volumes (MBoe)
25,878

 
29,439

Total MBoe/d
70.9

 
80.7

 
 
 
 
Prices per unit(1):
 

 
 

Oil
 

 
 

Average realized price on physical sales ($/Bbl)(2) 
$
56.08

 
$
62.34

Average realized price, including financial derivatives ($/Bbl)(2)(3) 
$
56.67

 
$
60.37

Natural gas
 

 
 

Average realized price on physical sales ($/Mcf)(2) 
$
1.16

 
$
1.66

Average realized price, including financial derivatives ($/Mcf)(2)(3) 
$
1.56

 
$
1.96

NGLs
 

 
 

Average realized price on physical sales ($/Bbl)
$
13.02

 
$
22.88

Average realized price, including financial derivatives ($/Bbl)(3) 
$
13.02

 
$
21.79

 
(1)
For the year ended December 31, 2019, there were no oil purchases associated with managing our physical oil sales. Oil prices for the year ended December 31, 2018 reflect operating revenues for oil reduced by $3 million for oil purchases associated with managing our physical sales. Natural gas prices for both the years ended December 31, 2019 and 2018 reflect operating revenues for natural gas reduced by less than $1 million for natural gas purchases associated with managing our physical sales.
(2)
Changes in realized oil and natural gas prices reflect the effects of unhedged locational or basis differentials, unhedged volumes and contractual deductions between the commodity price index and the actual price at which we sold our oil and natural gas.
(3)
The years ended December 31, 2019 and 2018 include approximately $8 million of cash received and $33 million of cash paid, respectively, for the settlement of crude oil derivative contracts. The years ended December 31, 2019 and 2018 include approximately $17 million and $14 million, respectively, of cash received for the settlement of natural gas financial derivatives. The year ended December 31, 2018 includes approximately $6 million of cash paid for the settlement of NGLs derivative contracts. No cash premiums were received or paid for the years ended December 31, 2019 and 2018.




36


Physical sales.  Physical sales represent accrual-based commodity sales transactions with customers. The table below displays the price and volume variances on our physical sales when comparing the years ended December 31, 2019 and 2018.
 
Oil
 
Natural gas
 
NGLs
 
Total
 
(in millions)
December 31, 2018 sales
$
1,045

 
$
75

 
$
120

 
$
1,240

Change due to prices
(90
)
 
(21
)
 
(48
)
 
(159
)
Change due to volumes
(165
)
 
(5
)
 
(10
)
 
(180
)
December 31, 2019 sales
$
790

 
$
49

 
$
62

 
$
901

Oil sales for the year ended December 31, 2019, compared to the year ended December 31, 2018, decreased by $255 million (24%), due primarily to lower oil prices and lower production in all areas reflecting lower capital spending in 2019. In 2019, Eagle Ford, NEU and Permian oil production volumes decreased by 11% (2.8 MBbls/d), 13% (1.5 MBbls/d) and 32% (2.9 MBbls/d), respectively, compared with the year ended December 31, 2018.
Natural gas sales decreased by $26 million (35%) for the year ended December 31, 2019 compared to the year ended December 31, 2018, due primarily to lower natural gas prices and lower production in the Eagle Ford and Permian.
Our oil, natural gas and NGLs are sold at index prices (WTI, Brent, LLS, Henry Hub and Mt. Belvieu) or refiners' posted prices at various delivery points across our producing basins.  Realized prices received (not considering the effects of hedges) are generally less than the stated index price as a result of fixed or variable contractual deductions, differentials from the index to the delivery point, adjustments for time, and/or discounts for quality or grade. 
In the Eagle Ford, our oil is sold at prices tied primarily to benchmark Magellan East Houston crude oil. In NEU, market pricing of our oil is based upon NYMEX based agreements which reflect a locational difference at the wellhead. In the Permian, physical barrels are generally sold at the WTI Midland Index, which trades at a spread to WTI Cushing. Across all regions, natural gas realized pricing is influenced by factors such as excess royalties paid on flared gas and the percentage of proceeds retained under processing contracts, in addition to the normal seasonal supply and demand influences and those factors discussed above. The table below displays the weighted average differentials and deducts on our oil and natural gas sales on an average NYMEX price.
 
 
Year ended December 31,
 
 
2019
 
2018
 
 
Oil
(Bbl)
 
Natural gas
(MMBtu)
 
Oil
(Bbl)
 
Natural gas
(MMBtu)
Differentials and deducts
 
$
(0.97
)
 
$
(1.41
)
 
$
(1.81
)
 
$
(1.32
)
NYMEX
 
$
57.03

 
$
2.63

 
$
64.77

 
$
3.09

Net back realization %
 
98.3
%
 
46.4
%
 
97.2
%
 
57.3
%
The oil realization percentage in the year ended December 31, 2019 was higher as compared to 2018 primarily as a result of the improvement of Magellan East Houston and Midland basis pricing and physical sales contracts relative to lower NYMEX WTI pricing. The lower natural gas realization percentage in the year ended December 31, 2019 was primarily a result of weaker Permian basin natural gas pricing.
NGLs sales decreased by $58 million (48%) for the year ended December 31, 2019 compared with 2018 as a result of lower average realized prices due to lower pricing on all liquid components.
Future growth in our overall oil, natural gas and NGLs sales (including the impact of financial derivatives) will largely be impacted by commodity pricing, our level of hedging, our ability to maintain or grow oil volumes and by the location of our production and the nature of our sales contracts. For further discussion on our derivative instruments, see Our Business and Liquidity and Capital Resources.
Gains or losses on financial derivatives.  We record gains or losses due to changes in the fair value of our derivative contracts based on forward commodity prices relative to the prices in the underlying contracts. We realize such gains or losses when we settle the derivative position.  During the years ended December 31, 2019 and 2018, we recorded a derivative loss of $81 million and a derivative gain of $84 million, respectively.



37


Operating Expenses
The tables below provide our operating expenses, volumes and operating expenses per unit for each of the periods presented:
 
Year ended December 31,
 
2019
 
2018
 
Total
 
Per Unit(1)
 
Total
 
Per Unit(1)
 
(in millions, except per unit costs)
Operating expenses
 
 
 
 
 
 
 
Oil and natural gas purchases
$

 
$

 
$
3

 
$
0.10

Transportation costs
93

 
3.59

 
100

 
3.41

Lease operating expense(2)
138

 
5.34

 
158

 
5.35

General and administrative(3)
123

 
4.73

 
89

 
3.03

Depreciation, depletion and amortization
418

 
16.15

 
507

 
17.23

Gain on sale of assets

 

 
(3
)
 
(0.13
)
Impairment charges
458

 
17.72

 
1,103

 
37.47

Exploration and other expense
7

 
0.27

 
5

 
0.18

Taxes, other than income taxes
56

 
2.17

 
77

 
2.61

Total operating expenses
$
1,293

 
$
49.97

 
$
2,039

 
$
69.25

 
 
 
 
 
 
 
 
Total equivalent volumes (MBoe)
25,878

 
 

 
29,439

 
 

 
(1)
Per unit costs are based on actual amounts rather than the rounded totals presented.
(2)
Includes approximately $2 million for the year ended December 31, 2018 or $0.07 per Boe of adjustments under a joint venture agreement.
(3)
For the year ended December 31, 2019, amount includes approximately $20 million or $0.76 per Boe of transition, severance and other costs, $18 million or $0.70 per Boe of incentive compensation expense, $1 million or $0.01 per Boe of fees paid to Sponsors and $24 million or $0.93 per Boe of legacy litigation accruals or settlements. For the year ended December 31, 2018, amount includes approximately $9 million or $0.32 per Boe of transition and severance costs related to workforce reductions, $13 million or $0.47 per Boe of incentive compensation expense.
    
Transportation costs.  Transportation costs for the year ended December 31, 2019 decreased by $7 million as compared to 2018 primarily as a result of (i) lower fees associated with revised transportation agreements in the Permian in 2019, (ii) an increase in wells drilled with our drilling joint venture partner in the Eagle Ford in 2019 (see Part II, Item 8. “Financial Statements and Supplementary Data”, Note 10), and (iii) lower transportation cost associated with the rejection of certain transportation contracts during the fourth quarter of 2019 in conjunction with our Chapter 11 Cases.
Lease operating expense.  Lease operating expense for the year ended December 31, 2019 decreased by $20 million compared to 2018. The decrease in 2019 compared to 2018 is due primarily to lower disposal costs in all areas and lower chemical costs in the Permian and NEU. Lease operating expense for the year ended December 31, 2018 includes approximately $2 million in adjustments under a joint venture agreement.
General and administrative expenses.  General and administrative expenses for the year ended December 31, 2019 increased by $34 million compared to 2018. Higher costs during the year ended December 31, 2019 compared to 2018 were primarily due to higher professional and legal fees of $19 million related to legal and financial advisory fees associated with bankruptcy related matters incurred prior to our Chapter 11 filing. Legal and financial advisory fees incurred after our Chapter 11 filing are recorded as reorganization costs as further noted below. Also impacting the year ended December 31, 2019 was an accrual of $21 million related to legacy legal matters (see Part II, Item 8. “Financial Statements and Supplementary Data”, Note 8) offset by $6 million in lower severance costs.
Depreciation, depletion and amortization expense.  Depreciation, depletion and amortization expense for the year ended December 31, 2019 decreased by $89 million compared to 2018 primarily due to non-cash impairment charges recorded in the fourth quarter of 2018 and third quarter of 2019 on our proved properties in the Permian and NEU, respectively, decreased capital spending and lower production volumes. Our depreciation, depletion and amortization rate in the future will be impacted by the level, the location, and timing of capital spending, the overall cost of capital and the level and type of

38


reserves recorded on completed projects. Our average depreciation, depletion and amortization costs per unit for the year-to-date periods were:
 
Year ended December 31,
 
2019
 
2018
Depreciation, depletion and amortization ($/Boe)
$
16.15

 
$
17.23

    
Impairment charges. For the year ended December 31, 2019, we recorded a non-cash impairment charge of
approximately $458 million on our NEU proved properties as a result of the filing of our Chapter 11 Cases (see Part II, Item 8. “Financial Statements and Supplementary Data”, Note 1A) and the uncertainties surrounding the availability of financing needed to develop our proved undeveloped reserves.

For the year ended December 31, 2018, we recorded non-cash impairment charges of approximately $1,044 million and $59 million on our proved and unproved properties, respectively, in the Permian basin as a result of the decline in commodity prices and the significant reduction in future development capital allocated to the Permian during 2018. See Part II, Item 8. “Financial Statements and Supplementary Data”, Note 3 for more information on impairment.

Taxes, other than income taxes.  Taxes, other than income taxes for the year ended December 31, 2019 decreased by $21 million from 2018. The decrease in 2019 compared to 2018 is primarily due to a decrease in severance taxes as a result of lower commodity prices and the realization of severance tax credits.

Other Income Statement Items.
Gain (loss) on extinguishment/modification of debt.  During the year ended December 31, 2019, we recorded a total gain on extinguishment of debt of $10 million as a result of our repurchase of approximately $50 million in aggregate principal amount of our senior unsecured notes due 2020.
For the year ended December 31, 2018, we recorded a total gain on extinguishment of debt of $73 million as a result of (i) exchanging certain senior unsecured notes for $1,092 million in new senior secured notes and (ii) repurchasing a portion of our senior unsecured notes due 2020, 2022 and 2023.
Interest expense. Interest expense for the year ended December 31, 2019 increased by $54 million compared to the same period in 2018 due to reclassifying our debt as current and writing off approximately $90 million in unamortized debt discount and debt issue costs in the third quarter 2019 as a result of uncertainties regarding default, event of default and cross-default provisions under our indentures and RBL Facility as of September 30, 2019 (including those discussed in Part I1, Item 8. “Financial Statements and Supplementary Data”, Note 1A). This was partially offset by discontinuing the accrual of interest during substantially all of the fourth quarter of 2019 associated with the 1.5 lien notes and senior unsecured notes classified as liabilities subject to compromise as a result of filing the Chapter 11 Cases on October 3, 2019. Also impacting interest expense for the year ended December 31, 2019 was the issuance of our senior secured notes due 2026 in May 2018.
Reorganization items, net. Reorganization items, net were $65 million for the year ended December 31, 2019. The reorganization items primarily consisted of expenses and gains/(losses) realized or incurred subsequent to our bankruptcy filing petition date and that are a direct result of the Chapter 11 Cases. These costs include professional fees incurred subsequent to the filing of the date of the Chapter 11 Cases, amounts recorded associated with the rejection of executory contracts approved by the Bankruptcy Court and DIP Facility costs.
Income taxes. Our effective tax rate for both the years ended December 31, 2019 and 2018 was 0%, which differed from the statutory rate of 21% primarily due to recording a full valuation allowance on our net deferred tax assets and non-deductible compensation expenses. Changes in our deferred taxes from year to year are offset by changes to our related valuation allowance and thus have the effect of eliminating the impact of federal taxes on our income. For additional details on our income taxes, see Part II, Item 8. “Financial Statements and Supplementary Data”, Note 4.



39


Supplemental Non-GAAP Measures
We use the non-GAAP measures “EBITDAX” and “Adjusted EBITDAX” as supplemental measures. We believe these supplemental measures provide meaningful information to our investors. We define EBITDAX as net income (loss) plus interest and debt expense, income taxes, depreciation, depletion and amortization and exploration expense. Adjusted EBITDAX is defined as EBITDAX, adjusted as applicable in the relevant period for the net change in the fair value of derivatives (mark-to-market effects of financial derivatives, net of cash settlements and cash premiums related to these derivatives), incentive compensation expense (which represents non-cash compensation expense under long-term incentive programs), transition, severance and other costs that affect comparability, reorganization items, fees paid to the Sponsors, legacy litigation settlements, gains and losses on sale of assets, gains and losses on extinguishment/modification of debt and impairment charges.
We believe that the presentation of EBITDAX and Adjusted EBITDAX is important to provide management and investors with additional information (i) to evaluate our ability to service debt, adjusting for items required or permitted in calculating covenant compliance under our debt agreements, (ii) to provide an important supplemental indicator of the operational performance of our business without regard to financing methods and capital structure, (iii) for evaluating our performance relative to our peers, (iv) to measure our liquidity (before cash capital requirements and working capital needs) and (v) to provide supplemental information about certain material non-cash and/or other items that may not continue at the same level in the future. EBITDAX and Adjusted EBITDAX have limitations as analytical tools and should not be considered in isolation or as a substitute for analysis of our results as reported under GAAP or as an alternative to net income (loss), operating income (loss), operating cash flows or other measures of financial performance or liquidity presented in accordance with GAAP.
Below is a reconciliation of our consolidated net income (loss) to EBITDAX and Adjusted EBITDAX:
 
Year ended December 31,
 
2019
 
2018
 
(in millions)
Net loss
$
(943
)
 
$
(1,003
)
Income tax expense

 

Interest expense, net of capitalized interest(1)
419

 
365

Depreciation, depletion and amortization
418

 
507

Exploration expense
4

 
4

EBITDAX
(102
)
 
(127
)
Mark-to-market on financial derivatives(2) 
81

 
(84
)
Cash settlements and cash premiums on financial derivatives(3) 
25

 
(25
)
Incentive compensation expense(4) 
18

 
13

Transition, severance and other costs
20

 
9

Reorganization items, net(5)
65

 

Fees paid to Sponsors
1

 

Legacy litigation settlements(6)
24

 

Gain on sale of assets

 
(3
)
Gain on extinguishment/modification of debt
(10
)
 
(73
)
Impairment charges
458

 
1,103

Adjusted EBITDAX
$
580

 
$
813

 
(1)
Includes approximately $90 million at December 31, 2019 related to the write-off of unamortized debt discount and debt issue costs during the third quarter 2019 due to reclassifying our debt as current as a result of uncertainties regarding default, event of default and cross-default provisions under our indentures and RBL Facility as of September 30, 2019. Amounts written off are included in interest expense in the consolidated statement of operations.
(2)
Represents the income statement impact of financial derivatives.
(3)
Represents actual cash settlements related to financial derivatives. No cash premiums were received or paid for the years ended December 31, 2019 and 2018.
(4)
For the year ended December 31, 2019, incentive compensation expense includes $10 million in amounts under the Key Employee Retention Program, “KERP”, in lieu of long-term incentive compensation. For additional details on the KERP, see Part II, Item 8. “Financial Statements and Supplementary Data”, Note 9.
(5)
Includes expenses and gains/(losses) realized or incurred subsequent to our bankruptcy filing petition date and that are a direct result of the Chapter 11 Cases. These costs include professional fees incurred subsequent to the filing date of the Chapter 11 Cases, amounts recorded associated with the rejection of executory contracts approved by the Bankruptcy Court and DIP Facility costs. For additional details on reorganization items, see Part II, Item 8. “Financial Statements and Supplementary Data”, Note 1A.
(6)
Reflects amounts accrued primarily related to our Fairfield legal case. For additional details on our legacy legal matters, see Part II, Item 8. “Financial Statements and Supplementary Data”, Note 8.

40


Commitments and Contingencies
For a further discussion of our commitments and contingencies, see Part II, Item 8. “Financial Statements and Supplementary Data”, Note 8.
Off-Balance Sheet Arrangements
We have no investments in unconsolidated entities or persons that could materially affect our liquidity or the availability of capital resources.  We do not have any off-balance sheet arrangements that have, or are reasonably likely to have, a material effect on our financial condition or results of operations.
Critical Accounting Estimates
Our significant accounting policies are described in Part II, Item 8. “Financial Statements and Supplementary Data”, Note 1 of our consolidated financial statements included elsewhere in this Annual Report on Form 10-K. The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amount of assets, liabilities, revenue and expense and the disclosures of contingent assets and liabilities. We consider our critical accounting estimates to be those estimates that require complex or subjective judgment in the application of the accounting policy and that could significantly impact our financial results based on changes in those judgments. Changes in facts and circumstances may result in revised estimates and actual results may differ materially from those estimates. Our management has identified the following critical accounting estimates:
Accounting for Oil and Natural Gas Producing Activities.  We apply the successful efforts method of accounting for our oil and natural gas exploration and development activities. Under this method, non-drilling exploratory costs and costs of carrying and retaining undeveloped properties are charged to expense as incurred while acquisition costs, development costs and the costs of drilling and completing wells are capitalized. If a well is exploratory in nature, such costs are capitalized, pending the determination of proved oil and natural gas reserves. As a result, at any point in time, we may have capitalized costs on our consolidated balance sheet associated with exploratory wells that may be charged to exploration expense in a future period. Costs of drilling exploratory wells that do not result in proved reserves are expensed. Under the successful efforts method, we also capitalize salaries and benefits that we determine are directly attributable to our oil and natural gas activities. Depreciation, depletion, amortization and the impairment of oil and natural gas properties is calculated on a depletable unit basis based on estimates of proved quantities of proved oil and natural gas reserves. Revisions to these estimates can alter our depletion rates in the future and affect our future depletion expense or assessment of impairment.
We evaluate capitalized costs related to proved properties at least annually or upon a triggering event (such as a significant decline in forward commodity prices or change in development plans, among other items) to determine if impairment of such properties has occurred.  Our evaluation of whether costs are recoverable is made based on common geological structure or stratigraphic conditions (for example, we evaluate proved property for impairment separately for each of our operating areas), and the evaluation considers estimated future cash flows for all proved developed (producing and non-producing), proved undeveloped reserves and risk-weighted non-proved reserves in comparison to the carrying amount of the proved properties. Important assumptions in the determination of these cash flows are estimates of future oil and gas production, estimated forward commodity prices as of the date of the estimate, adjusted for geographical location and contractual and quality differentials and estimates of future operating and development costs. If the carrying amount of a property exceeds the estimated undiscounted future cash flows of its reserves, the carrying amount is reduced to estimated fair value through a charge to income. Fair value is calculated by discounting those estimated future cash flows using a risk-adjusted discount rate. The discount rate is based on rates utilized by market participants that are commensurate with the risks inherent in the development and production of the underlying crude oil and natural gas.  Each of these estimates involves a high degree of judgment.
Capitalized costs associated with unproved properties (e.g., leasehold acquisition costs associated with non-producing areas) are also assessed for impairment based on estimated drilling plans and capital expenditures, which may also change relative to forward commodity prices and/or potential lease expirations. Generally, economic recovery of unproved reserves in non-producing areas are not yet supported by actual production or conclusive formation tests, but must be confirmed by continued exploration and development activities. Our allocation of capital to the development of unproved properties may be influenced by changes in commodity prices (e.g., a low oil price environment), the availability of oilfield services and the relative returns of our unproved property development in comparison to the use of capital for other strategic objectives.
During the year ended December 31, 2019, we recorded a non-cash impairment charge of approximately $458 million on our NEU proved properties as a result of the filing of our Chapter 11 Cases (see Part II, Item 8. “Financial Statements and Supplementary Data”, Note 1A) and the uncertainties surrounding the availability of financing needed to develop our proved undeveloped reserves. During the year ended December 31, 2018, we recorded non-cash impairment charges of approximately

41


$1,044 million and $59 million on our proved and unproved properties, respectively, in the Permian basin due to the decline in commodity prices during the year as well as the significant reduction in future development capital allocated to the Permian during 2018. As of December 31, 2019, our remaining net capitalized costs related to proved properties were approximately $1,961 million in Eagle Ford, $721 million in NEU, and $716 million in the Permian basin.
The proved oil and gas reserve estimates as of December 31, 2019 have been prepared by Ryder Scott Company, L.P. (“Ryder Scott”), our independent third party reserve engineers. Estimates of proved reserves reflect quantities of oil, natural gas and NGLs, which geological and engineering data demonstrate, with reasonable certainty, will be recoverable in future years from known reservoirs under existing economic conditions. These estimates of proved oil and natural gas reserves primarily impact our property, plant and equipment amounts on our balance sheets and the depreciation, depletion and amortization amounts, including any impairment charges, on our consolidated income statements, among other items. The process of estimating oil and natural gas reserves is complex and requires significant judgment to evaluate all available geological, geophysical engineering and economic data. Significant assumptions used in the proved oil and gas reserve estimates are assessed by both Ryder Scott and our internal reserve team. All reserve reports prepared by Ryder Scott were reviewed by our internal reserve and management teams. Because these estimates depend on many assumptions, any or all of which may differ substantially from actual results, reserve estimates may be different from the quantities of oil and natural gas that are ultimately recovered.
As of December 31, 2019, 100% of our total proved reserves were proved developed reserves. The data for a given field may change substantially over time as a result of numerous factors, including additional development activity, evolving production history and a continual reassessment of the viability of production under changing economic conditions. In addition, the subjective decisions and variances in available data for various fields increase the likelihood of significant changes in these estimates. As a result, material revisions to existing reserve estimates occur from time to time. For example, in 2018 we adjusted our PUD booking methodology from a five-year to a three-year timeframe and in 2019, we recorded no PUD reserves due to uncertainty regarding the Company's availability of capital prior to emerging from bankruptcy that would be required to develop the PUD reserves (see Part II, Item 8. “Financial Statements and Supplementary Data”, Note 1A). See Part I, Item 1. “Business” under the heading Oil and Natural Gas Properties for further discussion on our proved reserves.
Deferred Taxes and Valuation Allowances. We record deferred income tax assets and liabilities reflecting the tax consequences of differences between the financial statement carrying value of assets and liabilities and the tax basis of those assets and liabilities. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in income in the period that includes the enactment date. Our deferred tax assets and liabilities reflect our conclusions about which positions are more likely than not to be sustained if they are audited by taxing authorities.
We assess the available positive and negative evidence to estimate whether sufficient future taxable income will be generated to permit the use of existing deferred tax assets. When it is more likely than not that we will not be able to realize all or a portion of such asset, we record a valuation allowance. Based upon the evaluation of the available evidence, we maintained a valuation allowance against our net deferred tax assets of $743 million as of December 31, 2019. We evaluate our valuation allowances each reporting period and the level of such allowance will change as our deferred tax balances change. Key estimates and assumptions include expectations of future taxable income and the ability and our intent to undertake transactions that will allow us to realize the asset, all of which involve judgment. Changes in these estimates or assumptions can have a significant effect on our operating results.
ITEM 7A.      Qualitative and Quantitative Disclosures About Market Risk
We are exposed to market risks in our normal business activities. Market risk is the potential loss that may result from market changes associated with an existing or forecasted financial or commodity transaction. The types of market risks we are exposed to and examples of each are:
Commodity Price Risk
changes in oil, natural gas and NGLs prices impact the amounts at which we sell our production and affect the fair value of our oil and natural gas derivative contracts; and
changes in locational price differences also affect amounts at which we sell our oil, natural gas and NGLs production, and the fair values of any related derivative products.
Interest Rate Risk
changes in interest rates affect the interest expense we incur on our variable-rate debt and the fair value of fixed-rate debt; and

42


changes in interest rates used to discount liabilities result in higher or lower recorded amount of liabilities and accretion expense over time.
Risk Management Activities
Where practical, we manage commodity price risks by entering into contracts involving physical or financial settlement that attempt to limit exposure related to future market movements on our cash flows. The timing and extent of our risk management activities are based on a number of factors, including our market outlook, risk tolerance and liquidity. Our risk management activities typically involve the use of the following types of contracts:
forward contracts, which commit us to purchase or sell energy commodities in the future;
option contracts, which convey the right to buy or sell a commodity, financial instrument or index at a predetermined price;
swap contracts, which require payments to or from counterparties based upon the differential between two prices or rates for a predetermined contractual (notional) quantity; and
structured contracts, which may involve a variety of the above characteristics.
Many of the contracts we use in our risk management activities qualify as derivative financial instruments. A discussion of our accounting policies for derivative instruments is included in Part II, Item 8. “Financial Statements and Supplementary Data”, Notes 1 and 5.
For information regarding changes in commodity prices during 2019, please see Part II, Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations”.
Commodity Price Risk
Oil, Natural Gas and NGLs Derivatives. We attempt to mitigate commodity price risk and stabilize cash flows associated with our forecasted sales of oil and natural gas production through the use of derivative oil and natural gas swaps, basis swaps and option contracts. These contracts impact our earnings as the fair value of these derivatives changes. Our derivatives do not mitigate all of the commodity price risks of our forecasted sales of oil and natural gas production and, as a result, we are subject to commodity price risks on our remaining forecasted production.
Sensitivity Analysis. The table below presents the change in fair value of our commodity-based derivatives due to hypothetical changes in oil and natural gas prices, discount rates and credit rates at December 31, 2019:
 
 
 
Oil and Natural Gas Derivatives
 
 
 
10 Percent Increase
 
10 Percent Decrease
 
Fair Value
 
Fair Value
 
Change
 
Fair Value
 
Change
 
(in millions)
Price impact(1) 
$
9

 
$
(42
)
 
$
(51
)
 
$
52

 
$
43

 
 
 
Oil and Natural Gas Derivatives
 
 
 
1 Percent Increase
 
1 Percent Decrease
 
Fair Value
 
Fair Value
 
Change
 
Fair Value
 
Change
 
(in millions)
Discount Rate(2) 
$
9

 
$
8

 
$
(1
)
 
$
9

 
$

Credit rate(3) 
$
9

 
$
8

 
$
(1
)
 
$
9

 
$

 
(1)    Presents the hypothetical sensitivity of our commodity-based derivatives to changes in fair values arising from changes in oil and natural gas prices.
(2)    Presents the hypothetical sensitivity of our commodity-based derivatives to changes in the discount rates we used to determine the fair value of our derivatives.
(3)    Presents the hypothetical sensitivity of our commodity-based derivatives to changes in credit risk of our counterparties.
Interest Rate Risk
Certain of our debt agreements are sensitive to changes in interest rates.  The table below shows the maturity of the carrying amounts and related weighted-average effective interest rates on our long-term interest-bearing debt by expected maturity date as well as the total fair value of the debt.  The fair value of our long-term debt has been estimated primarily based on quoted market prices for the same or similar issues.



43


 
December 31, 2019
 
December 31, 2018
 
Expected Fiscal Year of Maturity of Carrying  Amounts
 
 
 
Fair Value
 
Carrying Amounts
 
Fair Value
 
2020
 
2021
 
2022
 
2023
 
2024
 
Thereafter
 
Total
 
 
 
 
(in millions)
Fixed rate debt
$
182

 
$

 
$
182

 
$
324

 
$
1,592

 
$
2,000

 
$
4,280

 
$
1,023

 
$
4,330

 
$
2,468

Average interest rate
8.2
%
 
8.2
%
 
8.2
%
 
8.3
%
 
8.1
%
 
7.8
%
 
 
 
 
 
 
 
 
Variable rate debt
$
148

 
$
315

 

 

 

 

 
$
463

 
$
463

 
$
108

 
$
108

Average interest rate
5.3
%
 
5.3
%
 
%
 
%
 
%
 
%
 
 
 
 

 
 

 
 


44


ITEM 8.        FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Index
Below is an index to the items contained in Part II, Item 8, Financial Statements and Supplementary Data
 
 
Page
 
 
 
 
 
 
 
 
 
 
 
 
Supplemental Financial Information
 
 
 
 
 
Schedules
 
All financial statement schedules have been omitted because they are either not required, not applicable or the information required to be presented is included in the financial statements or related notes thereto.

45


MANAGEMENT’S ANNUAL REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as defined by SEC rules adopted under the Securities Exchange Act of 1934, as amended. Our internal control over financial reporting is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. It consists of policies and procedures that:
Pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of our assets;
Provide reasonable assurance that transactions are recorded as necessary to permit preparation of the financial statements in accordance with generally accepted accounting principles, and that our receipts and expenditures are being made only in accordance with authorizations of our management and directors; and
Provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of our assets that could have a material effect on the financial statements.
Under the supervision and with the participation of management, including the Chief Executive Officer and Chief Financial Officer, we made an assessment of the effectiveness of our internal control over financial reporting as of December 31, 2019. In making this assessment, we used the criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework). Based on our evaluation, we concluded that our internal control over financial reporting was effective as of December 31, 2019


46


Report of Independent Registered Public Accounting Firm

To the Board of Directors of
EP Energy Corporation (Debtor in Possession)

Opinion on the Financial Statements

We have audited the accompanying consolidated balance sheets of EP Energy LLC (Debtor in Possession) (the “Company”) as of December 31, 2019 and 2018, the related consolidated statements of income, cash flows and changes in equity for each of the two years in the period ended December 31, 2019, and the related notes (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company at December 31, 2019 and 2018, and the results of its operations and its cash flows for each of the two years in the period ended December 31, 2019, in conformity with U.S. generally accepted accounting principles.

The Company's Ability to Continue as a Going Concern

The accompanying consolidated financial statements have been prepared assuming that the Company will continue as a going concern. As discussed in Note 1A to the consolidated financial statements, the Company filed for relief under Chapter 11 of Title 11 of the United States Bankruptcy Code on October 3, 2019 and has stated the significant risks and uncertainties related to the Company’s liquidity and Chapter 11 proceedings raise substantial doubt about the Company’s ability to continue as a going concern. Management’s evaluation of the events and conditions and management’s plans regarding these matters are also described in Note 1A. The consolidated financial statements do not include any adjustments that might result from the outcome of this uncertainty.

Basis for Opinion

These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB and in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion.

Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

/s/ Ernst & Young LLP


We have served as the Company’s auditor since 2006.

Houston, Texas
March 25, 2020

47


EP ENERGY LLC (DEBTOR IN POSSESSION)
CONSOLIDATED STATEMENTS OF INCOME
(In millions)
 
Year Ended December 31,
 
2019
 
2018
Operating revenues
 
 
 

Oil
$
790

 
$
1,045

Natural gas
49

 
75

NGLs
62

 
120

Financial derivatives
(81
)
 
84

Total operating revenues
820

 
1,324

 
 
 
 
Operating expenses
 
 
 
Oil and natural gas purchases

 
3

Transportation costs
93

 
100

Lease operating expense
138

 
158

General and administrative
123

 
89

Depreciation, depletion and amortization
418

 
507

Gain on sale of assets

 
(3
)
Impairment charges
458

 
1,103

Exploration and other expense
7

 
5

Taxes, other than income taxes
56

 
77

Total operating expenses
1,293

 
2,039

 
 
 
 
Operating loss
(473
)
 
(715
)
Other income
4

 
4

Gain on extinguishment/modification of debt
10

 
73

Interest expense
(419
)
 
(365
)
Reorganization items, net
(65
)
 

Loss before income taxes
(943
)
 
(1,003
)
Income tax expense

 

Net loss
$
(943
)
 
$
(1,003
)
See accompanying notes.


48


EP ENERGY LLC (DEBTOR IN POSSESSION)
CONSOLIDATED BALANCE SHEETS
(In millions)
 
December 31, 2019
 
December 31, 2018
ASSETS
 

 
 

Current assets
 

 
 

Cash and cash equivalents
$
32

 
$
27

Restricted cash
1

 

Accounts receivable
 
 
 

Customer, net of allowance of less than $1 in 2019 and 2018
127

 
164

Other, net of allowance of $1 in 2019 and 2018
16

 
66

Materials and supplies
42

 
22

Derivative instruments
9

 
101

Other
27

 
5

Total current assets
254

 
385

Property, plant and equipment, at cost
 
 
 

Oil and natural gas properties
7,388

 
7,344

Other property, plant and equipment
73

 
81

 
7,461

 
7,425

Less accumulated depreciation, depletion and amortization
4,026

 
3,651

Total property, plant and equipment, net
3,435

 
3,774

Other assets
 
 
 

Derivative instruments

 
13

Unamortized debt issue costs
2

 
8

Operating lease assets and other
19

 
1

 
21

 
22

Total assets
$
3,710

 
$
4,181

See accompanying notes.

49


EP ENERGY LLC (DEBTOR IN POSSESSION)
CONSOLIDATED BALANCE SHEETS
(In millions)
 
December 31, 2019
 
December 31, 2018
LIABILITIES AND EQUITY
 

 
 

Current liabilities
 

 
 

Current portion of long-term debt
$
1,815

 
$
58

Debtor in possession financing
148

 

Owner and royalties payable
72

 
144

Accounts payable and accrued expenses
139

 
105

Accrued interest
40

 
70

Accrued legal and other reserves
12

 
47

Other current liabilities
22

 
16

Total current liabilities
2,248

 
440

 
 
 
 
Long-term debt, net of debt issue costs

 
4,285

Other long-term liabilities
 
 
 

Asset retirement obligations
43

 
39

Lease obligations and other
20

 
16

Total non-current liabilities
63

 
4,340

 
 
 
 
Liabilities subject to compromise
2,932

 

Commitments and contingencies (Note 8)

 


Member’s equity
(1,533
)
 
(599
)
Total liabilities and equity
$
3,710

 
$
4,181

See accompanying notes.


50


EP ENERGY LLC (DEBTOR IN POSSESSION)
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In millions)
 
Year Ended December 31,
 
2019
 
2018
Cash flows from operating activities
 

 
 

Net loss
$
(943
)
 
$
(1,003
)