10-K

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

____________________________________________________________

Form 10-K

(Mark One)

xANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2019

OR

oTRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from                  to                  .

Commission File Number 001-36253

____________________________________________________________

EP Energy Corporation

(Exact Name of Registrant as Specified in Its Charter)

Delaware	46-3472728
(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

Title of each class	Trading Symbol(s)	Name of each exchange on which registered
N/A	N/A	N/A

*On June 7, 2019, a Form 25 relating to the delisting and deregistration under Section 12(b) of the Act of the registrant's Class A Common Stock, $0.01 par value per share, was filed by the New York Stock Exchange LLC. The registrant's Class A Common Stock, $0.01 par value per share, trades on the OTC Pink Sheets Market.

Securities registered pursuant to Section 12(g) of the Act: Class A Common Stock, $0.01 par value per share

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 o No x.

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 x  No o.

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 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

Aggregate market value of the Company’s common stock held by non-affiliates of the registrant as of June 28, 2019, was $20,418,558 based on the closing sale price on the OTC Pink Sheets Market.

Indicate the number of shares outstanding of each of the registrant’s classes of common stock, as of the latest practicable date.

Class A Common Stock, par value $0.01 per share. Shares outstanding as of February 28, 2020: 254,582,481

Class B Common Stock, par value $0.01 per share. Shares outstanding as of February 28, 2020: 237,256

EP ENERGY CORPORATION

TABLE OF CONTENTS

Caption	Page
PART I
Item 1. Business	1
Item 1A. Risk Factors	15
Item 1B. Unresolved Staff Comments	37
Item 2. Properties	37
Item 3. Legal Proceedings	37
Item 4. Mine Safety Disclosures	37
PART II
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	38
Item 6. Selected Financial Data	38
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations	38
Item 7A. Quantitative and Qualitative Disclosures About Market Risk	52
Item 8. Financial Statements and Supplementary Data	55
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	87
Item 9A. Controls and Procedures	87
Item 9B. Other Information	87
PART III
Item 10. Directors, Executive Officers and Corporate Governance	88
Item 11. Executive Compensation	96
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	101
Item 13. Certain Relationships and Related Transactions, and Director Independence	105
Item 14. Principal Accountant Fees and Services	107
PART IV
Item 15. Exhibits and Financial Statement Schedules	108
Item 16. Form 10-K Summary	116
Signatures	117

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 Corporation and/or its subsidiaries.

All references to “common stock” herein refer to Class A common stock.

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;

iii

• our limited ability to borrow under existing debt agreements to fund our operations;

• 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 15 through 36 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.

iv

PART I

ITEM 1.    BUSINESS

Overview

EP Energy Corporation (“EP Energy”), a Delaware corporation formed in 2013, is an independent exploration and production company engaged in the acquisition and development of unconventional onshore oil and natural gas properties in the United States. 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 accretiveacquisitionopportunities 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

1

due 2024 (the “2024 1.5 Lien Notes”), 9.375% Senior Notes due 2020, 2022 Unsecured Notes 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.

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

2

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 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, 8 and 9.

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. 

3

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.

Our Properties

Eagle Ford Shale.  The Eagle Ford Shale, located in South Texas, is one of the premier unconventional oil plays in the United States. We were an early entrant into this play in late 2008, and since that time have acquired a leasehold position in the core of the oil window, primarily in La Salle County. The Eagle Ford formation in La Salle County has up to 125 feet of net thickness (165 feet gross). Due to its high carbonate content, the formation is also very brittle, and exhibits high productivity when fractured.  During 2019, we invested $368 million in capital (excluding approximately $13 million in acquisition capital). As of December 31, 2019, we had 122,276 net (132,952 gross) acres in the Eagle Ford.

During 2019, we operated an average of two drilling rigs and as of December 31, 2019, we had 852 net producing wells (847 net operated wells) in this program. We are currently not running any rigs in the Eagle Ford. For the year ended December 31, 2019, our average net daily production was 33,700 Boe/d, representing a decrease of 9% over the same period in 2018 due to fewer wells placed on production in the second half of 2018 through 2019.

Northeastern Utah.  The Northeastern Utah asset is located in Duchesne and Uinta counties in the Uinta basin. The Uinta basin is characterized by naturally fractured, tight-oil sands and carbonates with multiple pay zones. Our operations are primarily focused on developing the NEU Complex, which is comprised of the Altamont, Bluebell and Cedar Rim fields. The NEU Complex has a gross pay interval thickness of over 4,300 feet and we believe the Wasatch and Green River formations are ideal targets for horizontal drilling and modern fracture stimulation techniques. Our commingled production is from over 1,500 feet of net stimulated rock. Historically, our activity has been focused on the development of our vertical inventory on 80-acre and 160-acre spacing; however, we have completed 14 horizontal wells with lateral lengths between 7,900 and 9,800 feet in the Wasatch and Green River formations. Industry activity has focused on horizontal drilling in the Wasatch and Green River formations testing tight carbonate and sand intervals and has also piloted 80-acre vertical downspacing in these formations. Due to the largely held-by-production nature of our acreage position, if horizontal drilling continues to be successful, it will result in additional opportunities that could be added to our inventory of drilling locations.

We are subject to a drilling joint venture to accelerate and fund future oil and natural gas development in

NEU. Under the joint venture, our partner is participating in the development of 53 wells and will provide a capital carry

in exchange for a 50 percent working interest in the joint venture wells. As of December 31, 2019, we have drilled and completed 51 wells under the joint venture agreement.

During 2019, we invested $144 million in capital in NEU (excluding approximately $6 million in acquisition capital). As of December 31, 2019, we had 160,891 net (292,641 gross) acres in NEU.

During 2019, we operated an average of two drilling rigs in NEU. As of December 31, 2019, we had 350 net producing wells (345 net operated wells) and are currently running two rigs in this program.  For the year ended December 31, 2019, our average net daily production was 15,687 Boe/d, representing a decrease of 8% over 2018 due to reduced drilling activity in 2019.

Permian.  The Permian basin is characterized by numerous stacked oil reservoirs (including the Wolfcamp A, B and C zones) that provide multiple targets for horizontal drilling. In 2009 and 2010, we leased 138,130 net (138,469 gross) acres on the University of Texas Land System in the Permian basin, located primarily in Reagan, Crockett, Upton and Irion counties. In 2014, we acquired approximately 37,000 net acres in the Southern Midland basin. As of December 31, 2019, we had 182,113 net (183,029 gross) acres in the Permian.

We are party to a Consolidated Drilling and Development Unit Agreement with the University of Texas Land System in the Permian basin to provide flexibility to extend the time frame to hold our acreage through 2021, with an annual well completion requirement of 55 wells per year through 2020. For the years ended 2016 and 2017, we met our annual well completion requirement; however, we failed to meet this requirement in 2018 and 2019. To the extent that we meet our annual well completion requirement, the wells completed during that year qualify for a variable royalty, which is determined using a rolling average six month price with royalty rates of 12.5% at an average price of $50 per Bbl (WTI) and below; 18.75% at an average price of $50.01 to $60 per Bbl (WTI); 25% at an average price of $60.01 to $80 per Bbl (WTI); and 28% above $80 per Bbl (WTI). Should we not meet our annual well completion requirement in a given year, the wells completed during that given year will not qualify for the variable royalty and instead be subject to a 25.00% royalty rate.

4

During 2019, we invested $5 million in capital in the Permian and we did not operate any drilling rigs. As of December 31, 2019, we had 356 net producing wells (353 net operated wells). We are currently not running any rigs in this program.  For the year ended December 31, 2019, our average net daily production was 21,464 Boe/d, representing a decrease of 19% over 2018, reflecting the slower pace of development from reduced capital spending in 2019. In 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.

The following table provides a summary of acreage and gross operated wells completed in each of the following areas as of December 31, 2019:

	Acres		Gross Operated Wells Completed (#)
	Gross	Net
Eagle Ford Shale	132,952	122,276	54
Northeastern Utah	292,641	160,891	13
Permian	183,029	182,113	—
Total	608,622	465,280	67

Oil and Natural Gas Properties

Oil, Natural Gas and NGLs Reserves and Production

Proved Reserves

The proved oil and gas reserve estimates as of December 31, 2019 presented in the table below have been prepared by Ryder Scott Company L.P. (“Ryder Scott”), our independent third party reserve engineers. The reserve data represents only estimates, which are often different from the quantities of oil and natural gas that are ultimately recovered, and is consistent with estimates of reserves filed with other federal agencies except for differences of less than 5% resulting from actual production, acquisitions, property sales, necessary reserve revisions and additions to reflect actual experience. The risks and uncertainties associated with estimating proved oil and natural gas reserves are discussed further in Item 1A, “Risk Factors”. Net proved reserves exclude royalties and interests owned by others and reflect contractual arrangements and royalty obligations in effect at December 31, 2019.

	Net Proved Reserves(1)
	Oil (MMBbls)	NGLs (MMBbls)	Natural Gas (Bcf)	Total (MMBoe)	Percent (%)
Reserves by Classification
Proved Developed
Eagle Ford Shale	53.5	15.5	88.2	83.8	44	%
Northeastern Utah	24.7	—	97.3	40.9	22	%
Permian	14.7	24.0	158.3	65.0	34	%
Total Proved Developed(2)	92.9	39.5	343.8	189.7	100	%
Proved Undeveloped(2)
Eagle Ford Shale	—	—	—	—	—	%
Northeastern Utah	—	—	—	—	—	%
Permian	—	—	—	—	—	%
Total Proved Undeveloped	—	—	—	—	—	%
Total Proved Reserves	92.9	39.5	343.8	189.7	100	%

(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. For a further discussion of our proved reserves and changes therein, see Part II, Item 8, “Financial Statements and Supplementary Data”, under the heading Supplemental Oil and Natural Gas Operations.

(2) As of December 31, 2019, we have no recorded proved undeveloped (“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).

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The table below presents net proved reserves as reported and sensitivities related to our estimated proved reserves based on differing price scenarios as of December 31, 2019.

	Net Proved Reserves (MMBoe)
As Reported	189.7
10 percent increase in commodity prices	198.5
10 percent decrease in commodity prices	178.0

The sensitivities in the table above were based on the average first day of the month spot price for the preceding 12-month period of $55.69 per barrel of oil (WTI), $2.58 per MMBtu of natural gas (Henry Hub) and $13.37 per Bbl of NGLs used to determine net proved reserves at December 31, 2019.

Ryder Scott prepared 100% (by volume) of our total net proved developed reserves on a barrel of oil equivalent basis. The overall procedures and methodologies utilized by Ryder Scott in evaluating and preparing estimates of our net proved reserves as of December 31, 2019 complied with current SEC regulations. Ryder Scott’s report is included as an exhibit to this Annual Report on Form 10-K.

The technical person at Ryder Scott primarily responsible for overseeing the reserves evaluation and preparation has a B.S. degree in petroleum engineering. She is a Licensed Professional Engineer in the State of Texas, a member of the Society of Petroleum Engineers and has more than 15 years of experience in petroleum reserves evaluation.

The significant assumptions used in the proved oil and gas reserve estimates prepared by Ryder Scott were also assessed by our internal reserve team. Our internal reserve team is comprised of a technical staff of engineers and geoscientists that perform technical analysis of each undeveloped location. The staff uses industry accepted practices to estimate, with reasonable certainty, the economically producible oil and natural gas. The practices for estimating hydrocarbons in place include, but are not limited to, mapping, seismic interpretation of two-dimensional and/or three-dimensional data, core analysis, mechanical properties of formations, thermal maturity, well logs of existing penetrations, correlation of known penetrations, decline curve analysis of producing locations with significant production history, well testing, static bottom hole testing, flowing bottom hole pressure analysis and pressure and rate transient analysis.

Our primary internal technical person in charge of overseeing our reserves estimates has a B.S. degree in Mathematics and Finance. He leads the strategic planning and reservoir engineering evaluation groups of the company.  In this capacity, he oversees the reserve reporting and engagement with the company's independent third party engineering firm. He has 15 years of industry experience in various modeling, technical support and management roles. For a discussion of the internal controls over our proved reserves estimation process, see Part II, Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Critical Accounting Estimates”.

In general, the volume of production from oil and natural gas properties declines as reserves are depleted. Except to the extent we conduct successful exploration and development activities or acquire additional properties with proved reserves, or both, our proved reserves will decline as they are produced. Recovery of PUD reserves requires significant capital expenditures and successful drilling operations. The reserve data assumes that we can and will make these expenditures and conduct these operations successfully, but future events, including commodity price changes, may cause these assumptions to change. In addition, estimates of PUD reserves and proved non-producing reserves are inherently subject to greater uncertainties than estimates of proved producing reserves. For further discussion of our reserves, see Part II, Item 8, "Financial Statements and Supplementary Data", under the heading Supplemental Oil and Natural Gas Operations.

Proved Undeveloped Reserves (“PUDs”)

Estimated capital expenditures to develop our PUD reserves (convert PUD reserves to proved developed reserves) are based upon a long-range plan approved by our management team and reviewed with the Board of Directors. All PUD locations are surrounded by producing properties, and a majority of our PUDs directly offset a producing property. When we record PUDs beyond one location away from a producing property, reasonable certainty of economic producibility has been established by reliable technology in our areas, including field tests that demonstrate consistent and repeatable results within the formation being evaluated.

As of December 31, 2019, we have no recorded 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).

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As of December 31, 2018, our PUD reserves reflected PUD bookings methodology utilizing a three-year timeframe as a result of our available liquidity at that time and access to the capital markets due to the economic price environment. The 2018 information in the table includes 64 MMBoe (29 MMBoe to extensions and discoveries, 4 MMBoe to acquisitions, and 31 MMBoe to revisions other than price) of negative adjustments in 2018 when calculating each respective category as a result of determining our PUDs using a three-year timeframe instead of a five-year timeframe.

The following table summarizes our changes in PUDs for the years ended December 31, 2018 and December 31, 2019, respectively (in MMBoe):

Balance, December 31, 2017	173.8
Acquisitions	12.5
Revisions due to prices	0.1
Revisions other than prices	(65.6	)
Transfers to proved developed	(22.6	)
Divestitures	(7.3	)
Balance, December 31, 2018	90.9
Acquisitions	—
Revisions due to prices	—
Revisions other than prices	(3.2	)
Transfers to proved developed	(14.8	)
Divestitures	—
Revisions due to going concern uncertainties/Chapter 11 cases	(72.9	)
Balance, December 31, 2019	—

Revisions due to prices represent PUD revisions due to increases or decreases in commodity prices (using SEC 12-month average pricing). Revisions to PUDs other than prices for the year ended December 31, 2019, primarily include negative revisions of 37 MMBoe in NEU and 36 MMBoe in the Eagle Ford due to uncertainty regarding the Company's availability of capital prior to emerging from bankruptcy and 3 MMBoe of negative revisions due to asset performance. Revisions to PUDs other than prices for the year ended December 31, 2018, primarily include negative revisions of 74 MMBoe due to a reallocation of capital from the Permian to other development areas and positive revisions of 12 MMBoe associated with increased drilling activity in the Eagle Ford and NEU.

During 2019, 2018 and 2017 we spent approximately $339 million, $444 million and $377 million, respectively, to convert approximately 16% or 15 MMBoe, 13% or 23 MMBoe and 13% or 31 MMBoe, respectively, of our prior year-end PUD reserves to proved developed reserves.  As of December 31, 2019, due to uncertainty regarding the Company's availability of capital prior to emerging from bankruptcy that would be required to develop the PUD reserves, we have no recorded PUD reserves at December 31, 2019. Accordingly. we have not included forecasted capital spending to develop any PUD reserves.

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 the Stipulation. On March 23, 2020, the Bankruptcy Court approved the Stipulation. The Debtors are working with their constituents to explore various alternatives. We expect to report PUD reserves in the future to the extent we determine that we have the financial capability to execute a development plan to develop our PUD reserves. The actual amount and timing of our forecasted expenditures will depend on a number of factors, including actual drilling results, oilfield service costs, technology, acreage position, availability of capital and future commodity prices, which in the future could be lower than those in our projected long-range plan.

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Acreage and Wells

The following tables detail (i) our interest in developed and undeveloped acreage at December 31, 2019, (ii) our interest in oil and natural gas wells at December 31, 2019 and (iii) our development wells completed during the years 2017 through 2019. Any acreage in which our interest is limited to owned royalty, overriding royalty and other similar interests is excluded.

Acreage
	Developed		Undeveloped		Total
	Gross(1)	Net(2)	Gross(1)	Net(2)	Gross(1)	Net(2)
Eagle Ford Shale	61,012	53,706	71,940	68,570	132,952	122,276
Northeastern Utah	153,989	108,215	138,652	52,676	292,641	160,891
Permian	25,815	22,892	157,214	159,221	183,029	182,113
Other	70,741	5,912	200,944	89,373	271,685	95,285
Total Acreage	311,557	190,725	568,750	369,840	880,307	560,565

(1) Gross interest reflects the total acreage we participate in regardless of our ownership interest in the acreage.

(2) Net interest is the aggregate of the fractional working interests that we have in the gross acreage.

Our net developed acreage is concentrated in Texas (42%) and Utah (57%). Our net undeveloped acreage is concentrated in Texas (63%), Utah (15%), West Virginia (12%) and Wyoming (9%). Approximately 2%, 4% and 2% of our net undeveloped acreage is held under leases that have minimum remaining primary terms expiring in 2020, 2021 and 2022, respectively. We employ various techniques to manage the expiration of leases, including drilling the acreage ourselves prior to lease expiration, entering into farm-out or joint development agreements with other operators or extending lease terms.

Productive Wells
	Oil		Natural Gas		Total		Wells In Progress at December 31, 2019(1)
	Gross(2)	Net(3)(4)	Gross(2)	Net(3)	Gross(2)	Net(3)(4)	Gross(2)	Net(3)
Eagle Ford Shale	943	843	9	9	952	852	31	30
Northeastern Utah	453	349	2	1	455	350	7	5
Permian	399	356	—	—	399	356	3	3
Total Productive Wells	1,795	1,548	11	10	1,806	1,558	41	38

(1) Comprised of wells that were spud as of December 31, 2019 and have not been completed.

(2) Gross interest reflects the total wells we participated in, regardless of our ownership interest.

(3) Net interest is the aggregate of the fractional working interests that we have in the gross wells or gross wells drilled.

(4) At December 31, 2019, we operated 1,545 of the 1,558 net productive wells.

Wells Completed⁽¹⁾ 

	Net Development(2)
	2019	2018	2017
Total Productive Wells Completed	52	91	106

(1) No dry wells or exploratory wells were drilled or completed during the years 2017 through 2019.     

(2) Net development is the aggregate of the fractional working interests that we have in the gross wells completed.

The performance above should not be considered indicative of future drilling performance, nor should it be assumed that there is any correlation between the number of productive wells completed and the amount of oil and natural gas that may ultimately be recovered.

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Net Production, Sales Prices, Transportation and Production Costs

The following table details our net production volumes, and prices and costs per unit for each of the three years ended December 31:

	2019		2018		2017
Volumes:
Total Net Production Volumes
Oil (MBbls)	14,083		16,726		16,833
Natural Gas (MMcf)	42,059		44,913		46,356
NGLs (MBbls)	4,785		5,227		5,465
Total Equivalent Volumes (MBoe)	25,878		29,439		30,024
MBoe/d	70.9		80.7		82.3
Net Production Volumes by Area
Eagle Ford Shale
Oil (MBbls)	8,102		9,137		8,168
Natural Gas (MMcf)	12,339		12,915		14,114
NGLs (MBbls)	2,142		2,240		2,498
Total Eagle Ford Shale (MBoe)	12,301		13,530		13,018
Northeastern Utah
Oil (MBbls)	3,730		4,269		4,493
Natural Gas (MMcf)	11,970		11,708		11,992
NGLs (MBbls)	1		4		4
Total Northeastern Utah (MBoe)	5,726		6,224		6,495
Permian
Oil (MBbls)	2,250		3,318		4,168
Natural Gas (MMcf)	17,672		20,169		20,117
NGLs (MBbls)	2,639		2,980		2,959
Total Permian (MBoe)	7,834		9,660		10,480
Other
Oil (MBbls)	1		2		4
Natural Gas (MMcf)	78		121		133
NGLs (MBbls)	3		3		5
Total Other (MBoe)	17		25		31
Prices and Costs per Unit:(1)
Oil Average Realized Sales Price ($/Bbl)
Physical Sales	$	56.08	$	62.34	$	48.23
Including Financial Derivatives(2)	$	56.67	$	60.37	$	53.50
Natural Gas Average Realized Sales Price ($/Mcf)
Physical Sales	$	1.16	$	1.66	$	2.32
Including Financial Derivatives(2)	$	1.56	$	1.96	$	2.47
NGLs Average Realized Sales Price ($/Bbl)
Physical Sales	$	13.02	$	22.88	$	18.87
Including Financial Derivatives(2)	$	13.02	$	21.79	$	18.46
Average Transportation Costs
Oil ($/Bbl)	$	1.83	$	1.80	$	1.86
Natural Gas ($/Mcf)	$	1.58	$	1.56	$	1.79
NGLs ($/Bbl)	$	0.12	$	0.08	$	0.15
Average Lease Operating Expenses ($/Boe)(3)	$	5.34	$	5.35	$	5.42
Average Production Taxes ($/Boe)	$	2.03	$	2.47	$	2.02

(1) For the years ended December 31, 2019 and 2017, 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 oil sales. Natural gas prices for the years ended December 31, 2019, 2018 and 2017 reflect operating revenues for natural gas reduced by less than $1 million, less than $1 million and $2 million, respectively, for natural gas purchases associated with managing our physical sales.

(2) Includes actual cash settlements related to financial derivatives. 

(3) Includes approximately $0.07 per Boe of adjustments under a joint venture agreement for the year ended December 31, 2018.

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Acquisition, Development and Exploration Expenditures

See Part II, Item 8, “Financial Statements and Supplementary Data” under the heading Supplemental Oil and Natural Gas Operations in the Total Costs Incurred table for details on our acquisition, development and exploration expenditures.

Transportation, Markets and Customers

Our marketing strategy seeks to ensure maximum deliverability of our physical production at the maximum realized prices. We leverage knowledge of markets and transportation infrastructure to enter into beneficial downstream processing, treating and marketing contracts. We primarily sell our domestic oil and natural gas production to third parties at spot market prices, while we sell our NGLs at market prices under monthly or long-term contracts. We typically sell our oil production to a relatively small number of creditworthy counterparties, as is customary in the industry. For the year ended December 31, 2019, nine purchasers accounted for approximately 89% of our oil revenues. The top two purchasers are: Shell Trading U.S. Co. (an affiliate of Shell Oil Company) and Flint Hills Resources, LP (an affiliate of Koch Industries), which together accounted for approximately 47% of our oil revenues. Across all of our areas, we maintain adequate gathering, treating, processing and transportation capacity, as well as downstream sales arrangements, to accommodate our production volumes.

In our Eagle Ford Shale area, we are connected to the Camino Real oil gathering system and to the NuStar Energy system.  The majority of our oil production flows on Camino Real, a 68-mile long pipeline with over 110,000 Bbls/d of capacity and a gravity bank that allows for oil blending to maintain attractive API levels. We have 80,000 Bbls/d of firm capacity on this oil system, of which we utilized an average of 24% during December 2019 and 29% on average for the year.  The system delivers oil to the Storey Oil Terminal east of Cotulla, Texas, southeast of Gardendale, Texas.  From the Storey Oil Terminal, oil can be pumped into Harvest’s Arrowhead #1 and/or #2 pipelines, as well as the Plains All American Pipeline connection to the Gardendale Hub.  Oil can also be loaded into trucks out of the Storey Oil Terminal or out of the numerous central tank batteries throughout our field, providing additional deliverability, reliability and flexibility.  We currently market our oil either at the Storey Oil Terminal, Gardendale or at our central tank batteries under a combination of short and long-term contracts, ranging from monthly deals to multi-year term sales. With adequate takeaway capacity in the region and close proximity to the Gulf Coast refining complex, we believe we have sufficient capacity on our contracts and do not anticipate any issues with marketing and delivering volumes from the Eagle Ford Shale. 

Our Eagle Ford natural gas production flows on either the Camino Real gas gathering system or the Frio LaSalle Pipeline system with the majority flowing on the Camino Real gas gathering system. The Camino Real gas gathering system receives high-pressure, unprocessed wellhead gas into an 83-mile pipeline with capacity up to 150 MMcf/d.  The gas is then redelivered into interconnects with ETC Texas Pipeline LTD, Enterprise Hydrocarbons LP, Regency Energy Partners LP and Eagle Ford Gathering LLC.  We currently have 125 MMcf/d of firm transportation capacity on Camino Real, of which we used an average of 35% during December 2019 and 33% on average for the year, and we have additional capacity available as needed.  We have firm gas gathering, processing and transportation agreements on three of the interconnected gas pipelines downstream of the Camino Real system, with a minimum capacity of approximately 100 MMBtu/d and rights to increase firm capacity as necessary.  In addition, gas produced from our northwest acreage position within the Eagle Ford area is connected to the Frio LaSalle Pipeline system, which provides access to firm H2S treating and processing.  Frio LaSalle can either return gas to the Camino Real system or, after processing, deliver to various Texas intrastate pipelines and a mix of interstates, such as Texas Eastern Transmission, Tennessee Gas Pipeline, and Transco. We market our physical gas to various purchasers at spot market prices. 

In NEU, the wax crude we produce is sold at the wellhead to multiple purchasers who transport the oil via truck to downstream refineries. We sell most of the oil we produce in the basin to Salt Lake City refineries under long-term sales agreements that accommodate our production forecasts. Our produced natural gas is gathered and processed at the Altamont plant, a third-party-owned processing facility, under a long-term sales agreement that provides for residue gas return for operational use.

In the Permian basin, we continue to leverage significant legacy gathering, processing and transportation infrastructure. For natural gas, we are connected to the West Texas Gas (WTG), DCP Midstream LP, Targa Pipeline Mid-Continent WestTex LLC and Cogent Midstream, LLC gathering systems, and we process a majority of our gas at the WTG Benedum & Sonora gas plants. We receive Waha pricing for our natural gas and Mt. Belvieu pricing for our NGLs. Our crude oil production facilities are connected to a third party oil gathering system that delivers to a Plains All American Pipeline at Owens Station in Reagan County, Texas, the Centurion Cline Shale Pipeline at Barnhart in Irion County, Texas and to the Magellan Longhorn pipeline in Crockett County, Texas. We sell our pipeline delivered crude to multiple purchasers under both short and long-term contracts at WTI-based pricing. We also maintain the capability to truck crude oil to those same purchasers under similarly-priced contracts to provide additional flow assurance. Given current Permian basin takeaway capacity, we anticipate no limitations moving physical crude oil to market.

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While most of our physical production is priced off spot market indices, we actively manage the volatility of spot market pricing through our risk management program. We enter into financial derivatives contracts on our oil, natural gas and a portion of our NGLs production to stabilize our cash flows, reduce the risk of downward commodity price movements and protect the economic assumptions associated with our capital investment program. We employ a disciplined risk management program that utilizes risk control processes. For a further discussion of these risk management activities and derivative contracts, see Part II, Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations”.

Competitors

The exploration and production business is highly competitive in the search for and acquisition of additional oil and natural gas reserves and in the sale of oil, natural gas and NGLs. Our competitors include major and intermediate sized oil and natural gas companies, independent oil and natural gas operators and individual producers or operators with varying scopes of operations and financial resources. Competitive factors include financial resources, price and contract terms, our ability to access drilling, completion and other equipment and our ability to hire and retain skilled personnel on a timely and cost effective basis. Ultimately, our future success in this business will be dependent on our ability to find and/or fund the acquisition and development of additional reserves at costs that yield acceptable returns on the capital invested.

Use of 3-D Seismic Data

Within our areas we have an inventory of approximately 1,473 square miles of 3-D seismic data providing approximately 48% coverage of our leased acreage in those areas. We use our 3-D seismic data to improve our geologic models for each area. In the Eagle Ford and the Permian, detailed maps of structural features (e.g., natural fractures, faulting and stratigraphic discontinuities) are used to position well bore laterals to optimally exploit oil bearing zones and navigate drilling hazards. In NEU, data analytics are run using 3-D seismic attributes to identify ideal locations in the reservoir and estimate resource distribution. Seismic data sets are continually updated to keep pace with technological advancements in seismic processing.

Regulatory Environment

Our oil and natural gas exploration and production activities are regulated at the federal, state and local levels in the United States. These regulations include, but are not limited to, those governing the drilling and spacing of wells, conservation, forced pooling and protection of correlative rights among interest owners.  We are also subject to various governmental safety and environmental regulations in the jurisdictions in which we operate.

Our operations under federal oil and natural gas leases are regulated by the statutes and regulations of the Department of the Interior (“DOI”) that currently impose liability upon lessees for the cost of environmental impacts resulting from their operations. Royalty obligations on all federal leases are regulated by the Office of Natural Resources Revenue within the DOI, which has promulgated valuation guidelines for the payment of royalties by producers. These laws and regulations affect the construction and operation of facilities, water disposal rights and drilling operations, among other items.  In addition, we maintain insurance to limit exposure to sudden and accidental pollution liability exposures.

Hydraulic Fracturing. Hydraulic fracturing is a process of pumping fluid and proppant (usually sand) under high pressure into deep underground geologic formations that contain recoverable hydrocarbons. These hydrocarbon formations are typically thousands of feet below the surface. The hydraulic fracturing process creates small fractures in the hydrocarbon formation. These fractures allow natural gas and oil to move more freely through the formation to the well and finally to the surface production facilities. We use hydraulic fracturing to maximize productivity of our oil and natural gas wells in our areas, and our proved undeveloped oil and natural gas reserves will be developed using hydraulic fracturing. For the year ended December 31, 2019, we incurred costs of approximately $95 million associated with hydraulic fracturing.

Hydraulic fracturing fluid is typically composed of over 99% water and proppant. The other 1% or less of the fluid is composed of additives that may contain acid, friction reducer, surfactant, gelling agent and scale inhibitor. We retain service companies to conduct such operations and we have worked with several service companies to evaluate, test and, where appropriate, modify our fluid design to reduce the use of chemicals in our fracturing fluid. We have worked closely with our service companies to provide voluntary and regulatory disclosure of our hydraulic fracturing fluids.

In order to protect surface and groundwater quality during the drilling and completion phases of our operations, we follow applicable industry practices and legal requirements of the applicable state oil and natural gas commissions with regard to well design, including requirements associated with casing steel strength, cement strength and slurry design. Our activities in the field are monitored by state and federal regulators. Key aspects of our field protection measures include: (i) pressure testing well construction and integrity, (ii) casing and cementing practices to ensure pressure management and separation of hydrocarbons from groundwater, and (iii) public disclosure of the contents of hydraulic fracturing fluids.

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In addition to these measures, our drilling, casing and cementing procedures are designed to prevent fluid migration and typically include some or all of the following:

• Our drilling process executes several repeated cycles conducted in sequence—drill, set casing, cement casing and then test casing and cement for integrity before proceeding to the next drilling interval.

• Conductor casing is drilled and cemented or driven in place. This string serves as the structural foundation for the well. Conductor casing is not necessary or required for all wells.

• Surface casing is set and is cemented in place. Surface casing is set on all wells. The purpose of the surface casing is to isolate and protect Underground Sources of Drinking Water (“USDW”) as identified by federal and state regulatory bodies. The surface casing and cement isolates wellbore materials from any potential contact with USDWs.

• Intermediate casing is set through the surface casing to a depth necessary to isolate abnormally pressured subsurface formations from normally pressured formations. Intermediate casing is not necessary or required for all wells. Our standard practices include cementing above any hydrocarbon bearing zone and performing casing pressure tests to verify the integrity of the casing and cement.

• Production casing is set through the surface and intermediate casing through the depth of the targeted producing formation. Our standard practices include pumping cement above the confining structure of the target zone and performing casing pressure tests and other tests to verify the integrity of the casing and cement. If any problems are detected, then appropriate remedial action is taken.

• With the casing set and cemented, a barrier of steel and cement is in place that is designed to isolate the wellbore from surrounding geologic formations. This barrier as designed mitigates against the risk of drilling or fracturing fluids entering potential sources of drinking water.

In addition to the required use of casing and cement in the well construction, we follow additional regulatory requirements and industry operating practices. These typically include pressure testing of casing and surface equipment and continuous monitoring of surface pressure, pumping rates, volumes of fluids and chemical concentrations during hydraulic fracturing operations. When any pressure differential outside the normal range of operations occurs, pumping is shut down until the cause of the pressure differential is identified and any required remedial measures are completed. Hydraulic fracturing fluid is delivered to our sites in accordance with the U.S. Department of Transportation (“DOT”) regulations in DOT approved shipping containers using DOT transporters.

We also have procedures to address water use and disposal. This includes evaluating surface and groundwater sources, commercial sources, and potential recycling and reuse of treated water sources. When commercially and technically feasible, we use recycled or treated water. This practice helps mitigate against potential adverse impacts to other water supply sources. When using raw surface or groundwater, we obtain all required water rights or compensate owners for water consumption. We are evaluating additional treatment capability to augment future water supplies at several of our sites. During our drilling and completions operations, we manage waste water to minimize environmental risks and costs. Flowback water returned to the surface is typically contained in steel tanks or pits. Water that is not treated for reuse is typically piped or trucked to waste disposal injection wells, a number of which we operate. These wells are permitted through the Underground Injection Control (“UIC”) program of the Safe Drinking Water Act (“SDWA”). We also use commercial UIC permitted water injection facilities for flowback and produced water disposal.

We have not received regulatory citations or notice of suits related to our hydraulic fracturing operations for environmental concerns. We have not experienced a surface release of fluids associated with hydraulic fracturing that resulted in material financial exposure or significant environmental impact. Consistent with local, state and federal requirements, releases are reported to appropriate regulatory agencies and site restoration completed. No remediation reserve has been identified or anticipated as a result of hydraulic fracturing releases experienced to date.

Spill Prevention/Response Procedures. There are various state and federal regulations that are designed to prevent and respond to any spills or leaks resulting from exploration and production activities. In this regard, we maintain spill prevention control and countermeasures programs, which frequently include the installation and maintenance of spill containment devices designed to contain spill materials on location. In addition, we maintain emergency response plans to minimize potential environmental impacts in the event of a spill or leak or any significant hydraulic fracturing well control issue.

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Environmental

A description of our environmental remediation activities is included in Part II, Item 8, “Financial Statements and Supplementary Data”, Note 9.

Employees

As of March 20, 2020, we had 370 full-time employees in the United States.

Information about our Executive Officers

Our executive officers as of March 20, 2020, are listed below.

Name	Office	Age
Russell E. Parker	President, Chief Executive Officer and Director	43
Raymond J. Ambrose	Senior Vice President, Engineering and Subsurface	47
Chad D. England	Senior Vice President, Operations	40
Kyle A. McCuen	Senior Vice President, Chief Financial Officer and Treasurer	45
Jace D. Locke	Vice President, General Counsel and Corporate Secretary	43

Russell E. Parker

Mr. Parker has been our President and Chief Executive Officer and has served as a member of the Board since November 6, 2017. He was previously Chief Executive Officer of Phoenix Natural Resources LLC (Phoenix), from March 2016 to October 2017. Mr. Parker was the President of Chief Oil & Gas LLC from March 2015 to December 2015, and prior to becoming President, was Vice President of Engineering and Operations from October 2014 to March 2015 and Vice President of Engineering from November 2012 to October 2014. From January 2001 to October 2012, Mr. Parker worked in various engineering and asset management capacities for Hilcorp Energy Company (Hilcorp). Mr. Parker received his BS in Petroleum and Geosystems from the University of Texas at Austin, where he also was recognized as an Outstanding Young Graduate of the Cockrell School of Engineering as well as Distinguished Alumnus of the Petroleum Engineering Department.

Raymond J. Ambrose

Dr. Ambrose has been our Senior Vice President, Engineering and Subsurface since November 6, 2017. He was previously Senior Vice President, Engineering and Business Development for Phoenix from April 2016 to October 2017. Dr. Ambrose worked as Senior Director, Petroleum Engineering for NRG Energy, Inc., from April 2015 until joining Phoenix and as the Chief Reservoir Engineer for Hilcorp from March 2012 to March 2015. Dr. Ambrose earned a BS in chemical engineering with a petroleum minor and an MS in petroleum engineering from the University of Southern California and a PhD from the University of Oklahoma where his dissertation was focused on unconventional gas storage phenomena and rate transient analysis of unconventional reservoirs.

Chad D. England

Mr. England has been our Senior Vice President, Operations, since November 6, 2017. He was previously Senior Vice President of Operations for Phoenix from April 2016 to November 2017. Mr. England worked for Hilcorp as an Operations Manager from September 2010 to April 2016 on the Eagle Ford, Utica and South Texas asset teams. Prior to Hilcorp, he held engineering positions for ConocoPhillips from October 2006 to September 2010. Mr. England received his BS in Mechanical Engineering from Texas A&M University.

Kyle A. McCuen

Mr. McCuen has been our Senior Vice President, Chief Financial Officer and Treasurer since January 1, 2018. He was our interim Chief Financial Officer from February 2017 to December 2017, and our Vice President and Treasurer since August 2013. He was Vice President and Treasurer of EP Energy LLC from May 2012 to August 2013. He previously served in various finance and strategic planning roles at El Paso Corporation, most recently serving as Vice President of Corporate and E&P Planning at El Paso Corporation from October 2011 to May 2012. Mr. McCuen graduated from the University of Texas with a BBA and received an MBA from the University of Houston.

Jace D. Locke

Mr. Locke has been our Vice President, General Counsel and Corporate Secretary since January 1, 2018. He was our Associate General Counsel and Assistant Secretary from August 2013 to December 2017 and was Associate General Counsel and

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Assistant Secretary for EP Energy LLC from May 2012 to August 2013. He previously served as Senior Counsel at El Paso Corporation from November 2007 to May 2012, which included service as Corporate Secretary of El Paso’s midstream business unit. Prior to joining El Paso Corporation, Mr. Locke served as an associate at the international law firm of Dewey & LeBoeuf LLP from June 2002 to October 2007. Mr. Locke graduated from the University of Utah with a BS in Political Science and received a JD from Brigham Young University.

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 our Board members, each of our Board’s standing committee charters, and our Corporate Governance Guidelines 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

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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.

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

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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.

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

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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.

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;

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• 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;

• 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.

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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 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 the 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;

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• 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

• 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:

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• unexpected drilling conditions;

• delays imposed by or resulting from compliance with regulatory and contractual requirements, including requirements on sourcing of materials;

• 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.

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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 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

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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 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

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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 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.

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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 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

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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.

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;

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• allowable production from wells;

• unitization or pooling of oil and gas properties;

• spill prevention plans;

• 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.

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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 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.

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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. 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

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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 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

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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 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

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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) 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

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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.

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;

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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.

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

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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 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”, and is incorporated herein by reference. 

We believe that we have satisfactory title to the properties owned and used in our businesses, subject to liens for taxes not yet payable, liens incident to minor encumbrances, liens for credit arrangements and easements and restrictions that do not materially detract from the value of these properties, our interests in these properties or the use of these properties in our businesses. We believe that our properties are adequate and suitable for the conduct of our business in the future.

ITEM 3.    LEGAL PROCEEDINGS

A description of our material legal proceedings is included in Part II, Item 8. “Financial Statements and Supplementary Data”, Note 9, 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 common stock started trading on the New York Stock Exchange under the symbol EPE on January 17, 2014. On June 7, 2019, a Form 25 relating to the delisting and deregistration under Section 12(b) of the Act of our Class A common stock was filed by the New York Stock Exchange LLC. Our Class A common stock trades on the OTC Pink Sheets Market.

As of February 28, 2020, we had 30 stockholders of record, which does not include beneficial owners whose shares are held by a clearing agency, such as a broker or bank.

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 Corporation 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, which are further described in Part I, Item I. “Business”.

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 accretiveacquisitionopportunities 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;

• 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

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• 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 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

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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.

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

40

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 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 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, 8 and 9.

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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			(139		)
Total cash flow from operations	$	227		$	422
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			—
Cash inflows from financing activities	$	1,221		$	2,090
Total cash inflows	$	1,448		$	2,704
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			2
Cash outflows from financing activities	$	924		$	1,740
Total cash outflows	$	1,442		$	2,722
Net change in cash, cash equivalents and restricted cash	$	6		$	(18	)

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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 decreased3.4 MBoe/d or (approximately 9%) due to fewer wells placed on production in the second half of 2018 through 2019, (ii) NEU equivalent volumes decreased1.4 MBoe/d or (approximately 8%) due to reduced drilling activity in 2019, and (iii) Permian equivalent volumes decreased5.0 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.

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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.

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Results of Operations

The information below reflects financial results for EP Energy Corporation 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	)

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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.

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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.

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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, 2019decreased 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 11), 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, 2019decreased 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, 2019increased 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 9) offset by $6 million in lower severance costs.

Depreciation, depletion and amortization expense.  Depreciation, depletion and amortization expense for the year ended December 31, 2019decreased 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 reserves recorded on completed projects. Our average depreciation, depletion and amortization costs per unit for the year-to-date periods were:

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	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, 2019decreased 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, 2019increased 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, non-deductible compensation expenses, and a non-deductible loss carryover. 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.

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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 our long-term incentive programs), transition, severance and other costs that affect comparability, reorganization items, fees paid to our 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 10.

(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 9.

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Commitments and Contingencies

For a further discussion of our commitments and contingencies, see Part II, Item 8. “Financial Statements and Supplementary Data”, Note 9.

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

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$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 $1,064 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.

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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

• 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 6.

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

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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.

	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		%	—		%	—		%	—		%	—		%

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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
Management’s Annual Report on Internal Control over Financial Reporting	56
Report of Independent Registered Public Accounting Firm	57
Consolidated Statements of Income for the Years Ended December 31, 2019 and 2018	58
Consolidated Balance Sheets as of December 31, 2019 and December 31, 2018	59
Consolidated Statements of Cash Flows for the Years Ended December 31, 2019 and 2018	61
Consolidated Statements of Changes in Equity for the Years Ended December 31, 2019 and 2018	62
Notes to Consolidated Financial Statements
1.   Basis of Presentation and Significant Accounting Policies	63
1A.Voluntary Reorganization under Chapter 11 Cases	66
2.   Acquisitions and Divestitures	69
3.   Impairment Charges	70
4.   Income Taxes	70
5.   Earnings Per Share	72
6.   Fair Value Measurements	72
7.   Property, Plant and Equipment	74
8.   Debt	75
9.   Commitments and Contingencies	77
10. Incentive Compensation / 401(k) Retirement Plan	80
11. Related Party Transactions	81
Supplemental Financial Information
Supplemental Oil and Natural Gas Operations (Unaudited)	82
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.

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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.

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Report of Independent Registered Public Accounting Firm

To the Stockholders and 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 Corporation (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. 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

57

EP ENERGY CORPORATION (DEBTOR IN POSSESSION)

CONSOLIDATED STATEMENTS OF INCOME

(In millions, except per common share amounts)

	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	)
Basic and diluted net income (loss) per common share
Net loss	$	(3.77	)	$	(4.05	)
Basic and diluted weighted average common shares outstanding	250			248

See accompanying notes.

58

EP ENERGY CORPORATION (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.

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EP ENERGY CORPORATION (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 9)
Stockholders’ equity
Class A shares, $0.01 par value; 550 million shares authorized; 256 million shares issued and 255 million outstanding at December 31, 2019; 256 million shares issued and outstanding at December 31, 2018;	3			3
Class B shares, $0.01 par value; less than one million shares authorized, issued and outstanding at December 31, 2019 and December 31, 2018	—			—
Preferred stock, $0.01 par value; 50 million shares authorized; no shares issued or outstanding	—			—
Treasury stock (at cost); one million and less than one million shares at December 31, 2019 and December 31, 2018	(1		)	(1		)
Additional paid-in capital	3,545			3,536
Accumulated deficit	(5,080		)	(4,137		)
Total stockholders’ equity	(1,533		)	(599		)
Total liabilities and equity	$	3,710		$	4,181

See accompanying notes.

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EP ENERGY CORPORATION (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	)
Adjustments to reconcile net loss to net cash provided by operating activities
Depreciation, depletion and amortization	418			507
Gain on sale of assets	—			(3		)
Impairment charges	458			1,103
Gain on extinguishment/modification of debt	(10		)	(73		)
Write-off of debt discount and deferred issue costs	90			—
Reorganization items, net	24			—
Other non-cash income items	23			30
Asset and liability changes
Accounts receivable	85			(56		)
Owner and royalties payable	(72		)	32
Accounts payable and accrued expenses	21			(24		)
Derivative instruments	105			(109		)
Accrued interest	86			8
Other asset changes	(37		)	8
Other liability changes	(21		)	2
Net cash provided by operating activities	227			422
Cash flows from investing activities
Cash paid for capital expenditures	(497		)	(690		)
Proceeds from the sale of assets	—			192
Cash paid for acquisitions	(21		)	(292		)
Net cash used in investing activities	(518		)	(790		)
Cash flows from financing activities
Proceeds from issuance of long-term debt	923			2,090
Repayments and repurchases of long-term debt	(765		)	(1,654		)
Proceeds from borrowing under DIP Facility	298			—
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		)	(2		)
Net cash provided by financing activities	297			350
Change in cash, cash equivalents and restricted cash	6			(18		)
Cash, cash equivalents and restricted cash - beginning of period	27			45
Cash, cash equivalents and restricted cash - end of period	$	33		$	27
Supplemental cash flow information
Interest paid, net of amounts capitalized	$	226		$	337
Income tax refunds	—			(9		)

See accompanying notes.

61

EP ENERGY CORPORATION (DEBTOR IN POSSESSION)

CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY

(In millions) 

	Class A Stock				Class B Stock			Treasury Stock			Additional Paid-in Capital		Retained Earnings (Accumulated Deficit)
	Shares		Amount		Shares	Amount										Total
Balance at December 31, 2017	252		$	3	0.3	—		$	(3	)	$	3,526	$	(3,134	)	$	392
Share-based compensation	4		—		—	—		2			10		—			12
Net loss	—		—		—	—		—			—		(1,003		)	(1,003		)
Balance at December 31, 2018	256		$	3	0.3	—		$	(1	)	$	3,536	$	(4,137	)	$	(599	)
Share-based compensation	(1	)	—		—	—		—			9		—			9
Net loss	—		—		—	—		—			—		(943		)	(943		)
Balance at December 31, 2019	255		$	3	0.3	$	—	$	(1	)	$	3,545	$	(5,080	)	$	(1,533	)

See accompanying notes.

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EP ENERGY CORPORATION (DEBTOR IN POSSESSION)

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

1.    Basis of Presentation and Significant Accounting Policies

Basis of Presentation and Consolidation

Our consolidated financial statements are prepared in accordance with United States generally accepted accounting principles (“U.S. GAAP”) and include the accounts of all consolidated subsidiaries after the elimination of all significant intercompany accounts and transactions. 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. The consolidated financial statements included herein have been prepared as if we were a going concern and in accordance with Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) Topic No. 852, Reorganizations. For a further discussion of our Chapter 11 filing, see Note 1A.

We consolidate entities when we have the ability to control the operating and financial decisions of the entity or when we have a significant interest in the entity that gives us the ability to direct the activities that are significant to that entity. The determination of our ability to control, direct or exert significant influence over an entity involves the use of judgment.

We are engaged in the exploration for and the acquisition, development, and production of oil, natural gas and NGLs in the United States. Our oil and natural gas properties are managed as a single operating segment rather than through discrete operating segments or business units. We track basic operational data by area and allocate capital resources on a project-by-project basis across our entire asset base without regard to individual areas.  We assess financial performance as a single enterprise and not on a geographical area basis.

New Accounting Pronouncements Issued But Not Yet Adopted

Income Taxes. In December 2019, the FASB issued ASU No. 2019-12, Income Taxes (Topic 740): Simplifying the Accounting for Income Taxes, which is intended to simplify various aspects related to accounting for income taxes by eliminating certain exceptions within ASC 740, Income Taxes, and clarifying certain aspects of the current guidance. This standard is effective beginning for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2020, with early adoption permitted. The Company is in the process of assessing the impact the adoption of this guidance may have on our consolidated financial statements.

Significant Accounting Policies

Use of Estimates

The preparation of our financial statements requires the use of estimates and assumptions that affect the amounts we report as assets, liabilities, revenues and expenses and our disclosures in these financial statements. Actual results can, and often do, differ from those estimates.

Revenue Recognition

Our revenues are generated primarily through the physical sale of oil, natural gas and NGLs to third party customers at spot or market prices under both short and long-term contracts. We recognize revenue upon satisfaction of our contractual performance obligation requiring us to deliver oil, natural gas and NGLs to a delivery point. Our performance obligation is satisfied upon transfer of control of the commodity to the customer. Transfer of control varies depending on the product and delivery method, but typically occurs when delivery and passage of title and risk of loss have occurred at a pipeline or gathering line delivery point interconnect when delivered via pipeline or at the wellhead or tank battery to purchasers who transport the oil via truck. Realized prices for each barrel of oil, MMcf of natural gas or MMBtu of NGLs are based upon index prices (WTI, LLS, Henry Hub and Mt. Belvieu) or refiners' posted prices at various delivery points across our producing basins. Realized transaction prices received (not considering the effects of hedges) are generally less than the stated index price as a result of contractual deductions, differentials from the index to the delivery point, adjustments for time, and/or discounts for quality or grade.

Revenue is recorded net of any royalty interests or other profit interests in the produced product. Revenues related to products delivered, but not yet billed, are estimated each month. These estimates are based on contract data, commodity prices and preliminary throughput and allocation measurements. When actual sales volumes exceed our entitled share of sales volumes, an overproduced imbalance occurs. To the extent the overproduced imbalance exceeds our share of the remaining estimated proved natural gas reserves for a given property, we record a liability. 

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Costs associated with the transportation and delivery of production between the wellhead and its intended sale location are generally included in transportation costs.  We also purchase and sell oil and natural gas on a monthly basis to manage our overall oil and natural gas production and sales. These transactions are undertaken to optimize prices we receive for our oil and natural gas, to physically move oil and gas to its intended sales point, or to manage firm transportation agreements. Revenue related to these transactions are recorded in oil and natural gas sales in operating revenues and associated purchases reflected in oil and natural gas purchases in operating expenses in our consolidated income statements.

For the years ended December 31, 2019 and 2018, we had two and three customers, respectively, that individually accounted for 10 percent or more of our total revenues. The loss of any one customer would not have an adverse effect on our ability to sell our oil, natural gas and NGLs production.

While most of our physical production is priced off of market indices, we actively manage the volatility of market pricing through our risk management program whereby we enter into financial derivatives contracts. All of our derivatives are marked-to-market each period. The change in the fair value of our commodity-based derivatives, as well as any realized amounts, are reflected in operating revenues as financial derivative revenues (see Derivatives below and Note 6).

Cash and Cash Equivalents and Restricted Cash

We consider short-term investments with an original maturity of less than three months to be cash equivalents. As of December 31, 2019, we had $1 million in restricted cash. As of December 31, 2018, we had no restricted cash.

Allowance for Doubtful Accounts

We establish provisions for losses on accounts receivable and for natural gas imbalances with other parties if we determine that we will not collect all or part of the outstanding balance. We regularly review collectability and establish or adjust our allowance as necessary using the specific identification method.

Oil and Natural Gas Properties

We account for oil and natural gas properties in accordance with the successful efforts method of accounting for oil and natural gas exploration and development activities.

Under the successful efforts method, we capitalize (i) lease acquisition costs, all development costs and exploratory drilling costs until results are determined, (ii) certain internal costs directly identified with the acquisition, successful drilling of exploratory wells and development activities, and (iii) interest costs related to financing oil and natural gas projects actively being developed until the projects are evaluated or substantially complete and ready for their intended use if the projects were evaluated as successful. Non-drilling exploratory costs, including certain geological and geophysical costs such as seismic costs and delay rentals, are expensed as incurred.

We provide for depreciation, depletion, and amortization on the basis of common geological structure or stratigraphic conditions applied to total capitalized costs, plus future abandonment costs, net of salvage value, using the unit of production method.  Lease acquisition costs are amortized over total proved reserves, while other exploratory drilling and all developmental costs are amortized over total proved developed reserves.

We evaluate capitalized costs related to proved properties upon a triggering event to determine if impairment of such properties is necessary.  Our evaluation of recoverability is made on the basis of common geological structure or stratigraphic conditions and considers estimated future cash flows primarily from all proved developed (producing and non-producing) and proved undeveloped reserves in comparison to the carrying amount of the proved properties. Estimated future cash flows are determined based on estimates of future oil and gas production, estimated or published commodity prices as of the date of the estimate, adjusted for geographical location, contractual and quality price differentials, and estimates of future operating and development costs. If the carrying amount of a property exceeds these estimated undiscounted future cash flows, the carrying amount is reduced to its estimated fair value through a charge to income. Fair value is calculated by discounting the estimated future cash flows using a risk-adjusted discount rate. This 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. Leasehold acquisition costs associated with non-producing areas are also assessed for impairment based on our estimated drilling plans and anticipated capital expenditures related to potential lease expirations.

Property, Plant and Equipment (Other than Oil and Natural Gas Properties)

Our property, plant and equipment, other than our assets accounted for under the successful efforts method, are recorded at their original cost of construction or, upon acquisition, at the fair value of the assets acquired. We capitalize the

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major units of property replacements or improvements and expense minor items. We depreciate our non-oil and natural gas property, plant and equipment using the straight-line method over the useful lives of the assets which range from four to seven years. 

Accounting for Asset Retirement Obligations

We record a liability for legal obligations associated with the replacement, removal or retirement of our long-lived assets in the period the obligation is incurred and is estimable. Our asset retirement liabilities are initially recorded at their estimated fair value with a corresponding increase to property, plant and equipment. This increase in property, plant and equipment is then depreciated over the useful life of the asset to which that liability relates. An ongoing expense is recognized for changes in the value of the liability as a result of the passage of time, which we record as depreciation, depletion and amortization expense in our consolidated income statements.

Accounting for Long-Term Incentive Compensation

We measure the cost of long-term incentive compensation based on the fair value of the award on the day it is granted.  Awards issued under our incentive compensation programs are recognized as either equity awards or liability awards based on their characteristics.  Expense is recognized in our consolidated financial statements as general and administrative expense over the period of service required by the award. See Note 10 for further discussion of our long-term incentive compensation.

Environmental Costs, Legal and Other Contingencies

Environmental Costs. We record environmental liabilities at their undiscounted amounts on our consolidated balance sheet in other current and long-term liabilities when we assess that remediation efforts are probable and the costs can be reasonably estimated. Estimates of our environmental liabilities are based on current available facts, existing technology and presently enacted laws and regulations, taking into consideration the likely effects of other societal and economic factors, and include estimates of associated legal costs. These amounts also consider prior experience in remediating contaminated sites, other companies’ clean-up experience and data released by the Environmental Protection Agency (EPA) or other organizations. Our estimates are subject to revision in future periods based on actual costs or new circumstances. We capitalize costs that benefit future periods and expense costs that do not in general and administrative expense.

We evaluate any amounts paid directly or reimbursed by government sponsored programs and potential recoveries or reimbursements of remediation costs from third parties, including insurance coverage, separately from our liability. Recovery is evaluated based on the creditworthiness or solvency of the third party, among other factors. When recovery is assured, we record and report an asset separately from the associated liability on our consolidated balance sheet.

Legal and Other Contingencies.  We recognize liabilities for legal and other contingencies when we have an exposure that indicates it is both probable that a liability has been incurred and the amount of the loss can be reasonably estimated. Where the most likely outcome of a contingency can be reasonably estimated, we accrue a liability for that amount. Where the most likely outcome cannot be estimated, a range of potential losses is established and if no one amount in that range is more likely than any other to occur, the low end of the range is accrued.

Derivatives

We enter into derivative contracts on our oil and natural gas products primarily to stabilize cash flows and reduce the risk and financial impact of downward commodity price movements on commodity sales.  Derivative instruments are reflected on our consolidated balance sheet at their fair value as assets and liabilities. We classify our derivatives as either current or non-current based on their anticipated settlement date. We net derivative assets and liabilities with counterparties where we have a legal right of offset.

All of our derivatives are marked-to-market each period and changes in the fair value of our commodity based derivatives, as well as any realized amounts, are reflected as operating revenues. We classify cash flows related to derivative contracts based on the nature and purpose of the derivative. As the derivative cash flows are considered an integral part of our oil and natural gas operations, they are classified as cash flows from operating activities. In our consolidated balance sheet, receivables and payables resulting from the settlement of our derivative instruments are reported as trade receivables and payables. See Note 6 for a further discussion of our derivatives.

Income Taxes

We record current income taxes based on our estimates of current taxable income and provide for deferred income taxes to reflect estimated future income tax payments and receipts. Changes in tax laws are recorded in the period they are enacted. Deferred taxes represent the tax impacts of differences between the financial statement and tax bases of assets and

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liabilities and carryovers at each year end. We classify all deferred tax assets and liabilities, along with any related valuation allowance, as non-current on the consolidated balance sheet. We account for tax credits under the flow-through method, which reduces the provision for income taxes in the year the tax credits first become available.

The realization of our deferred tax assets depends on recognition of sufficient future taxable income during periods in which those temporary differences are deductible. We record a valuation allowance against deferred tax assets when, based on our estimates, it is more likely than not that a portion of those assets will not be realized in a future period. The estimates utilized in recognition of deferred tax assets are subject to revision, either up or down, in future periods based on new facts or circumstances. In evaluating our valuation allowances, we consider cumulative book losses, the reversal of existing temporary differences, the existence of taxable income in carryback years, tax planning strategies and future taxable income for each of our taxable jurisdictions, the latter two of which involve the exercise of significant judgment. Changes to our valuation allowances could materially impact our results of operations.

1A. Voluntary Reorganization under 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 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 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

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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 further amended from time to time, the “Plan”) and an updated Disclosure Statement for Fourth Amended Joint Chapter 11 Plan of Reorganization of EP Energy Corporation and its Affiliated Debtors (as further 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 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 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 (“LCs”) 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.

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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.

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 (the “Exit Credit Agreement”).

Ability to Continue as a Going Concern. The significant risks and uncertainties related to the Company’s liquidity and the 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. Further, completion of a plan of reorganization could materially change the amounts and classifications of assets and liabilities reported in the consolidated financial statements. The accompanying consolidated financial statements have (i) been prepared on a going concern basis, which contemplates the realization of assets and satisfaction of liabilities and other commitments in the normal course of business and (ii) do not include any adjustments to reflect the possible future effects of this uncertainty on the recoverability or classification of recorded asset amounts or the amounts or classifications of liabilities.

Reorganization Items, Net. 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 have been expensed as incurred as reorganization items in our consolidated statements of income. For the year ended December 31, 2019, reorganization items, net were $65 million and consisted of:

	Year ended   December 31,   2019
	(in millions)
Professional fees	$	44
Rejection of executory contracts approved by Bankruptcy Court	16
DIP Facility costs	5
Total reorganization items, net	$	65

Liabilities subject to compromise. Prepetition unsecured and under-secured obligations that may be impacted by the Chapter 11 Cases have been classified as liabilities subject to compromise on our consolidated balance sheet. These liabilities are reported at the amounts expected to be allowed as claims by the Bankruptcy Court, although they may be settled for less or adjusted depending on Bankruptcy Court actions, further developments with respect to disputed claims, determination of secured status of certain claims, the determination as to the value of any collateral securing claims, proof of claims or other events. Differences between estimated liabilities recorded and claims filed, or to be filed, will be evaluated and resolved in connection with the claims resolution process and adjusted as necessary, and such adjustments may be material.

Liabilities subject to compromise includes allowed claims, prepetition accounts payable and other amounts related to the rejection of executory contracts approved by the Bankruptcy Court. Additional amounts may be included in liabilities subject to compromise in future periods if additional executory contracts and certain unexpired leases are rejected prior to

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emerging from bankruptcy. Based on the nature of potential allowed claims, future adjustments to amounts recorded as liabilities subject to compromise may be material.

As of December 31, 2019, liabilities subject to compromise were $2,932 million and consisted of:

	Year ended   December 31,   2019
	(in millions)
Senior secured 1.5 lien notes	$	2,092
Senior unsecured notes	688
Prepetition accrued interest on senior secured 1.5 lien and unsecured notes	117
Allowed claims, prepetition accounts payable and other	35
Total liabilities subject to compromise	$	2,932

As a result of the commencement of the Chapter 11 cases, the principal balance on the 1.5 lien notes and senior unsecured notes of $2,092 million and $688 million, respectively, as of December 31, 2019, has been reclassified as liabilities subject to compromise. Additionally, any prepetition accrued interest on the senior secured 1.5 lien notes and senior unsecured notes was also reclassified from accrued liabilities to liabilities subject to compromise as of December 31, 2019 as no interest payments have been made since the commencement of the Chapter 11 Cases or will be made in the future on these notes. Contractual interest expense amounts were $235 million for the year ended December 31, 2019, which is in excess of $211 million included in interest expense on the consolidated statements of income as a result of discontinuing the accrual of interest subsequent to the Petition Date on the senior secured 1.5 lien notes and senior unsecured notes.

2.    Acquisitions and Divestitures

Acquisitions. In 2018, we completed acquisitions of (i) producing properties and proved undeveloped acreage in Eagle Ford for approximately $246 million and (ii) additional working interests in certain producing properties in Eagle Ford for approximately $31 million. Our consolidated balance sheet reflects the cost of each of these assets acquired during the year as proved properties.

Divestitures. During 2018, we also completed the sale of certain assets in Northeastern Utah (“NEU”) for approximately $177 million. We treated this sale as a normal retirement reflecting the difference between net cash proceeds and the underlying net book value of the assets sold in accumulated depreciation rather than recording a gain on sale of assets.

3.    Impairment Charges

We evaluate capitalized costs related to proved properties upon a triggering event (e.g., a significant continued decline in forward commodity prices or significant reduction to development capital) to determine if an impairment of such properties has occurred. Commodity price declines may cause changes to our capital spending levels, production rates, levels of proved reserves and development plans, which may result in an impairment of the carrying value of our proved properties in the future.

For the year ended December 31, 2019, as a result of the filing of our Chapter 11 Cases (see Note 1A) and the uncertainties surrounding the availability of financing that would be available to develop our proved undeveloped reserves, we performed an impairment assessment of our asset groups under ASC 360. As a result, the undiscounted future cash flows related to our NEU proved properties were not in excess of the related carrying value of the asset. Accordingly, we have recorded a non-cash impairment charge of approximately $458 million related to this asset group, reflecting a reduction in the net book value of the proved property in this area to its estimated fair value.

During the fourth quarter of 2018, due to the significant reduction to future development capital in the Permian basin in light of the depressed oil price environment, we recorded non-cash impairment charges of approximately (i) $1,044 million on our proved properties, reflecting a reduction in the net book value of the proved property in this area to its estimated fair value and (ii) $59 million on our unproved properties.

Subsequent to December 31, 2019, the COVID-19 outbreak has had a material impact on the demand for oil and the price of oil has significantly decreased as a result of the decrease in demand and the failure of OPEC and Russia to reach an agreement with respect to production cuts. These recent events will continue to have an impact on oil price volatility, the scale and duration of which remain uncertain. If oil prices remain at or below current levels for an extended period of time, this may result in further impairments of the carrying value of our proved properties in the future.

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4.    Income Taxes

Pretax Income (Loss) and Income Tax (Expense) Benefit.  The tables below show the pretax loss and the components of income tax expense for the following periods:

	Year Ended December 31,
	2019			2018
	(in millions)
Pretax Loss	$	(943	)	$	(1,003	)
Components of Income Tax Expense
Current
Federal	$	—		$	—
State	—			—
	$	—		$	—
Deferred
Federal	$	—		$	—
State	—			—
Total income tax expense	$	—		$	—

Effective Tax Rate Reconciliation.  Our income taxes included in net income differ from the amount computed by applying the statutory federal income tax rate of 21% for the following reasons:

	Year Ended December 31,
	2019			2018
	(in millions)
Income taxes at the statutory federal rate	$	198		$	211
Increase (decrease)
State income taxes, net of federal income tax effect	11			8
Change in valuation allowance	(207		)	(213		)
Capital loss expiration	—			(5		)
Other	(2		)	(1		)
Income tax expense	$	—		$	—

The effective tax rate for both the years ended December 31, 2019 and 2018 was 0%. Our effective tax rate differed from the statutory rate of 21% primarily due to the change in our valuation allowance on our net deferred tax assets, non-deductible compensation expenses, and a non-deductible loss carryover. 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.

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Deferred Tax Assets and Liabilities.  The following are the components of net deferred tax assets and liabilities:

	December 31,   2019			December 31,   2018
	(in millions)
Deferred tax assets
Property, plant and equipment	$	238		$	157
Net operating loss carryovers	642			611
Employee benefits	1			2
Lease obligations	4			—
Legal and other reserves	17			9
Asset retirement obligations	10			9
Interest deduction limitation	125			76
Transaction costs	33			14
Total deferred tax assets	1,070			878
Valuation allowance	(1,064		)	(857		)
Net deferred tax assets	6			21
Deferred tax liabilities
Operating lease assets	4			—
Financial derivatives	2			21
Total deferred tax liabilities	6			21
Net deferred tax liabilities	$	—		$	—

Unrecognized Tax Benefits. At December 31, 2019 and 2018, the total amount of unrecognized tax benefits was $46 million and $0, respectively. The $46 million recorded in 2019 related to tax positions taken in the current year and reflects the potential impact on the classification of certain tax attributes recorded within the components of net deferred assets and liabilities.  We do not expect the settlement of the unrecognized tax benefit to have an impact on the Company's earnings or liquidity. 

We did not recognize any interest and penalties related to unrecognized tax benefits (classified as income taxes in our consolidated income statement) in 2019 or 2018, nor do we have any accrued interest and penalties associated with income taxes in our consolidated balance sheets as of December 31, 2019 and 2018. The Company's and certain subsidiaries' income tax years after 2015 remain open and subject to examination by both federal and state tax authorities.

Net Operating Loss and Tax Credit Carryovers. The table below presents the details of our federal and state net operating loss carryover periods as of December 31, 2019 (in millions): 

	Expiration Period
	2031 - 2037		No expiration(1)		Total
U.S. federal net operating loss carryover(1)	$	2,524	$	429	$	2,953

	2026 - 2038
State net operating loss carryover	$	480

(1) U.S. federal net operating loss carryovers generated since 2018 do not expire but are limited to 80% of taxable income per year.

At December 31, 2019, we have no federal net operating loss carryovers subject to the limitations provided under Sections 382 of the Internal Revenue Code. Additionally, there are no alternative minimum tax credits at December 31, 2019.

Valuation Allowances. As of December 31, 2019 and 2018, we have a valuation allowance on our deferred tax assets of $1,064 million and $857 million, respectively. These amounts are recorded based on our evaluation of whether it was more likely than not that our deferred tax assets would be realized. Our evaluations considered cumulative book losses, the reversal of existing temporary differences, the existence of taxable income in prior carryback years, tax planning strategies and future taxable income for each of our taxable jurisdictions.

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5.    Earnings Per Share

We exclude potentially dilutive securities from the determination of diluted earnings per share (as well as their related income statement impacts) when their impact on net income per common share is antidilutive. Potentially dilutive securities consist of our stock options, restricted stock, performance share unit awards and performance unit awards. For both the years ended December 31, 2019 and 2018, we incurred net losses and accordingly excluded all potentially dilutive securities from the determination of diluted earnings per share as their impact on loss per common share was antidilutive.

6.    Fair Value Measurements

We use various methods to determine the fair values of our financial instruments. The fair value of a financial instrument depends on a number of factors, including the availability of observable market data over the contractual term of the underlying instrument. We separate the fair value of our financial instruments into three levels (Levels 1, 2 and 3) based on our assessment of the availability of observable market data and the significance of non-observable data used to determine fair value. Each of the levels are described below:

• Level 1 instruments’ fair values are based on quoted prices in actively traded markets.

• Level 2 instruments’ fair values are based on pricing data representative of quoted prices for similar assets and liabilities in active markets (or identical assets and liabilities in less active markets).

• Level 3 instruments’ fair values are partially calculated using pricing data that is similar to Level 2 instruments, but also reflect adjustments for being in less liquid markets or having longer contractual terms.

The following table presents the carrying amounts and estimated fair values of our financial instruments:

	December 31, 2019				December 31, 2018
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	(in millions)
Debt obligations:
Debtor-in-possession credit facility(1)	$	148	$	148	$	—	$	—
Liabilities subject to compromise(2)	$	2,780	$	53	$	—	$	—
Current portion of long-term debt(1)	$	1,815	$	1,285	$	58	$	44
Long-term debt(1)	$	—	$	—	$	4,380	$	2,532
Derivative instruments	$	9	$	9	$	114	$	114

(1) Current portion of long-term debt includes $315 million of the RBL Facility and the principal balance of the 2024 1.25 Lien Notes and 7.750% Senior Secured Notes due 2026 reflected in current portion of long-term debt on our balance sheet as of December 31, 2019. For a further discussion on our Chapter 11 Cases, reclassification of debt and DIP Facility, see Notes 1A and 8.

(2) Amount includes the principal balance on the 1.5 lien notes and senior unsecured notes totaling approximately $2,780 million reclassified as liabilities subject to compromise as of December 31, 2019.

For the years ended December 31, 2019 and 2018, the carrying amount of cash and cash equivalents, accounts receivable and accounts payable represent fair value because of the short-term nature of these instruments.  Our debt obligations (see Note 8) have various terms, and we estimated the fair value of debt (representing a Level 2 fair value measurement) primarily based on quoted market prices for the same or similar issuances, considering our credit risk.

Oil, Natural Gas and NGLs Derivative Instruments.  We attempt to mitigate a portion of our commodity price risk and stabilize cash flows associated with forecasted sales of oil, natural gas and NGLs through the use of financial derivatives. As of December 31, 2019, we had derivatives contracts in the form of fixed price swaps and three-way collars on 14 MMBbls of oil. As of December 31, 2018, we had derivative contracts for 16 MMBbls of oil and 26 TBtu of natural gas. In addition to the contracts above, we have derivative contracts related to locational basis differences on our oil production. None of our derivative contracts are designated as accounting hedges.

As of December 31, 2019 and 2018, all derivative financial instruments were classified as Level 2. Our assessment of the level of an instrument can change over time based on the maturity or liquidity of the instrument, which can result in a change in the classification level of the financial instrument.

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The following table presents the fair value associated with our derivative financial instruments as of December 31, 2019 and 2018.  All of our derivative instruments are subject to master netting arrangements which provide for the unconditional right of offset for all derivative assets and liabilities with a given counterparty in the event of default. We present assets and liabilities related to these instruments in our consolidated balance sheets as either current or non-current assets or liabilities based on their anticipated settlement date, net of the impact of master netting agreements.  On derivative contracts recorded as assets in the table below, we are exposed to the risk that our counterparties may not perform.

	Level 2
	Derivative Assets									Derivative Liabilities
	Gross Fair Value					Balance Sheet Location				Gross Fair Value					Balance Sheet Location
			Impact of Netting			Current		Non-current					Impact of Netting		Current		Non-current
			(in millions)										(in millions)
December 31, 2019
Derivative instruments	$	14	$	(5	)	$	9	$	—	$	(5	)	$	5	$	—	$	—
December 31, 2018
Derivative instruments	$	116	$	(2	)	$	101	$	13	$	(2	)	$	2	$	—	$	—

For the years ended December 31, 2019 and 2018, we recorded a derivative loss of $81 million and a derivative gain of $84 million, respectively. Derivative gains and losses on our oil, natural gas and NGLs financial derivative instruments are recorded in operating revenues in our consolidated income statements.

Credit Risk. We are subject to a risk of loss on our derivative instruments that could occur if our counterparties do not perform pursuant to the terms of their contractual obligations. We maintain credit policies with regard to our counterparties to minimize our overall credit risk. These policies require that we (i) evaluate potential counterparties’ financial condition to determine their credit worthiness; (ii) monitor our oil, natural gas and NGLs counterparties’ credit exposures; (iii) review significant counterparties' credit from physical and financial transactions on an ongoing basis; (iv) use contractual language that affords us netting or set-off opportunities to mitigate risk; and (v) when appropriate, require counterparties to post cash collateral, parent guarantees or letters of credit to minimize credit risk.  Our assets related to derivatives as of December 31, 2019 represent financial instruments from two counterparties, all of which are lenders associated with our RBL Facility with an “investment grade” (minimum Standard & Poor’s rating of BBB+ or better) credit rating. Subject to the terms of our RBL Facility, collateral or other securities are not exchanged in relation to derivatives activities with the parties in the RBL Facility.

Other Fair Value Considerations. During the years ended December 31, 2019 and 2018, we recorded non-cash impairment charges on our proved properties in NEU and on our proved and unproved properties in the Permian basin. The estimate of fair value of our proved oil and natural gas properties used to determine the impairment was estimated using a discounted cash flow model and other relevant financial and transactional market participant data. These estimates represented a Level 3 fair value measurement. Significant Level 3 inputs associated with the calculation of discounted cash flows used in the impairment analysis include management’s estimate of future crude oil and natural gas prices, production costs, development expenditures, anticipated production of proved reserves, appropriate risk-adjusted discount rates and other relevant data. See Notes 1 and 3 for a further discussion of our impairment charges.

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7.    Property, Plant and Equipment

Oil and Natural Gas Properties.  As of December 31, 2019 and 2018, we had approximately $3.4 billion and $3.8 billion, respectively, of total property, plant, and equipment, net of accumulated depreciation, depletion, and amortization on our balance sheet, substantially all of which relates to proved oil and natural gas properties.

Our capitalized costs related to proved oil and natural gas properties by area for the periods ended December 31 were as follows:

	2019			2018
	(in millions)
Proved
Eagle Ford	$	4,266		$	3,898
Northeastern Utah	1,331			1,659
Permian	1,791			1,787
Total Proved	7,388			7,344
Less accumulated depletion	(3,990		)	(3,607		)
Net capitalized costs for oil and natural gas properties	$	3,398		$	3,737

As of December 31, 2019, we did not have any suspended wells and as of December 31, 2018, suspended well costs were not material.

Asset Retirement Obligations.  We have legal asset retirement obligations associated with the retirement of our oil and natural gas wells and related infrastructure. We settle these obligations when production on those wells is exhausted, when we no longer plan to use them or when we abandon them. We accrue these obligations when we can estimate the timing and amount of their settlement.

In estimating the liability associated with our asset retirement obligations, we utilize several assumptions, including a credit-adjusted risk-free rate between 7 percent and 9 percent on a majority of our obligations and a projected inflation rate of 2.5 percent. Changes in estimates in the table below represent changes to the expected amount and timing of payments to settle our asset retirement obligations. Typically, these changes primarily result from obtaining new information about the timing of our obligations to plug and abandon oil and natural gas wells and the costs to do so, or reassessing our assumptions in light of changing market conditions. The net asset retirement liability as of December 31 on our consolidated balance sheet in other current and non-current liabilities and the changes in the net liability for the periods ended December 31 were as follows:

	2019			2018
	(in millions)
Net asset retirement liability at January 1	$	42		$	35
Liabilities incurred	1			1
Liabilities settled	(1		)	—
Accretion expense	3			3
Changes in estimate	—			3
Net asset retirement liability at December 31	$	45		$	42

Capitalized Interest.  Interest expense is reflected in our financial statements net of capitalized interest. We capitalize interest primarily on the costs associated with drilling and completing wells until production begins using a weighted average interest rate on our outstanding borrowings. Capitalized interest for both the years ended December 31, 2019 and 2018 was approximately $5 million. Subsequent to filing for Chapter 11 relief as further described in Note 1A, we only capitalize interest on those debt obligations for which interest will continue to be paid and which are not classified as liabilities subject to compromise.

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8.    Debt

Listed below are our debt obligations as of the periods presented:

	Interest Rate		December 31, 2019			December 31, 2018
			(in millions)
Prepetition RBL credit facility - due November 23, 2021(1)	Variable		$	315		$	100
Senior secured term loans:
2.0 Lien due April 30, 2019(2)	Variable		—			8
Senior secured notes:
1.5 Lien due May 1, 2024	9.375	%	1,092			1,092
1.25 Lien due November 29, 2024	8.00	%	500			500
1.5 Lien due February 15, 2025	8.00	%	1,000			1,000
1.125 Lien due May 15, 2026	7.75	%	1,000			1,000
Senior unsecured notes:
Due May 1, 2020	9.375	%	182			232
Due September 1, 2022	7.75	%	182			182
Due June 15, 2023	6.375	%	324			324
Unamortized discount and debt issue costs(3)			—			(95		)
Total debt			4,595			4,343
Current portion of long-term debt(3)			(1,815		)	(58		)
Amounts reclassified as liabilities subject to compromise(4)			(2,780		)	—
Total long-term debt			$	—		$	4,285
Debtor-in-possession facility	Variable		$	148		$	—

(1) Carries interest at a specified margin over LIBOR of 2.50%to 3.50%, based on borrowing utilization and 0.375% commitment fee on unused capacity. Such margins will fluctuate based on the utilization of the facility.

(2) Carries interest at a specified margin over the LIBOR of 3.50%, with a minimum LIBOR floor of 1.00%.  As of December 31, 2018, the effective interest rate for the term loan was 6.21%. In April 2019, we retired the note in full.

(3) Due to uncertainties at September 30, 2019 regarding default, event of default and cross-default provisions under our indentures and RBL Facility, we reclassified our debt as current and wrote off approximately $90 million in unamortized debt discount and debt issue costs in the third quarter 2019. Amounts written off are included in interest expense in the consolidated statement of operations.

(4) As a result of the Chapter 11 Cases, the principal balance on the 1.5 lien notes and senior unsecured notes of approximately $2,092 million and $688 million, respectively, has been reclassified as liabilities subject to compromise as of December 31, 2019. In addition, accrued and unpaid interest of approximately $117 million related to the 1.5 lien notes and senior unsecured notes has been reclassified from accrued liabilities to liabilities subject to compromise as of December 31, 2019. For a further discussion of the Chapter 11 Cases, see Note 1A.

Gain on extinguishment/modification of debt. During 2018, we completed an exchange of approximately $1.1 billion of certain senior unsecured notes for new 1.5 Lien Notes maturing in 2024. The exchange transaction was accounted for as a modification of debt and an extinguishment of debt depending on the senior unsecured notes exchanged. In conjunction with the exchange, we recorded a $12 million loss on debt considered modified for accounting purposes and a net gain of $53 million on debt considered extinguished for accounting purposes.

Additionally, during the year ended December 31, 2019 and 2018, we recorded a net gain on extinguishment/modification of debt of $10 million and $32 million, respectively, primarily related to repurchased debt. In the first quarter of 2019, we paid approximately $40 million in cash to repurchase a total of $50 million in aggregate principal amount of our senior unsecured notes due 2020. In 2018, we paid approximately $49 million in cash to repurchase a total of approximately $84 million in aggregate principal amount of our senior unsecured notes due 2022 and 2023.

Covenant Violations and Chapter 11 Cases. On August 15, 2019, we did not make the approximately $40 million cash interest payment due with respect to the 2025 1.5 Lien Notes. On September 3, 2019, we did not make the approximately $7 million cash interest payment due with respect to 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 RBL Facility.

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On September 14, 2019, we entered into forbearance agreements, extending through October 3, 2019, with the Noteholders and the RBL Forbearing Parties, pursuant to which each Noteholder and RBL Forbearing Party temporarily agreed, subject to certain terms and conditions, to forbear from exercising any rights or remedies they may have in respect of the failure to make the approximately $40 million cash interest payment.

On October 3, 2019, the Debtors filed the Chapter 11 Cases in the Bankruptcy Court seeking relief under the Bankruptcy Code. 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 the RBL Facility and indentures governing 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. For a further discussion of the Chapter 11 Cases, see Note 1A.

Debtor-in-possession financing. As noted in Note 1A, on November 25, 2019, EPE Acquisition, LLC and EP Energy LLC entered into a Senior Secured Superpriority Debtor-In-Possession 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 (as amended or modified from time to time, the “DIP Credit Agreement”). 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 commitments under the DIP Credit Agreement which provides for an approximately $315 million debtor-in-possession senior secured superpriority revolving credit facility, 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.

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.

The DIP Loans bear interest at a rate per annum equal to (i) adjusted LIBOR plus an applicable margin of 3.50% or (ii) an alternative base rate plus an applicable margin of 2.50%, in each case, as selected by EP Energy LLC. Any unused revolving commitments will be subject to a commitment fee at a rate per annum equal to 0.50% on the Available Commitment (as defined in the DIP Credit Agreement) in effect on such day. The DIP Facility is secured by a senior secured superpriority perfected security interest on substantially all assets of EP Energy LLC and any subsidiary guarantors. The security interests and liens are further subject to certain carve-outs and permitted liens, as set forth in the DIP Credit Agreement and the DIP Order.

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.

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9.    Commitments and Contingencies

Chapter 11 Cases

On October 3, 2019, the Debtors filed the Chapter 11 Cases in the Bankruptcy Code seeking relief under the Bankruptcy Code. We expect to continue operations in the normal course during the pendency of the Chapter 11 Cases. In addition, commencement of the Chapter 11 Cases automatically stayed all of the proceedings and actions against the Company, including those noted below. For a further discussion of the Chapter 11 Cases, see Note 1A. Any claims filed, or to be filed in relation to the Chapter 11 Cases, will be investigated and addressed in connection with the claims resolution process. The Company will continue to evaluate these liabilities throughout the Chapter 11 process and adjust amounts as necessary.

Legal Matters

We and our subsidiaries and affiliates are parties to various legal actions and claims that arise in the ordinary course of our business. For each matter, we evaluate the merits of the case or claim, our exposure to the matter, possible legal or settlement strategies and the likelihood of an unfavorable outcome.  If we determine that an unfavorable outcome is probable and can be estimated, we establish the necessary accruals. While the outcome of our current matters cannot be predicted with certainty and there are still uncertainties related to the costs we may incur, based upon our evaluation and experience to date, we believe we have established appropriate reserves for these matters. It is possible, however, that new information or future developments could require us to reassess our potential exposure and adjust our accruals accordingly, and these adjustments could be material. As of December 31, 2019, we had approximately $26 million accrued for all outstanding legal matters, which also represents our best estimate of the allowed claims for these legal matters which have been reclassified as liabilities subject to compromise on our balance sheet at December 31, 2019.

FairfieldNodal v. EP Energy E&P Company, L.P. On March 3, 2014, Fairfield filed suit against one of our subsidiaries in the 157th District Court of Harris County, Texas, claiming we were contractually obligated to pay a transfer fee of approximately $21 million for seismic licensing, triggered by a change in control with the Sponsors' acquisition of our predecessor entity in 2012. Prior to the change in control, we had unilaterally terminated the seismic licensing agreements, and we returned the applicable seismic data. Fairfield also claimed EP Energy did not properly maintain the confidentiality of the seismic data and interpretations made from it. In April 2015, the district court granted summary judgment to EP Energy, and Fairfield then appealed. On July 6, 2017, an intermediate court of appeals in Texas reversed the judgment related to the transfer fee and denied rehearing on October 5, 2017. We filed a petition for review in the Texas Supreme Court, which denied review in June 2019. We filed a motion for rehearing in the Texas Supreme Court on July 31, 2019. If denied, the case will be remanded to the trial court for further proceedings. As of December 31, 2019, we had accrued approximately $21 million related to this matter.

Storey Minerals, Ltd., et al. v. EP Energy E&P Company, L.P. On May 29, 2018, Storey Minerals, Ltd., Maltsberger/ Storey Ranch, LLC, and Rene R. Barrientos, Ltd. (collectively, “MSB”) filed suit against EP Energy in the 81st Judicial District Court of La Salle County, Texas. MSB alleged that by acquiring certain oil and gas leases within the perimeter of the Storey Altito Ranch, EP Energy triggered the most favored nation clause (“MFN clause”) in the leases. After investigation, EP Energy agreed that the MFN clause had been triggered and tendered a lease amendment with a check for $4 million for increased lease bonus. EP Energy's calculation confirmed that no delay rentals were due. MSB, however, did not accept the tender and asserts that the MFN clause operates retroactively to the date of the lease and applies to all of the acreage leased at that time. EP Energy maintains that the unambiguous language in the MFN clause operates prospectively and supports its tendered amendment and calculation. The parties filed cross-motions for summary judgment. In June 2019, the court entered an order agreeing with EP Energy on delay rentals, but with MSB on lease bonus. The court entered a final judgment in July 2019 ordering EP Energy to pay MSB $43.8 million in increased lease bonus, attorney’s fees, expenses and interest to date. EP Energy filed an appeal to the Fourth Circuit Court of Appeals in San Antonio, Texas on July 17, 2019 and intends to pursue fully its appeal. As of December 31, 2019, EP Energy's accrual of approximately $4 million related to this matter reflects the amount tendered to MSB with the lease amendment noted above, which EP Energy believes is the appropriate amount of increased bonus due to MSB.

Environmental Matters

We are subject to existing federal, state and local laws and regulations governing environmental quality, pollution control and greenhouse gas emissions. Numerous governmental agencies, such as the EPA, issue regulations which often require difficult and costly compliance measures that carry substantial administrative, civil and criminal penalties and may result in injunctive obligations for non-compliance. Our management believes that we are in substantial compliance with applicable environmental laws and regulations, and we have not experienced any material adverse effect from compliance with these environmental requirements. For additional details on certain environmental matters, including matters related to climate

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change, air quality and other emissions, hydraulic fracturing regulations and waste handling, refer to Part I, Item 1A. "Risk Factors".

While our reserves for environmental matters are currently not material, there are still uncertainties related to the ultimate costs we may incur in the future in order to comply with increasingly strict environmental laws, regulations, and orders of regulatory agencies, as well as claims for damages to property and the environment or injuries to employees and other persons resulting from our current or past operations. Based upon our evaluation and experience to date, however, we believe our accruals for these matters are adequate. It is possible that new information or future developments could result in substantial additional costs and liabilities which could require us to reassess our potential exposure related to these matters and to adjust our accruals accordingly, and these adjustments could be material.

Other Matters

As of December 31, 2019, we had approximately $12 million accrued (in other accrued liabilities in our consolidated balance sheet) related to other contingent matters including, but not limited to, a number of examinations by taxing authorities on non-income matters and indemnifications that we periodically enter into as part of the divestiture of assets or businesses. These arrangements include, but are not limited to, indemnifications for income taxes, the resolution of existing disputes and other contingent matters. In addition, the decline in commodity prices has created an environment where there is an increased risk that owners and/or operators of assets previously purchased from us may no longer be able to satisfy plugging and abandonment obligations that attach to such assets. In that event, under various laws or regulations, we could be required to assume all, or a portion of the plugging or abandonment obligations on assets we no longer own or operate.

Lease Obligations

In the first quarter of 2019, we adopted ASU No. 2016-02, Leases on a modified retrospective basis, allowing us to account for leases entered into before adoption under prior ASC 840 guidance. The adoption did not have a material impact on our consolidated financial statements, nor did the adoption result in a cumulative-effect adjustment to retained earnings. In addition, we made certain permitted elections upon adoption, the most significant of which were (i) exempting short-term leases (i.e., leases with an initial term of less than 12 months) from balance sheet recognition, (ii) maintaining existing accounting treatment for existing or expired land easements not previously accounted for as leases under prior guidance and (iii) accounting for lease and non-lease components in a contract as a single lease component when not readily determinable.

Our noncancellable leases classified as finance leases for accounting purposes include certain compressors under long-term arrangements which were capitalized upon commencement of the lease term at the fair value of the leased asset, which was lower than the present value of the minimum lease payments. The discount rate used for our finance leases was the incremental borrowing rate adjusted so that the present value of the corresponding lease payments did not exceed the fair value of the leased asset. For the year ended December 31, 2019, interest and depreciation expense associated with our finance leases were approximately $4 million and $3 million, respectively, and related cash payments were approximately $4 million.

Our noncancellable leases classified as operating leases and capitalized upon commencement of the lease term for accounting purposes include those for office space, drilling rigs and field equipment. The discount rate used for our operating leases is either the discount rate implicit in the contract, or the applicable interest rate on a collateralized basis if not determinable. Operating lease costs for minimum lease payments are recognized as capital or expense on a straight-line basis over the lease term depending on the nature of the payment. For the year ended December 31, 2019, operating lease costs and related cash payments were approximately $11 million and $10 million, respectively. These were primarily capitalized as part of our oil and natural gas properties. Variable lease costs (amounts incurred beyond minimum lease payments such as utilities, usage, maintenance, mobilization fees, etc.) are recognized in the period incurred. For the year ended December 31, 2019, variable lease cost was approximately $3 million.

Short-term lease cost for the year ended December 31, 2019 was approximately $20 million, and was primarily capitalized as part of our oil and natural gas properties.

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Supplemental balance sheet information related to leases was as follows:

	December 31, 2019
	(in millions)
Operating lease assets(1)(4)	$	18
Finance lease assets(2)	10
Total lease assets	$	28
Operating leases(3)(4)
Current liability	$	9
Noncurrent liability	9
Total operating lease liability	$	18
Finance leases(3)
Current liability	$	2
Noncurrent liability	9
Total finance lease liability	$	11
Weighted average remaining lease term
Operating leases	3 years
Finance leases	4 years
Weighted average discount rate
Operating leases	9.06		%
Finance leases	26.53		%

(1) Operating lease assets are reflected in Operating lease assets and other in our consolidated balance sheet as of December 31, 2019.

(2) Finance lease assets are reflected in Other property, plant and equipment in our consolidated balance sheet as of December 31, 2019.

(3) Current and noncurrent operating and finance lease liabilities are reflected in Other current liabilities and Lease obligations and other, respectively, in our consolidated balance sheet as of December 31, 2019.

(4) Upon adoption of ASU 2016-02 effective January 1, 2019, we recognized operating leases of approximately $10 million. For the year ended December 31, 2019, we also recorded an additional $16 million of operating leases.

Future minimum annual rental commitments under non-cancelable future operating and finance lease commitments at December 31, 2019, were as follows:

Year Ending December 31,	Operating Leases			Finance Leases
	(in millions)
2020	$	10		$	5
2021	3			5
2022	2			5
2023	2			2
Thereafter	4			—
Total	$	21		$	17
Less: imputed interest	(3		)	(6		)
Present value of operating and finance lease obligations	$	18		$	11

Rental expense for the year ended December 31, 2018 was $7 million.

Other Commercial Commitments

At December 31, 2019, we have various commercial commitments totaling $134 million primarily related to commitments and contracts associated with volume and transportation, completion activities and seismic activities. Our annual obligations under these arrangements are $44 million in 2020, $35 million in 2021, $27 million in 2022, $9 million in 2023, and $19 million thereafter.

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10.    Incentive Compensation / 401(k) Retirement Plan

Overview. Under our current stock-based compensation plans (the EP Energy Corporation 2014 Omnibus Incentive Plan and 2017 EP Energy Corporation Employment Inducement Plan), we may issue to our employees and non-employee directors various forms of long-term incentive (“LTI”) compensation including stock options, stock appreciation rights, restricted stock, restricted stock units, performance shares/units, incentive awards, cash awards, and other stock-based awards. We are authorized to grant awards of up to 36,832,525 shares of our common stock for awards under these plans, with 10,579,000 shares remaining available for issuance as of December 31, 2019. 

In addition, in conjunction with the acquisition of certain of our subsidiaries by Apollo and other private equity investors in 2012 (the Acquisition), we issued Class B shares (formerly management incentive units intended to constitute profits interests) which become payable only on the achievement of certain predetermined performance measures as further described below.  No additional Class B shares are available for issuance.

We record stock-based compensation expense as general and administrative expense over the requisite service period. For the years ended December 31, 2019 and 2018, we recognized pre-tax compensation expense related to our LTI programs, net of the impact of forfeitures of approximately $9 million and $14 million, respectively, and recorded an associated income tax benefit of $2 million and $4 million for the years 2019 and 2018, respectively.

Restricted stock.  We grant shares of restricted common stock which carry voting and dividend rights and may not be sold or transferred until they are vested. The fair value of our restricted stock is determined on the date of grant and these shares generally vest in equal amounts over three years from the date of the grant. A summary of the changes in our non-vested restricted shares for the year ended December 31, 2019 is presented below:

	Number of Shares		Weighted Average Grant Date Fair Value per Share
Non-vested at December 31, 2018	7,060,334		$	2.69
Granted	103,000		$	0.70
Vested	(2,648,390	)	$	3.22
Forfeited	(1,000,409	)	$	2.45
Non-vested at December 31, 2019	3,514,535		$	2.30

The total unrecognized compensation cost related to these arrangements at December 31, 2019 was approximately $6 million, which is expected to be recognized over a weighted average period of approximately two years.

Performance Share Units. As of December 31, 2019, we had 1,478,100 of outstanding performance share units (PSUs). The PSUs represent a contractual right to receive one share of EP Energy’s common stock if certain conditions are met, and the number of PSUs actually earned, if any, will be based upon achievement of specified stock price goals over a four-year performance period (grant date thru October 2021). For accounting purposes, the PSUs are treated as an equity award and will vest over a weighted average period of three years with expense recognized on an accelerated basis over the life of the award. Of the 1,478,100 PSU’s outstanding at December 31, 2019, 1,224,000 shares will remain subject to certain settlement and transfer restrictions from November 2021 through October 2024 unless certain conditions are satisfied.

The grant date fair value of the 2018 and 2017 awards was approximately $5 million and $12 million, respectively, as determined by a Monte Carlo simulation, utilizing multiple input variables that determine the probability of satisfying the market condition stipulated in the award. Volatility was based on life-to-date volatility of EP Energy’s common stock, which has been publicly traded for an amount of time less than the contractual term of the award. We estimated the risk free rate based on zero coupon U.S. Treasury STRIPS (Separate Trading of Registered Interest and Principal of Securities) that have a term equal to the length of the period from the valuation date to the final vest date. The following table summarizes the significant assumptions used to calculate the grant date fair value of the PSUs:

	2018 Awards		2017 Awards
Expected Term in Years	4		6
Expected Volatility	89.62	%	100.03	%
Risk-Free Interest Rate	2.75	%	1.89	%

Total compensation cost related to our non-vested performance share units not yet recognized at December 31, 2019 was $6 million, which is expected to be recognized over a weighted average period of two years.

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Key Employee Retention Program. On May 29, 2019, the Compensation Committee of the Board of Directors of the Company approved the implementation of a Key Employee Retention Program (a “KERP”) for all employees of the Company. KERP payments totaling approximately $21 million were made in July 2019 and were comprised of approximately $10 million in lieu of target bonus amounts for 2019 performance, which were already being accrued during the year, plus an incremental amount of approximately $11 million in lieu of long-term incentive compensation for 2019. KERP payments are subject to certain termination provisions through June 30, 2020 which would result in the repayment of the award in full.

As of December 31, 2019, our consolidated balance sheet reflects a deferred charge in the amount of approximately$10 million related to the KERP. For accounting purposes, deferred expense is being amortized over the 13-month term of the KERP agreement. During the year ended December 31, 2019, we recorded $10 million in expense related to the KERP.

Other. We have issued and/or granted, in prior periods, (i) Class B shares (including those issued to EPE Employee Holdings, II, LLC, a subsidiary), which payout only occurs on the achievement of certain predetermined performance measures (e.g., certain liquidity events in which our private equity investors receive a return of at least one times their invested capital plus a stated return), (ii) stock options at a strike price of $19.82 per share and (iii) total shareholder return (TSR) based performance units treated as liability awards. Due to both reductions in force affecting the holders of these awards and/or declines in stock price performance in recent years, these awards will not materially impact the company and as of December 31, 2019, we had (i) unrecognized compensation expense of $1 million related to Class B shares, which will only be recognized should the liquidity events described above occur and the right to such amounts become nonforfeitable and (ii) less than $1 million in unrecognized compensation cost for non-vested performance units, which is expected to be recognized over a weighted average period of less than one year.

401(k) Retirement Plan. We sponsor a tax-qualified defined contribution retirement plan for a broad-based group of employees.  We make matching contributions (dollar for dollar up to 6% of eligible compensation) and non-elective employer contributions (5% of eligible compensation) to the plan, and individual employees are also eligible to contribute to the defined contribution plan. During 2019 and 2018, we contributed $5 million and $6 million, respectively, of matching and non-elective employer contributions. 

11.    Related Party Transactions

Chapter 11 Cases. As of December 31, 2019, affiliates of Apollo held approximately $675 million of the aggregate outstanding principal amount of approximately $2,092 million of our 2024 1.5 Lien Notes and 2025 1.5 Lien Notes, and approximately $21 million of the outstanding principal amount of $500 million of our 2024 1.25 Lien Notes. As of December 31, 2019, affiliates of Access held approximately $48 million of our 1.5 lien notes. On October 18, 2019, we entered into the (i) PSA, to support a restructuring on the terms of the Plan described therein, and (ii) BCA, pursuant to which the Commitment Parties agreed to backstop the Rights Offering, in each case, with holders of certain of our debt, including affiliates of, or funds managed by, Apollo and Access. 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 the Stipulation. On March 23, 2020, the Bankruptcy Court approved the Stipulation. The Debtors are working with their constituents to explore various alternatives. For a discussion of the Chapter 11 Cases, refer to Note 1A.

Joint Venture. We are party to a drilling joint venture to fund future oil and natural gas development with Wolfcamp Drillco Operating L.P. (the Investor, which is managed and controlled by an affiliate of Apollo) and indirectly through Access (through an indirect minority ownership interest in the Investor). The Investor agreed to fund 60 percent of the estimated drilling, completion and equipping costs in the joint venture wells, divided into two approximately $225 million investment tranches, in exchange for a 50 percent working interest. We are the operator of the joint venture assets. Once the Investor achieves a 12 percent internal rate of return on its invested capital in each tranche, its working interest reverts to 15 percent.  In 2018, we completed the planned activity in the first tranche and amended the drilling joint venture to direct the second tranche investment to the Eagle Ford. As of the second quarter 2019, we had drilled and completed all wells under the amended agreement. For the years ended December 31, 2019 and 2018, we recovered approximately $91 million and $138 million, respectively, related to capital costs of the joint venture wells from the Investor. At December 31, 2019 and 2018, we had accounts receivable of $3 million and $47 million, respectively, from our Investor and accounts payable of $7 million and $20 million, respectively, to our Investor reflected in our consolidated balance sheet.

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Supplemental Oil and Natural Gas Operations (Unaudited)

We are engaged in the exploration for, and the acquisition, development and production of oil, natural gas and NGLs, in the United States (U.S.).

Capitalized Costs. Capitalized costs relating to domestic oil and natural gas producing activities and related accumulated depreciation, depletion and amortization were as follows at December 31 (in millions):

	2019		2018
Oil and natural gas properties	$	7,388	$	7,344
Less accumulated depreciation, depletion and amortization	3,990		3,607
Net capitalized costs(1)	$	3,398	$	3,737

(1) During the year ended December 31, 2019, we recorded non-cash impairment charges of approximately $458 million on our NEU proved properties. During 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.

Total Costs Incurred. Costs incurred in oil and natural gas producing activities, whether capitalized or expensed, were as follows for the years ended December 31, 2019 and 2018 (in millions):

	U.S.
2019:
Property acquisition costs
Proved properties	$	22
Unproved properties	—
Exploration costs (capitalized and expensed)	8
Development costs	495
Costs expended	525
Asset retirement obligation costs	1
Total costs incurred	$	526
2018:
Property acquisition costs
Proved properties	$	322
Unproved properties	—
Exploration costs (capitalized and expensed)	7
Development costs	649
Costs expended	978
Asset retirement obligation costs	1
Total costs incurred	$	979

We capitalize salaries and benefits that we determine are directly attributable to our oil and natural gas activities. The table above includes capitalized labor costs of $10 million and $14 million for the years ended December 31, 2019 and 2018, respectively, and capitalized interest of $5 million for both periods.

Oil and Natural Gas Reserves. We employed Ryder Scott Company, L.P. (“Ryder Scott”) to evaluate and prepare the estimates of our net proved reserves as of December 31, 2019.  Ryder Scott prepared 100% (by volume) of our total net proved developed reserves on a barrel of oil equivalent basis. The overall procedures and methodologies utilized by Ryder Scott in evaluating and preparing estimates of our net proved reserves as of December 31, 2019 complied with current SEC regulations. Ryder Scott’s report is included as an exhibit to this Annual Report on Form 10-K.

Net quantities of proved developed and undeveloped reserves of natural gas, oil and NGLs and changes in these reserves at December 31, 2019 presented in the tables below are based on Ryder Scott's report. Net proved reserves exclude royalties and interests owned by others and reflect contractual arrangements and royalty obligations in effect at the time of the estimate. Our 2019 proved reserves were consistent with estimates of proved reserves filed with other federal agencies in 2019 except for differences of less than five percent resulting from actual production, acquisitions, property sales, necessary reserve revisions and additions to reflect actual experience.

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As of December 31, 2019, the Company is not including PUD reserves in its total proved reserve estimates due to uncertainty regarding the Company's availability of capital prior to emerging from bankruptcy that would be required to develop the PUD reserves. Accordingly, we have not included forecasted capital spending to develop any PUD reserves.

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 the Stipulation. On March 23, 2020, the Bankruptcy Court approved the Stipulation. The Debtors are working with their constituents to explore various alternatives. We expect to report PUD reserves in the future to the extent we determine that we have the financial capability to execute a development plan to develop our PUD reserves. The actual amount and timing of our forecasted expenditures will depend on a number of factors, including actual drilling results, oilfield service costs, technology, acreage position, availability of capital and future commodity prices, which in the future could be lower than those in our projected long-range plan.

	Year Ended December 31, 2019(1)
	Natural Gas (in Bcf)		Oil (in MBbls)		NGLs (in MBbls)		Equivalent Volumes (in MMBoe)
Proved developed and undeveloped reserves
Beginning of year	574		168,657		60,054		324.5
Revisions due to prices	(48	)	(6,253	)	(6,165	)	(20.4	)
Revisions other than prices(2)	(141	)	(55,728	)	(9,669	)	(89.0	)
Purchase of reserves	1		316		100		0.5
Sales of reserves in place	—		(33	)	(10	)	—
Production	(42	)	(14,077	)	(4,782	)	(25.9	)
End of year	344		92,882		39,528		189.7
Proved developed reserves:
Beginning of year	434		111,201		49,942		233.6
End of year	344		92,882		39,528		189.7
Proved undeveloped reserves:
Beginning of year	140		57,455		10,111		90.9
End of year	—		—		—		—

(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) The 89 MMBoe of revisions other than prices primarily includes 77 MMBoe of negative revisions due to uncertainty regarding the Company's availability of capital prior to emerging from from bankruptcy and 12 MMBoe of negative revisions. The 12 MMBoe of negative revisions includes negative revisions of 7 MMBoe in the Eagle Ford, 3 MMBoe in NEU and 2 MMBoe in Permian.

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	Year Ended December 31, 2018(1)
	Natural Gas (in Bcf)		Oil (in MBbls)		NGLs (in MBbls)		Equivalent Volumes (in MMBoe)
Proved developed and undeveloped reserves
Beginning of year	652		203,865		79,477		392.1
Revisions due to prices	31		7,975		3,932		17.1
Revisions other than prices(2)	(75	)	(31,581	)	(23,268	)	(67.4	)
Purchase of reserves	31		14,902		5,285		25.4
Sales of reserves in place	(20	)	(9,785	)	(152	)	(13.3	)
Production	(45	)	(16,719	)	(5,220	)	(29.4	)
End of year	574		168,657		60,054		324.5
Proved developed reserves:
Beginning of year	372		114,282		41,989		218.3
End of year	434		111,201		49,942		233.6
Proved undeveloped reserves:
Beginning of year	280		89,584		37,489		173.8
End of year	140		57,455		10,111		90.9

(1) Proved reserves were evaluated based on the average first day of the month spot price for the preceding 12-month period of $65.56 per Bbl (WTI) and $3.10 per MMBtu (Henry Hub) and $23.60 per Bbl of NGLs.

(2) The 67 MMBoe of revisions other than prices primarily includes negative revisions of 74 MMBoe due to a reallocation of capital from the Permian to other development

areas and a positive revision of 12 MMBoe associated with increased drilling activity in the Eagle Ford and NEU.

In accordance with SEC Regulation S-X, Rule 4-10 as amended, we use the 12-month average price calculated as the unweighted arithmetic average of the spot price on the first day of each month preceding the 12-month period prior to the end of the reporting period. The first day 12-month average price used to estimate our proved reserves at December 31, 2019 was $55.69 per barrel of oil (WTI), $2.58 per MMBtu for natural gas (Henry Hub) and $13.37 per Bbl of NGLs.

All estimates of proved reserves are determined according to the rules prescribed by the SEC in existence at the time estimates were made. These rules require that the standard of “reasonable certainty” be applied to proved reserve estimates, which is defined as having a high degree of confidence that the quantities will be recovered. A high degree of confidence exists if the quantity is much more likely to be achieved than not, and, as more technical and economic data becomes available, a positive or upward revision or no revision is much more likely than a negative or downward revision. Estimates are subject to revision based upon a number of factors, including many factors beyond our control such as reservoir performance, prices, economic conditions and government restrictions. In addition, as a result of drilling, testing and production subsequent to the date of an estimate; a revision of that estimate may be necessary.

Reserve estimates are often different from the quantities of oil and natural gas that are ultimately recovered. Estimating quantities of proved oil and natural gas reserves is a complex process that involves significant interpretations and assumptions and cannot be measured in an exact manner. It requires interpretations and judgment of available technical data, including the evaluation of available geological, geophysical, and engineering data. The accuracy of any reserve estimate is highly dependent on the quality of available data, the accuracy of the assumptions on which they are based upon economic factors, such as oil and natural gas prices, production costs, severance and excise taxes, capital expenditures, workover and remedial costs, and the assumed effects of governmental regulation. In addition, due to the lack of substantial, if any, 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.

The meaningfulness of reserve estimates is highly dependent on the accuracy of the assumptions on which they were based. In general, the volume of production from oil and natural gas properties we own declines as reserves are depleted. Except to the extent we conduct successful exploration and development activities or acquire additional properties containing proved reserves, or both, our proved reserves will decline as reserves are produced. Subsequent to December 31, 2019, there have been no major discoveries, favorable or otherwise, on our proved reserves volumes that may be considered to have caused a significant change in our estimated proved reserves at December 31, 2019. We expect to report PUD reserves in the future to the extent we determine that we have the financial capability to execute a development plan to develop our PUD reserves. For a

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further discussion of our PUD reserves and Chapter 11 proceedings, see above and refer to Part II, Item 8. “Financial Statements and Supplementary Data”, Note 1A.

Results of Operations. Results of operations for oil and natural gas producing activities for the years ended December 31, 2019 and 2018 (in millions):

2019:
Net Revenues(1) — Sales to external customers	$	901
Costs of products and services	(97		)
Production costs(2)	(191		)
Impairment charges	(458		)
Depreciation, depletion and amortization(3)	(407		)
Exploration and other expense	(7		)
	(259		)
Income tax benefit	54
Results of operations from producing activities	$	(205	)
2018:
Net Revenues(1) — Sales to external customers	$	1,240
Costs of products and services	(111		)
Production costs(2)	(231		)
Impairment charges	(1,103		)
Depreciation, depletion and amortization(3)	(496		)
Exploration and other expense	(5		)
	(706		)
Income tax benefit	148
Results of operations from producing activities	$	(558	)

(1)    Excludes the effects of oil and natural gas derivative contracts.

(2)    Production costs include lease operating expense and production related taxes, including ad valorem and severance taxes.

(3)    Includes accretion expense on asset retirement obligations of $3 million for both the years ended December 31, 2019 and 2018.

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Standardized Measure of Discounted Future Net Cash Flows. The standardized measure of discounted future net cash flows relating to our consolidated proved oil and natural gas reserves at December 31 is as follows (in millions):

2019:
Future cash inflows(1)	$	6,026
Future production costs	(2,938		)
Future development costs	(231		)
Future income tax expenses	(76		)
Future net cash flows	2,781
10% annual discount for estimated timing of cash flows	(1,094		)
Standardized measure of discounted future net cash flows	$	1,687
2018:
Future cash inflows(1)	$	13,278
Future production costs	(4,708		)
Future development costs	(1,703		)
Future income tax expenses	(456		)
Future net cash flows	6,411
10% annual discount for estimated timing of cash flows	(3,061		)
Standardized measure of discounted future net cash flows	$	3,350

(1) The company had no commodity-based derivative contracts designated as accounting hedges at December 31, 2019 and 2018. Amounts also exclude the impact on future net cash flows of derivatives not designated as accounting hedges.

Changes in Standardized Measure of Discounted Future Net Cash Flows. The following are the principal sources of change in our consolidated standardized measure of discounted future net cash flows (in millions):

	Year Ended December 31,(1)
	2019			2018
Consolidated:
Sales and transfers of oil and natural gas produced net of production costs	$	(710	)	$	(1,005	)
Net changes in prices and production costs	(1,439		)	1,620
Extensions, discoveries and improved recovery, less related costs	—			—
Changes in estimated future development costs	731			360
Previously estimated development costs incurred during the period	—			381
Revision of previous quantity estimates	(883		)	(677		)
Accretion of discount	341			228
Net change in income taxes	95			(80		)
Purchase of reserves in place	8			355
Sales of reserves in place	(1		)	(165		)
Change in production rates, timing and other	195			300
Net change	$	(1,663	)	$	1,317
Representative NYMEX prices:(2)
Oil (Bbl)	$	55.69		$	65.56
Natural gas (MMBtu)	$	2.58		$	3.10

(1) This disclosure reflects changes in the standardized measure calculation excluding the effects of hedging activities.

(2) Average first day of the month spot price for the preceding 12-month period before price differentials and deducts. Price differentials and deducts were applied when the estimated future cash flows from estimated production from proved reserves were calculated.

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ITEM 9.    CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

ITEM 9A.    CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

As of December 31, 2019, we carried out an evaluation under the supervision and with the participation of our management, including our Chief Executive Officer (CEO) and our Chief Financial Officer (CFO), as to the effectiveness, design and operation of our disclosure controls and procedures. This evaluation considered the various processes carried out under the direction of our disclosure committee in an effort to ensure that information required to be disclosed in the U.S. Securities and Exchange Commission reports we file or submit under the Exchange Act is accurate, complete and timely. Our management, including our CEO and our CFO, does not expect that our disclosure controls and procedures or our internal controls will prevent and/or detect all errors and all fraud. A control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Further, the design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, within our Company have been detected. Our disclosure controls and procedures are designed to provide reasonable assurance of achieving their objectives and our CEO and CFO concluded that our disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) were effective as of December 31, 2019. See Part II, Item 8. “Financial Statements and Supplementary Data” under Management’s Annual Report on Internal Control Over Financial Reporting.

Changes in Internal Control over Financial Reporting

There were no changes in our internal control over financial reporting during the fourth quarter of 2019 that have materially affected or are reasonably likely to materially affect our internal control over financial reporting.

ITEM 9B.    OTHER INFORMATION

None.

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PART III

ITEM 10.     DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

Directors

The information in this Item 10 reflects the composition of the Company’s board of directors (“Board”), executive officers and corporate governance structure.

The Board is currently classified, with directors divided into three classes. The members of each class serve staggered, three‑year terms. Upon the expiration of the term of a class of directors, directors in that class will stand for re‑election for an additional three‑year term in the year in which their term expires.

The following table sets forth certain information as of December 31, 2019. The biographies of each of the directors follow the list and contain information regarding the person’s service as a director, business experience, director positions held currently or at any time during the last five years, information regarding involvement in certain legal or administrative proceedings, if applicable, and the experiences, qualifications, attributes or skills of each Board member.

Name	Position and Offices	Age
Class I Directors
Alan R. Crain	Independent Director, Chairman	68
Carol Flaton	Independent Director	55
Wilson B. Handler	Director	35
Rajen Mahagaokar	Director	33
Class II Director Nominees
Jae Hwii Gwag	Director	53
J. Barton Kalsu	Independent Director	52
Donald A. Wagner	Director	56
Rakesh Wilson	Director	44
Class III Directors
Gregory A. Beard	Director	48
Scott R. Browning	Director	31
Russell E. Parker	Director	43
Robert C. Reeves	Independent Director	50
Robert M. Tichio	Director	42

Class I Directors

Alan R. Crain. Mr. Crain has been Chairman of the Board since November 2017 and a member of our Board since May 2017. He is a former director, and Chairman of the Governance Committee, of the National Association of Corporate Directors Texas Tri-Cities Chapter. He is a lecturer at the Jones Graduate School of Business at Rice University and other organizations regarding complex issues facing corporate boards. He is a member of the board of directors of Bullseye Testing LLC, oilfield services portfolio companies of Hastings Equity Partners and Arbitrator Intelligence, Inc. He is President and Chairman of the Board of the Houston Committee on Foreign Relations. He is also on the boards of the World Affairs Council of Houston; the American Arbitration Association; the Asia Society, Texas Center; the Institute for Transnational Arbitration and organizations dedicated to protecting human rights. Mr. Crain was Senior Vice President, Chief Legal and Governance Officer of Baker Hughes Incorporated until his retirement at the end of December 2016. He joined Baker Hughes in October 2000 as Vice President and General Counsel. Prior thereto he was General Counsel of Crown Cork & Seal Company and General Counsel of Union Texas Petroleum Holdings, Inc. Earlier in his career he was a lawyer with Pennzoil Company and with El Paso LNG Company. He is a member of the Council on Foreign Relations and has served on the ABA's Center for Human Rights. He graduated from Rensselaer Polytechnic Institute with both BS and MS degrees in Engineering and received a MBA and a JD (cum laude; Order of The Coif) from Syracuse University.

For more than 35 years, Mr. Crain has worked in the oil and gas industry. He came to the industry with training in engineering, business and law and has gained extensive experience both domestically and internationally, onshore and offshore, with major companies engaged in the exploration, development, production and transportation of oil and gas. He

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has personally negotiated a broad portfolio of agreements across the full range of the value chain of oil and gas related projects. He possesses detailed knowledge and experience in the oilfield technology and services portion of the industry. For over 20 years, he has been a senior leader overseeing the development and execution of strategic plans for companies engaged in oil and gas related activities, both in his capacity as a senior officer of two public companies, Baker Hughes and Union Texas Petroleum Holdings, and his role as the member of the boards of directors of six companies, EP Energy, Mariner Energy, Desert Downhole, Bullseye Testing, Arbitrator Intelligence, Inc. and Accend, Inc. He is a recognized expert in corporate governance.

Carol Flaton. Ms. Flaton has been a member of our Board since May 2019. From 2014 to April 2019, she was a Managing Director of AlixPartners (f/k/a Zolfo Cooper, LLC). While employed at AlixPartners, she served as the Strategic Director of Finance for Cetera Financial Group from February 2016 to June 2016 and served as interim management of Doral Financial Corporation from March 2015 to October 2016. Prior to joining AlixPartners in 2014, she was a Managing Director in the restructuring practice at Lazard Freres. Ms. Flaton has over 30 years of experience in restructuring, banking and finance across multiple industries. Ms. Flaton served as an independent director of Jupiter Resources, Inc., a Calgary-based energy company during 2018. Ms. Flaton received a BSBA from the University of Delaware and an MBA from International Institute of Management Development, Lausanne, Switzerland.

We believe that Ms. Flaton’s extensive knowledge in financial and reorganization matters and her experience as advisor to financially distressed companies brings valuable expertise to our Board.

Wilson B. Handler. Mr. Handler has been a member of our Board since November 2013. Mr. Handler joined Apollo in 2011 and is a member of the Natural Resources group. Prior to joining Apollo, Mr. Handler was an investment professional at First Reserve, where he was involved in the execution and monitoring of investments in the energy sector. Previously, he worked in the Investment Banking Division at Lehman Brothers in the Natural Resources group. Currently, Mr. Handler serves on the board of directors of certain private companies, including American Petroleum Partners, LLC, CSV Midstream Solutions GP LLC, Jupiter Resources GP LLC, Resource Energy Partners, LLC, and Wolfcamp DrillCo, LLC and previously served as a director of Athlon Energy Inc. Mr. Handler graduated from Dartmouth College with an AB in Economics and Government. Mr. Handler was appointed to our Board by Apollo.

Based upon Mr. Handler’s extensive investment experience, his knowledge of the Company and experience in the energy industry, we believe he possesses the requisite skills to serve as a member of our Board.

Rajen Mahagaokar. Mr. Mahagaokar has been a member of our Board since November 2017. Mr. Mahagaokar is a Principal of Riverstone Holdings LLC and joined Riverstone in 2015. Prior to joining Riverstone, he analyzed investment opportunities globally in the energy and financial services industries and was a co-founder and Partner of Marka, LLC from 2013 to 2014 and from 2012 to 2013 was an investment professional at Silver Lake Kraftwerk. Mr. Mahagaokar began his career in 2008 in the Investment Banking Division at Goldman Sachs in the Natural Resources group where he worked on M&A transactions and capital markets financings, with a focus on the oil and gas sectors and in the Urban Investment Group, a principal investing strategy. He received his BA in Mathematical Economic Analysis from Rice University. Mr. Mahagaokar was appointed to our Board by Riverstone.

We believe that Mr. Mahagaokar’s experience in financial analysis, global investment opportunities and capital markets combined with his understanding of the oil and gas sectors qualify him to serve on our Board.

Class II Directors

Jae Hwii Gwag. Mr. Gwag has been a member of our Board since April 2019. Mr. Gwag joined Korea National Oil Corporation (KNOC) in 1992 as a petroleum engineer. He headed up their technology department where he maximized investment returns by concentrating on solving geological and engineering issues for KNOC’s overseas and domestic E&P businesses. Mr. Gwag was involved in the startup of an Eagle Ford shale joint venture with Anadarko. This joint venture, in the Maverick Basin, was the first unconventional shale gas business in KNOC’s history. Mr. Gwag has managed offshore E&P assets at SAVIA, Peru for over three years. He is currently serving as President and a board member of KNOC Eagle Ford Corporation. He received his master’s degree in Geology (Sedimentology) from Seoul National University. Mr. Gwag was appointed to our Board by KNOC.

Based on Mr. Gwag’s knowledge and experience in the E&P sector, and his expertise in unconventional shale business, we believe he possesses the requisite skills to serve as a member of our Board.

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J. Barton Kalsu. Mr. Kalsu has been a member of our Board since January 2018. Mr. Kalsu currently serves as Executive Vice President and Chief Financial Officer of SolarWinds, Inc. He joined SolarWinds, Inc. in 2007 as Chief Accountant and Vice President, Finance and was responsible for managing their financial operations through an initial public offering and then as a private company. He was previously Vice President, Commercial Banking, for JPMorgan Chase from June 2005 to August 2007 and from April 2002 until June 2005, Mr. Kalsu was Senior Director of Finance. Prior to 2002, Mr. Kalsu worked in public accounting for Arthur Andersen LLP. Mr. Kalsu previously served on the board of directors of Athlon Energy prior to its acquisition by Encana Corporation. He currently serves on the board of the Hill Country Rally for Kids. He holds a BS in Accounting from Oklahoma State University.

As the standing CFO of a publicly-traded company, Mr. Kalsu brings successful financial leadership to our Board with more than 25 years of experience in global finance and accounting roles. He also provides the Board with valuable public company operating and management experience.

Donald A. Wagner. Mr. Wagner has been a member of our Board since August 2013 and previously served as a member of the Board of Managers of our predecessor entity, EPE Acquisition, LLC, from May 2012 to August 2013. Mr. Wagner is a Managing Director of Access Industries, having been with Access since 2010. He is responsible for sourcing and executing new investment opportunities in North America, and he oversees Access’ current North American investments. From 2000 to 2009, Mr. Wagner was a Senior Managing Director of Ripplewood Holdings L.L.C., responsible for investments in several areas and heading the industry group focused on investments in basic industries. Previously, Mr. Wagner was a Managing Director of Lazard Freres & Co. LLC and had a 15-year career at that firm and its affiliates in New York and London. He is a board member of Access portfolio company Warner Music Group and was appointed to the board of Calpine Corporation in March 2018. He is also a director of Banff Parent Inc., a parent company of BMC Software Inc. He served on the board of NYSE-listed RSC Holdings from November 2006 until August 2009. Mr. Wagner graduated summa cum laude with an AB in physics from Harvard College. Mr. Wagner was appointed to our Board by Access.

Based upon Mr. Wagner’s experience as a director of various companies, including public companies, and over 25 years of experience in investing, banking and private equity, we believe that Mr. Wagner possesses the requisite set of skills to serve as a member of our Board.

Rakesh Wilson. Mr. Wilson has been a member of our Board since August 2013 and previously served as a member of the Board of Managers of our predecessor entity, EPE Acquisition, LLC, from May 2012 to August 2013. Mr. Wilson served as Senior Partner of Apollo until 2019, joining Apollo in 2009. Prior to joining Apollo, Mr. Wilson was at Morgan Stanley's Commodities Department in the principal investing group responsible for generating, evaluating and executing investment ideas across the energy sector. Mr. Wilson began his career at Goldman Sachs in equity research and then moved to its investment banking division in New York and Asia. Mr. Wilson currently serves on the board of directors of certain private companies, including American Petroleum Partners, LLC, CSV Midstream Solutions GP LLC, Express Energy Services, LLC, Jupiter Resources GP LLC, Resource Energy Partners, LLC, and Wolfcamp DrillCo LLC. He previously served as a director of Athlon Energy Inc., Parallel Petroleum and Talos Energy, LLC. Mr. Wilson graduated from the University of Texas at Austin and received his MBA from INSEAD, Fontainebleau, France. Mr. Wilson was appointed to our Board by Apollo. Mr. Wilson's affiliations with Apollo terminated after December 31, 2019, but he remains on our Board.

We believe that Mr. Wilson’s extensive international investment and risk management experience, his knowledge of the company and his service on multiple boards have provided him with a strong understanding of the financial, operational and strategic issues facing public companies in our industry, and that he possesses the requisite set of skills to serve as a member of our Board.

Class III Directors

Gregory A. Beard. Mr. Beard has been a member of our Board since August 2013 and previously served as a member of the Board of Managers of our predecessor entity, EPE Acquisition, LLC, from May 2012 to August 2013. He is a member of the Senior Management Committee of Apollo Global Management. Mr. Beard joined Apollo in June 2010 as the Global Head of Natural Resources and Senior Partner based in the New York office. Mr. Beard has 24 years of investment experience, including 10 years at Riverstone Holdings where he was a founding member, Managing Director and lead deal partner in many of the firm’s top oil and gas and energy service investments. While at Riverstone, Mr. Beard was involved in all aspects of the investment process including sourcing, structuring, monitoring and exiting transactions. Mr. Beard began his career as a Financial Analyst at Goldman Sachs, where he played an active role in that firm’s energy-sector principal investment activities. Mr. Beard has also served on the board of directors of many oil and natural gas companies, including Belden & Blake Corporation, Canera Resources, Cobalt International Energy, Eagle Energy, Legend Natural Gas I-IV, Mariner Energy, Phoenix Exploration, Titan Operating, Vantage Energy and Virginia Uranium. Mr. Beard has served on the board of various

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oilfield services companies, including CDM Max, CDM Resource Management, and International Logging. Mr. Beard currently serves on the board of directors of certain private companies, including Apex Energy, LLC, Caelus Energy Alaska, LLC, CSV Midstream Solutions GP LLC, Double Eagle Energy Holdings, LLC, Double Eagle Energy Holdings II, LLC, Double Eagle Energy Holdings III, LLC, DoublePoint Energy, LLC, Jupiter Resources GP LLC, Northwoods Energy LLC, Pegasus Optimization Partners, LLC, Roundtable Energy Holdings, LLC, Spartan Energy Acquisition Corporation, Talos Energy, LLC and Tumbleweed Royalty, LLC. He previously served as a director of Athlon Energy Inc., NRI Management Group, LLC, Phoenix Natural Resources Holdings, LLC, and Pinnacle Agriculture Holdings, LLC. Mr. Beard received his BA from the University of Illinois at Urbana. Mr. Beard was appointed to our Board by Apollo.

Based upon Mr. Beard’s extensive investment and management experience, particularly in the energy sector, his strong financial background and his service on the boards of multiple oil and natural gas E&P companies and oilfield services companies, which have provided him with a deep working knowledge of our operating environment, we believe that he possesses the requisite skills to serve as a member of our Board.

Scott R. Browning. Mr. Browning has been a member of our Board since June 2016. Mr. Browning joined Apollo in 2014 and is a member of the Natural Resources group. Prior to joining Apollo, Mr. Browning was an investment professional at Natural Gas Partners from 2013 to 2014, where he was involved in the execution and monitoring of investments in the energy sector. Previously, he worked in the Investment Banking Division at Goldman, Sachs & Co. in the Natural Resources group from 2011 to 2013. Mr. Browning currently serves on the board of directors of certain private companies, including Belvedere Royalties, LLC, ES Platform Holdings, Inc. (a/k/a Express Energy Services), Momentum Minerals, LLC, Pegasus Optimization Partners, LLC and AP Shale Logistics Holdco LLC (a/k/a Tidewater Logistics). Mr. Browning previously served on the board of directors of Phoenix Natural Resources Holdings, LLC. Mr. Browning received a BS in Chemical Engineering with Highest Honors from The University of Texas at Austin. Mr. Browning was appointed to our Board by Apollo.

We believe that Mr. Browning’s energy industry experience and investment and financial expertise bring valuable expertise to our Board.

Russell E. Parker. Mr. Parker has been a member of our Board since November 2017. He was the CEO of Phoenix Natural Resources LLC from March 2016 until October 2017. Prior to that time, Mr. Parker was the President of Chief Oil & Gas LLC from March 2015 until December 2015, and prior to becoming President, was Vice President of Engineering and Operations from October 2014 until March 2015 and Vice President of Engineering from November 2012 until October 2014. From January 2001 to October 2012, Mr. Parker worked in various engineering and asset management capacities for Hilcorp Energy Company. Mr. Parker received his BS in Petroleum and Geosystems from the University of Texas at Austin where he also was recognized as an Outstanding Young Graduate of the Cockrell School of Engineering as well as Distinguished Alumnus of the Petroleum Engineering Department. As President and CEO of our company, Mr. Parker brings to the Board a record of success in energetically implementing creative solutions to address the challenges facing oil and gas operators.

With his comprehensive knowledge and understanding of our Company and the E&P sector, he provides the Board with a valuable perspective on the operations of our Company.

Robert C. Reeves. Mr. Reeves has been a member of our Board since December 2017. He previously served as Athlon Energy's Chairman, President, and CEO since its formation in August 2010 through to its $7.1 billion sale to Encana in November 2014. Mr. Reeves was Senior Vice President, Chief Financial Officer and Treasurer of Encore Acquisition Company and Encore Energy Partners until the $4.5 billion sale of both companies to Denbury Resources Inc. in March 2010. Prior to joining Encore, Mr. Reeves served as Assistant Controller for Hugoton Energy Corporation. Since its formation in August 2015 until present, Mr. Reeves has served on the Board of Directors for privately held Incline Niobrara Partners LP which focuses on acquiring oil and liquids-rich minerals, royalties and non-operated working interest in the DJ basin of Colorado. Since its formation in January 2018 until present, Mr. Reeves has served on the Board of Directors for Privately held Incline Energy Partners LP which focuses on acquiring oil and liquids-rich minerals, royalties and working interest in the DJ Basin of Colorado and the Bakken play in the Williston Basin of North Dakota and Montana. In August 2018, Mr. Reeves was appointed to the board of directors of Spartan Energy Acquisition Corporation, a special purpose acquisition entity focused on the energy industry in North America, which is owned by a private investment fund managed by an affiliate of Apollo Global Management, LLC. Since February 2015, Mr. Reeves has served as Chairman and President of Solar Soccer Club, a private 501(c)3 non-profit organization focused on youth soccer development in the Dallas Fort Worth area. Mr. Reeves received his BS degree in accounting from the University of Kansas and is a Certified Public Accountant.

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As the former CEO of a publicly traded E&P Company, we believe that Mr. Reeves’ outstanding success in building and optimizing oil and gas companies brings valuable expertise, insight and fresh perspective to our Board. With his strong background in operations and management, he provides our Board with a unique understanding of the issues facing energy companies today.

Robert M. Tichio. Mr. Tichio has been a member of our Board since September 2013. Mr. Tichio is a Partner of Riverstone Holdings LLC and joined Riverstone in 2006. Prior to joining Riverstone, Mr. Tichio was in the Principal Investment Area of Goldman Sachs, which manages the firm's private corporate equity investments. Mr. Tichio began his career at J.P. Morgan in the Mergers & Acquisitions group where he concentrated on assignments that included public company combinations, asset sales, takeover defenses and leveraged buyouts. Mr. Tichio became a director of Pipestone Energy Corp. in January 2019. He is on the board of directors of Talos Energy Inc. and has been since April 2012. Talos Energy Inc. became publicly traded in 2018. Mr. Tichio has been a director of Centennial Resource Development, Inc. since October 2016. Mr. Tichio is also a director of a number of private portfolio companies and structuring vehicles sponsored by Riverstone Holdings LLC. Mr. Tichio previously served as a member of the board of directors of Gibson Energy from 2008 to 2013, Midstates Petroleum Company, Inc. from 2012 to 2015 and Northern Blizzard Resources Inc. from June 2011 to May 2017. He holds an MBA from Harvard Business School and a bachelor’s degree from Dartmouth College. Mr. Tichio was appointed to our Board by Riverstone.

We believe Mr. Tichio’s extensive energy industry background, particularly his expertise in mergers and acquisitions, brings important experience and skill to our Board.

Executive Officers

Information relating to our executive officers is included in Part I, Item 1. “Information about our Executive Officers” and is incorporated herein by reference.

Board Composition

The supervision of our management and the general course of our affairs and business operations are entrusted to our Board. Our Board is currently comprised of thirteen directors, with (i) four designated by Apollo, (ii) two designated by Riverstone, (iii) one designated by Access, (iv) one designated by KNOC, (v) our chief executive officer and (vi)  four independent directors. Apollo has the right to designate any director as the Chairman of the Board and Mr. Crain currently serves in that capacity.

Our Board is divided into three classes. The members of each class serve staggered, three‑year terms. Upon the expiration of the term of a class of directors, directors in that class will stand for re‑election for an additional three‑year term at the annual meeting of stockholders in the year in which their term expires.

• Gregory A. Beard, Scott R. Browning, Robert C. Reeves, Russell E. Parker, and Robert M. Tichio are Class III directors, whose terms will expire in 2020;

• Alan R. Crain, Carol Flaton, Wilson B. Handler, and Rajen Mahagaokar are Class I directors, whose terms will expire in 2021; and

• Jae Hwii Gwag, J. Barton Kalsu, Donald A. Wagner, and Rakesh Wilson are Class II directors, whose terms will expire in 2022.

Any additional directorships resulting from an increase in the number of directors will be distributed among the three classes so that, as nearly as possible, each class will consist of one‑third of our directors.

As ownership in us by a Sponsor decreases, our stockholders agreement provides for the reduction in the number of directors such Sponsor may designate. The tables below state the number of director(s) that each Sponsor may designate to the Board pursuant to the stockholders agreement based on such Sponsor’s ownership of common stock, in each case, expressed as a percentage of its ownership of common stock as of the first day of effectiveness, January 16, 2014, of the Company’s registration statement under the Securities Act of 1933, as amended, in connection with our initial public offering (the “Effective Time”) (e.g., 75% means that the Sponsor holds 75% of the common stock that it held as of the Effective Time).

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Apollo Ownership	Non-Independent Directors	Independent Directors
At least 75%	5	2
Between 50% and 75%	4	2
Between 25% and 50%	2	1
Between 10% and 25%	1	0
Less than 10%	0	0

Riverstone Ownership	Non-Independent Directors	Independent Directors
50%	2	1
Between 20% and 50%	0	1
Less than 20%	0	0

Access Ownership	Non-Independent Directors	Independent Directors
At least 50%	1	0
Less than 50%	0	0

KNOC Ownership	Non-Independent Directors	Independent Directors
At least 50%	1	0
Less than 50%	0	0

A director that is designated by any Sponsor pursuant to the stockholders agreement may be removed and replaced at any time and for any reason (or for no reason) only at the direction and upon the approval of such Sponsor for so long as such Sponsor has the right to designate the applicable director. The replacement of any director will be designated by the Sponsor that designated any such vacant seat unless such Sponsor has lost its right to designate the applicable director pursuant to the above. If the Sponsor has lost its right to designate the applicable director and the legacy stockholders hold at least 50% of our outstanding common stock, the legacy stockholders will have the right to designate a replacement director by a vote of the legacy stockholders holding a majority‑in‑interest of our outstanding common stock then held by the legacy stockholders (each such director, a “Replacement Director”); provided, that such Replacement Director is “independent” of us, the legacy stockholders and their affiliates under the rules of the NYSE, which we follow at this time.

Board Observers

Our stockholders agreement provides certain Sponsors with certain rights with respect to the designation of observers to the Board. Each observer generally may attend the meetings of our Board as an observer (and not as a director) and receive the same meeting‑related information given to Board members. No observer has a vote on our Board. The members of the Board can exclude any board observer from any board meeting to protect attorney‑client privilege, in connection with a conflict of interest, or for any other reason with the consent of the Sponsor that appointed the board observer, which consent cannot be unreasonably withheld, conditioned or delayed. The tables below state the number of board observers that each Sponsor (other than Apollo, which has no such right) may designate pursuant to the stockholders agreement based on such Sponsor’s ownership of common stock, in each case, expressed as a percentage of its ownership of common stock as of the Effective Time (e.g., 50% means that the Sponsor holds 50% of the common stock that it held as of the Effective Time).

Riverstone Ownership	Board Observer
Between 20% and 50%	2
Less than 20%	0

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Access Ownership	Board Observer
Between 20% and 50%	1
Less than 20%	0

KNOC Ownership	Board Observer
Between 20% and 50%	1
Less than 20%	0

Committees of the Board

Our stockholders agreement provides that for so long as each Sponsor has the right to designate a director or an observer to the Board, we will cause any committee of our Board to include in its membership such number of members that is consistent with, and reflects, the right of each Sponsor to designate a director or observer to the Board, except to the extent that such membership would violate applicable securities laws or stock exchange or stock market rules.

The Board has established three standing committees to assist the Board in carrying out its duties: the Audit Committee, the Compensation Committee and the Governance and Nominating Committee. The Board also created a Special Committee in June 2019 consisting of independent members of the Board who are not affiliated with the Company’s sponsors to address liquidity and balance sheet issues. The below table represents membership in the committees.

Name	Board	Audit	Compensation	Governance and Nominating	Special
Gregory A. Beard	Member		Chairman	Member
Scott R. Browning	Member		Member	Member
Alan R. Crain*	Chairman	Member	Member	Chairman	Member
Carol Flaton*	Member	Member	Member	Member	Chairwoman
Jae Hwii Gwag	Member		Member	Member
Wilson B. Handler	Member		Member	Member
J. Barton Kalsu*	Member	Chairman	Member	Member	Member
Rajen Mahagaokar	Member
Russell E. Parker	Member
Robert C. Reeves*	Member	Member	Member	Member
Robert M. Tichio	Member		Member	Member
Donald A. Wagner	Member		Member	Member
Rakesh Wilson	Member		Member	Member

* Independent Board member.

The Board has adopted charters for the Audit Committee, the Compensation Committee and the Governance and Nominating Committee that comply with the corporate governance rules adopted by the SEC pursuant to the Sarbanes-Oxley Act of 2002 . The Audit Committee, the Compensation Committee, and the Governance and Nominating Committee charters can be found on our website at www.epenergy.com.

Audit Committee

The Audit Committee presently consists of four members: Messrs. Kalsu (Chair), Crain, Reeves and Ms. Flaton. Each member of the Audit Committee satisfies the financial literacy and independence requirements . In addition in 2019, the Board affirmatively determined that Mr. Kalsu qualifies as an “audit committee financial expert.” No Audit Committee member serves on more than three audit committees of public companies, including our Audit Committee.

The primary purpose of the Audit Committee is to assist the Board in fulfilling its oversight responsibilities with respect to:

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• the Company’s independent registered public accounting firm’s qualifications and independence;

• the Company’s independent petroleum engineering consultants;

• the audit of the Company’s financial statements;

• the performance of the Company’s internal audit function and independent registered public accounting firm; and

• the preparation of the report of the Audit Committee to be included in the Company’s annual proxy statement under the rules of the SEC.

The Audit Committee is directly responsible for the appointment, compensation, oversight and dismissal of the Company’s independent auditor, Ernst & Young LLP, and the independent auditor reports directly to the Audit Committee. In addition, the Audit Committee provides an open avenue of communication between the internal auditors, the independent auditor and the Board.

The Audit Committee Charter can be found on our website at www.epenergy.com.

Policy for Approval of Audit and Non‑Audit Services

During 2019, the Audit Committee approved a pre‑approval policy for audit, non‑audit and tax services to be provided by our independent auditors, as required under applicable law, and the pre‑approved limit on fees for each of these categories. The Audit Committee’s current practice is to consider for pre‑approval annually all categories of audit and permitted non‑audit and tax services proposed to be provided by our independent auditors for a fiscal year. The Audit Committee will also consider for pre‑approval annually the maximum amount of fees and the manner in which the fees are determined for each type of service proposed to be provided by the independent auditors for the fiscal year. The Audit Committee must separately pre‑approve any service that is not included in the approved list of services or any proposed services that would exceed the pre‑approved cost levels. See “Principal Accountant Fees and Services” on page 107 for the aggregate fees paid to Ernst & Young LLP for the year ended December 31, 2019.

Corporate Governance

Code of Ethics

We have adopted a code of ethics, referred to as our “Code of Conduct,” that applies to all of our directors and employees, including our Chief Executive Officer, Chief Financial Officer and senior financial and accounting officers. In addition to other matters, our Code of Conduct establishes policies to deter wrongdoing and to promote honest and ethical conduct. A copy of our Code of Conduct is available on our website at www.epenergy.com. We will post to our website all waivers to, or amendments of, our Code of Conduct, which are required to be disclosed by applicable law.

Corporate Governance Guidelines

Our Board has adopted Corporate Governance Guidelines. The Corporate Governance Guidelines address matters including qualifications for directors, standards for independence of directors, election of directors, responsibilities of directors, mandatory retirement age for directors, limitation on serving on other boards/committees, management succession, director access to management and outside advisors, director compensation, prohibition on hedging and pledging of company stock, director orientation and continuing education, and annual self‑evaluation of the Board and its committees. The Board recognizes that effective corporate governance is an on‑going process, and the Board, either directly or through the Governance and Nominating Committee, will review and revise as necessary our Corporate Governance Guidelines annually, or more frequently if deemed necessary. A copy of our Corporate Governance Guidelines is available on our website at www.epenergy.com.

Audit Committee Financial Expert

The Audit Committee plays an important role in promoting effective accounting, financial reporting, risk management and compliance procedures and controls. All members of our Audit Committee meet the financial literacy standard and at least one member qualifies as having accounting or related financial management expertise. In addition, the Board has affirmatively determined that Mr. Kalsu (chairman of our Audit Committee) is an “audit committee financial expert”.

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ITEM 11.     EXECUTIVE COMPENSATION

We are currently considered a “smaller reporting company” for purposes of the SEC’s executive compensation and other disclosures.  As such, we have opted to take advantage of the scaled disclosure requirements afforded to smaller reporting companies and, as such, have provided more limited (or, in some cases, eliminated) disclosures.

Summary Compensation Table

Name and Principal Position	Year	Salary ($)	Bonus ($)(1)	Stock Awards ($)	Option Awards ($)	Non-Equity Incentive Plan Compensation ($)	Nonqualified Deferred Compensation Earnings ($)	All Other Compensation ($) (2)	Total ($)
Russell E. Parker	2019	850,000	2,392,800	0	—	—	—	35,688	3,179,488
President and Chief Executive Officer	2018	500,000	350,000	590,550	—	—	—	31,640	1,472,190
Chad D. England	2019	400,000	933,600	—	—	—	—	30,800	1,364,400
Senior Vice President, Operations	2018	400,000	—	0	—	180,000	—	31,570	611,570
Raymond J. Ambrose	2019	400,000	662,000	—	—	—	—	30,800	1,092,800
Senior Vice President,	2018	400,000	—	0	—	240,000	—	31,255	671,255
Engineering and Subsurface

(1) The amounts in this column reflect the key employment retention bonuses paid to each of Messrs. Parker, England and Ambrose in July 2019 ($2,392,800, $813,600 and $572,000 respectively), under the Key Employee Retention Program (as discussed further below, the “KERP”). These amounts were in lieu of any bonuses or long-term incentive awards, if any, that would otherwise be due or payable to each of Messrs. Parker, England or Ambrose in respect of the 2019 calendar year, and are subject to repayment in certain circumstances as set forth in the KERP. In addition, the amounts for Messrs. England and Ambrose reflect retention amounts paid over the course of fiscal year 2019 ($120,000 and $90,000, respectively).

Retention Awards. On February 28, 2019, the Compensation Committee approved short-term cash-based retention awards for certain key employees other than the CEO, including Messrs, England and Ambrose.  The awards were made to motivate and retain the executive officers and to incentivize focus and performance throughout the year. The retention awards were to be paid in eight equal monthly installments over the course of 2019, provided the employee remained in the employ of the Company on the payment date.  Due to the filing of the Chapter 11 Cases, the final two payments were not made to Messrs. England or Ambrose.

Key Employee Retention Program. On May 29, 2019, the Compensation Committee approved the implementation of a Key Employee Retention Program (a “KERP”) for all employees of the Company. The KERP was designed to retain employees of the Company in their current roles over the near term while providing them with financial stability. Pursuant to the KERP, employees must continue their employment with the Company for approximately thirteen months or they will forfeit the full amount of the retention payment. The KERP payments are in lieu of any bonuses or long-term incentive awards, if any, that would otherwise be due or payable to the KERP participants for 2019 performance. If a KERP participant is terminated for cause or voluntarily terminates his or her employment with the Company without good reason (other than as a result of death or disability) such participant must repay his or her KERP payment in full. The KERP was formulated with the input and based upon the recommendations of the Committee’s independent compensation consultant.

(2) The compensation reflected in the “All Other Compensation” column for 2019 for our named executive officers are set forth below includes items listed in the table immediately following these footnotes.

All Other Compensation included in the Summary Compensation Table for 2019

	Company Contributions to the 401(k) Retirement Plan	Company Vehicle Use	Total
Name	($)	($)(1)	($)
Russell E. Parker	30,800	4,888	35,688
Chad D. England	30,800	—	30,800
Raymond J. Ambrose	30,800	—	30,800

(1) This amount is imputed as income and no tax gross-up is added.

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Employment Agreements and Arrangements

We entered into employment agreements with Messrs. Parker, England and Ambrose on November 1, 2017. The employment agreements have an initial four‑year term, but the term of each agreement will be extended automatically for successive additional one‑year periods unless either the executive or Company provides written notice to the other at least 30 days prior to the end of the then‑current initial term or extension term that no such automatic extension will occur.

Russell E. Parker

We entered into an employment agreement with Mr. Parker, effective November 1, 2017, to serve as our President and Chief Executive Officer. Under the terms of the agreement, Mr. Parker’s annual base salary was $500,000 (increased to $850,000 as of January 1, 2019) with an annual bonus target equal to at least 100% of his base salary payable depending on performance relative to targets. Mr. Parker is eligible to participate in all benefit plans and programs that are available to other senior executives of our Company. Mr. Parker’s employment agreement contains provisions related to the payment of benefits upon certain termination events, as well as non‑compete, non‑solicitation and confidentiality restrictions.

Chad D. England

We entered into an employment agreement with Mr. England, effective November 1, 2017, to serve as our Senior Vice President, Operations. Under the terms of the agreement, Mr. England’s annual base salary is $400,000, with an annual bonus target equal to at least 75% of his base salary payable depending on performance relative to targets. Mr. England is eligible to participate in all benefit plans and programs that are available to other senior executives of our Company. Mr. England’s employment agreement contains provisions related to the payment of benefits upon certain termination events, as well as certain non‑compete, non‑solicitation and confidentiality restrictions.

Raymond J. Ambrose

We entered into an employment agreement with Mr. Ambrose, effective November 1, 2017, to serve as our Senior Vice President, Engineerings and Subsurface. Under the terms of the agreement, Mr. Ambrose’s annual base salary is $400,000, with an annual bonus target equal to at least 75% of his base salary payable depending on performance relative to targets. Mr. Ambrose is eligible to participate in all benefit plans and programs that are available to other senior executives of our Company. Mr. Ambrose’s employment agreement contains provisions related to the payment of benefits upon certain termination events, as well as certain non‑compete, non‑solicitation and confidentiality restrictions.

Outstanding Equity Awards

at Fiscal Year‑End 2019

	Stock Awards
			Equity Incentive Plan	Equity Incentive Plan
			Awards: Number of	Awards: Market or Payout
	Number of Shares or Units	Market Value of Shares or	Unearned Shares, Units or	Value of Unearned Shares,
	of Stock That Have	Units of Stock That Have	Other Rights That Have	Units or Other Rights
	Not Vested	Not Vested	Not Vested	That Have Not Vested
Name	(#)	($) (1)	(#) (2)	($) (3)
Russell E. Parker	94,340 (4)	—	240,000	—
Chad D. England	75,472 (4)	—	168,000	—
Raymond J. Ambrose	75,472 (4)	—	168,000	—

(1)    On Tuesday, December 31, 2019, the Company’s stock price was trading below $0.01. Consequently, no value is presented in this column.

(2)    The number of shares in this column represents the number of performance share units that would pay out based on achieving target‑level performance.

(3)    On Tuesday, December 31, 2019, the Company’s stock price was trading below $0.01. Consequently, no value is presented in this column.

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(4)    These are shares of restricted stock that were granted to Messrs. Parker, England and Ambrose in connection with their hire in November 2017. The restricted shares are subject to a four‑year ratable vesting schedule with remaining vesting dates on each of November 1, 2020 and 2021.

Potential Payments Upon Termination or Change in Control

The following section describes the benefits that may become payable to our named executive officers in connection with a termination of their employment.

Potential Payments under Employment and Severance Arrangements

As discussed above, we have entered into employment agreements with each of our named executive officers. The agreements contain provisions for the payment of severance benefits following certain termination events. Below is a summary of the payments and benefits these named executive officers would receive in connection with various employment termination scenarios.

Messrs. Parker, England and Ambrose

Under the terms of the employment agreement for Messrs. Parker, England and Ambrose, if the executive’s employment is terminated by us without cause or by the executive with good reason then the executive will be entitled to receive severance payments in a total amount equal to 100% of base salary paid in 12 equal monthly installments.

For purposes of the above, “good reason” means, as to any executive, the occurrence of any of the following events without the executive’s consent: (a) a material diminution in the executive’s base salary; (b) a material breach by the Company of any of its covenants or obligations under the employment agreement; and (c) the relocation of the geographic location of the executive’s principal place of employment by more than 50 miles from the location of the executive’s principal place of employment as of the effective date of the employment agreement. The term “cause” means the executive’s (i) material breach of the employment agreement or any other written agreement between the executive and one or more members of the company group; (ii) the commission of willful misconduct, breach of fiduciary duty, fraud, theft or embezzlement on the part of the executive; (iii) the commission by the executive of, or conviction or indictment of the executive for, or plea of nolo contendere by the executive to, any felony (or state law equivalent) or any crime involving moral turpitude; or (iv) the executive’s willful failure or refusal, other than due to disability, to perform the executive’s obligations pursuant to the employment agreement or to follow any lawful directive from the board that is commensurate with the executive’s position.

Potential Payments under Welfare Benefit Plans

We sponsor a welfare benefit plan available to all employees that provides long‑term disability benefits in the event of an employee’s permanent disability. In the event of a named executive officer’s permanent disability, disability income would be payable on a monthly basis as a long as the executive officer qualified as permanently disabled. Long‑term disability benefits are equal to 60% of the executive’s base salary in effect immediately prior to the disability, with a maximum monthly benefit equal to $25,000. In the event of a named executive officer’s permanent disability, he or she may also elect to maintain basic life and health insurance coverage under our welfare benefit plan at active‑employee rates for as long as the individual qualifies as permanently disabled or until he or she reaches age 65.

In addition, our named executive officers participate in our Senior Executive Survivor Benefits Plan, which provides each of our named executive officers with survivor benefits coverage in the event of the executive’s death in lieu of the coverage provided generally under our group life insurance plan. The amount of benefits provided is 2.5 times the executive’s annual salary.

Treatment of Long‑Term Incentive Awards

In addition to the severance and welfare benefits described above, our named executive officers’ outstanding long‑term incentive awards may be impacted in the event of certain termination scenarios, as described below.

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Employment Inducement Awards

Restricted Stock

The restricted shares issued under our Employment Inducement Plan to Messrs. Parker, Ambrose and England in 2017 are subject to a four‑year ratable vesting schedule with vesting commencing in 2018. If the executive’s employment is involuntarily terminated by the Company without cause or the executive resigns for good reason, then if any restricted shares remain unvested as of the date of such termination, a pro‑rata portion of the unvested restricted shares shall immediately vest. If the executive’s employment terminates due to death or disability, 50% of such unvested restricted shares shall immediately vest. Restricted shares that remain subject to the restriction period will be immediately forfeited in the event of a voluntary termination by the executive or a termination for cause.

Performance Share Units

The performance share units issued under our Employment Inducement Plan to Messrs. Parker, Ambrose and England in 2017 incorporated a four‑year performance period. The number of performance share units actually earned, if any, will be based upon achievement of specified stock price goals over the performance period. In addition, the performance share units are subject to time‑based vesting restrictions. Any shares earned pursuant to the performance share units will be issued over the fourth (20%), fifth (20%) and sixth (60%) years following the grant date, but such shares will be subject to certain transfer restrictions pursuant to the performance share unit agreement unless certain conditions are satisfied. If the executive’s employment terminates due to death or disability, 50% of such unvested performance share units shall immediately vest. In addition, any unvested performance share units will fully vest in the event of an executive’s termination of employment without cause or by the executive for good reason within one year following a change in control of EP Energy, with the termination date being deemed the end of the performance period and settlement occurring immediately thereafter.

Director Compensation

Our independent directors received cash compensation for their services as directors in 2019, which program was revised in May 2019. Below is a summary of our director compensation program.

Effective May 1, 2019, independent directors received the following cash retainers:

• $30,000 per month base cash retainer for each independent director;

• The Chairman of the Board received an additional $20,000 per month in addition to his base cash retainer; and

• The Chairwoman of the Special Committee received an additional $15,000 per month in addition to her base cash retainer.

Directors also receive reimbursement for out‑of‑pocket expenses associated with attending board or committee meetings.

The Board approved the changes to our independent director compensation program in light of the increased responsibilities and time commitment of the independent directors in connection with the Company’s evaluation of liability management and reorganization efforts throughout 2019.

Prior to May 2019, our independent directors were compensated as shown below:

• an annual cash retainer of $90,000;

• an additional annual cash retainer of $125,000 for service as non-executive Chairman;

• an additional annual retainer of $30,000 for service as the chair of the Audit Committee and $15,000 for service as the chair of the Compensation Committee or of any other board committee;

• for non‑chair committee members, an additional annual cash retainer of $15,000 for membership on the Audit Committee and $10,000 for membership on the Compensation Committee or any other board committee;

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• an annual award of restricted stock granted under our Omnibus Plan, having a value as of the grant date of $175,000;

• an additional award of restricted stock granted under our Omnibus Plan to the non-executive Chairman, having a value as of the grant date of $50,000; and

• meeting fees for participation in each meeting held outside of regularly scheduled meetings of the Board ($4,000 per meeting) and Audit Committee, Compensation Committee and Governance and Nominating Committee ($2,000 per meeting).

Director Compensation Table

The following table sets forth the aggregate dollar amount of all fees paid to each of our independent directors during 2019 for their services on the Board. The independent directors do not receive stock options or pension benefits.

Director Compensation

for the Year Ended December 31, 2019 (1)

Name	Fees Earned or Paid in Cash ($)	Stock Awards ($)	All Other Compensation ($)	Total  ($)
Alan R. Crain	539,000	—	—	539,000
Carol Flaton	390,000	—	—	390,000
J. Barton Kalsu	320,667	—	—	320,667
Robert C. Reeves	311,667	—	—	311,667

(1) Our sponsor‑appointed non‑independent directors do not receive any compensation from us for serving on the Board; consequently they are not included in the Director Compensation Table above. In addition, employee directors do not receive any additional compensation for serving on the Board. Amounts paid as reimbursable business expenses to each director for attending Board functions are not reflected in this table. We do not consider the directors’ reimbursable business expenses for attending board functions and other business expenses required to perform board duties to have a personal benefit. Accordingly, they are not considered a perquisite.

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ITEM 12.     SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

EQUITY COMPENSATION PLAN INFORMATION

The following table provides information concerning the EP Energy Corporation 2014 Omnibus Incentive Plan and the EP Energy Corporation Employment Inducement Plan, as of December 31, 2019.

	(a)	(b)	(c)
Plan Category	Number of Securities to be Issued upon Exercise of Outstanding Options, Warrants and Rights	Weighted-Average Exercise Price of Outstanding Options, Warrants and Rights	Number of Securities Remaining Available for Future Issuance under Equity Compensation Plans (Excluding Securities Reflected in Column (a))
Equity compensation plans approved by stockholders (2)	11,462 (1)	$19.82	—
	5,903,125 (3)	—	8,695,946
Equity compensation plans not approved by stockholders (4)	9,500,000 (5)	—	1,883,054
Total	15,414,587	$19.82	10,579,000

(1) Represents the maximum amount payable under stock options.

(2) Represents the 2014 Omnibus Incentive Plan.

(3) Represents the maximum amount payable under performance share units granted in 2018.

(4) Represents the Employment Inducement Plan.

(5) Represents the maximum amount payable under performance share units granted in November 2017.

2014 Omnibus Incentive Plan

In connection with our initial public offering, we adopted the 2014 Omnibus Incentive Plan, which plan was approved by our Board and became effective on January 15, 2014, the day prior to our initial public offering. At our 2016 annual meeting of stockholders on May 11, 2016, our stockholders approved an increase in the number of shares available for issuance under the Omnibus Plan by 12,398,776 shares.

Employment Inducement Plan

On October 30, 2017 the Board adopted the Inducement Plan, effective November 1, 2017, in order to attract and retain able persons as employees, directors and consultants of the Company and its affiliates. The Inducement Plan provides for the grant of the following types of equity‑based awards: (i) stock options, (ii) stock appreciation rights, (iii) restricted stock, (iv) restricted stock units, (v) stock awards, (vi) dividend equivalents, (vii) other stock‑based awards, (viii) cash awards, (ix) substitute awards and (x) performance awards. Subject to adjustment in accordance with the terms of the Inducement Plan, 12,000,000 shares of the Company’s Class A common stock, par value $0.01 per share, have been reserved for delivery pursuant to awards under the Inducement Plan. Common stock withheld to satisfy exercise prices or tax withholding obligations will again be available for delivery pursuant to other awards. The Inducement Plan is administered by the Compensation Committee of the Board. No awards may be granted under the Inducement Plan on and after November 1, 2027.

The Inducement Plan was adopted by the Board without stockholder approval pursuant to Rule 303A.08. Awards under the Inducement Plan may only be granted to an individual, as a material inducement to such individual to enter into employment with us, who (i) has not previously been an employee of us or our affiliates or (ii) is rehired following a bona fide period of non‑employment with us and our affiliates.

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Policy on Hedging and Pledging of Company Securities

We have a robust anti‑hedging policy that prohibits employees and independent directors from engaging in any kind of hedging transaction that seeks to reduce or limit that person’s economic risk associated with his or her ownership in EP Energy securities, which includes short‑selling or the purchase or sale of puts, calls, options or other derivative securities based on the Company’s securities.

In addition, our executives and independent directors are prohibited from holding EP Energy securities in a margin account or otherwise entering into any pledge arrangement that, in either case, would permit a third party to sell EP Energy securities without the individual’s consent or knowledge.

SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

The following table provides certain information regarding the beneficial ownership of our outstanding common stock as of December 31, 2019, for:

• each person or group who beneficially owns more than 5% of our common stock;

• each of our directors;

• each of the named executive officers in the Summary Compensation Table; and

• all of our current executive officers and directors as a group.

The percentage of ownership is based on 254,582,551 shares of common stock outstanding as of December 31, 2019.

The amounts and percentages of common stock beneficially owned are reported on the basis of SEC regulations governing the determination of beneficial ownership of securities. Under the SEC rules, a person is deemed to be a “beneficial owner” of a security if that person has or shares “voting power,” which includes the power to vote or to direct the voting of such security, or “investment power,” which includes the power to dispose of or to direct the disposition of such security. A person is also deemed to be a beneficial owner of any securities of which that person has a right to acquire beneficial ownership within 60 days. Under these rules, more than one person may be deemed a beneficial owner of the same securities and a person may be deemed a beneficial owner of securities as to which he has no economic interest. Except as indicated by footnote and in the next paragraph, the persons named in the table below have sole voting and investment power with respect to all shares of common stock shown as beneficially owned by them.

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	Shares of Common Stock Beneficially Owned
	Shares	Percentage
5% Beneficial Owners
Apollo Funds (1)	99,447,348	39.1	%
Riverstone (2)	31,276,726	12.3	%
Access (3)	34,943,104	13.7	%
KNOC (4)	31,276,726	12.3	%
Directors
Gregory A. Beard	—	—
Scott R. Browning	—	—
Alan R. Crain	49,928	*
Carol Flaton	—	—
Jae Hwii Gwag	—	—
Wilson B. Handler	—	—
J. Barton Kalsu	30,382	*
Rajen Mahagaokar	—	—
Robert C. Reeves	29,051	*
Robert M. Tichio	—	—
Donald A. Wagner	—	—
Rakesh Wilson	—	—
Named Executive Officers
Russell E. Parker	248,415	*
Raymond J. Ambrose	182,565	*
Chad D. England	176,904	*
Directors and executive officers as a group (17 persons)	1,168,166	*

* Less than 1%.

(1) Includes shares held of record by Apollo Investment Fund VII, L.P. (“AIF VII”), Apollo Overseas Partners (Delaware 892) VII, L.P. (“AOP (Delaware 892)”), AOP VII (EPE Intermediate), L.P. (“AOP Intermediate”), Apollo Investment Fund (PB) VII, L.P. (“AIF (PB) VII”), ANRP (EPE Intermediate), L.P. (“ANRP Intermediate”), ANRP (Corp AIV), L.P. (“ANRP (Corp AIV)”), EPE Domestic Co‑Investors, L.P. (“Domestic Co‑Investors”), EPE Overseas Co‑Investors (FC), L.P. (“Overseas Co‑Investors”), EPE 892 Co‑Investors I, L.P. (“Co‑Investor I”), EPE 892 Co‑Investors II, L.P. (“Co‑Investor II”), and EPE 892 Co‑Investors III, L.P. (“Co‑Investor III,” and together with AIF VII, AOP (Delaware 892), AOP Intermediate, AIF (PB) VII, ANRP Intermediate, ANRP (Corp AIV), Domestic Co‑Investors, Overseas Co‑Investors, Co‑Investor I and Co‑Investor II, the “Apollo Funds”). Apollo Management VII, L.P. (“Management VII”) is the manager of AIF VII, AOP (Delaware 892), AOP Intermediate and AIF (PB) VII. Apollo Commodities Management, L.P. with respect to Series I (“Commodities Management”) is the manager of ANRP Intermediate and ANRP (Corp AIV). EPE Acquisition Holdings, LLC (“Acquisition Holdings”) is the general partner of Domestic Co‑Investors, Overseas Co‑Investors, Co‑Investor I, Co‑Investor II and Co‑Investor III. Management VII and Commodities Management are the members and managers of Acquisition Holdings. AIF VII Management, LLC (“AIF VII LLC”) is the general partner of Management VII. Apollo Management, L.P. (“Apollo Management”) is the sole member‑manager of AIF VII LLC. Apollo Management GP, LLC (“Management GP”) is the general partner of Apollo Management. Apollo Commodities Management GP, LLC (“Commodities GP”) is the general partner of Commodities Management. Apollo Management Holdings, L.P. (“Management Holdings”) is the sole member and manager of Management GP and of Commodities GP. Apollo Management Holdings GP, LLC (“Management Holdings GP”) is the general partner of Management Holdings. Leon Black, Joshua Harris and Marc Rowan are the managers, as well as executive officers, of Management Holdings GP, and as such may be deemed to have voting and dispositive control of the shares of stock held of record by the Apollo Funds. The address of each of ANRP Intermediate, ANRP (Corp AIV), AIF VII, AOP (Delaware 892), AOP Intermediate, AIF (PB) VII, Domestic Co‑Investors, Co‑Investor I, Co‑Investor II and Co‑Investor III is One Manhattanville Road, Suite 201, Purchase, New York 10577. The address of Overseas Co‑Investors is c/o Intertrust Corporate Services (Cayman) Limited, 190 Elgin Street, George Town, Grand Cayman KY1‑9005, Cayman Islands. The address of Commodities Management, Commodities GP, Acquisition Holdings, Management VII, AIF VII LLC, Apollo Management, Management GP, Management Holdings and Management Holdings GP, and Messrs. Black, Harris and Rowan, is 9 W. 57th Street, 43rd Floor, New York, New York 10019.

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(2) Riverstone V Everest Holdings, L.P. and Riverstone V FT Corp Holdings, L.P. are the record holders of 19,942,040 shares of common stock and 11,334,686 shares of common stock, respectively. Riverstone Energy Partners V, L.P. is the general partner of each of Riverstone V Everest Holdings, L.P. and Riverstone V FT Corp Holdings, L.P. Riverstone Energy GP V, LLC is the general partner of Riverstone Energy Partners V, L.P. Riverstone Energy GP V, LLC is managed by a managing committee that includes six individuals: Pierre F. Lapeyre, Jr., David M. Leuschen, N. John Lancaster, E. Bartow Jones, Baran Tekkora and Robert M. Tichio. These individuals, as the members of the managing committee of Riverstone Energy GP V, LLC, may be deemed to share beneficial ownership of the shares of common stock owned of record by Riverstone V Everest Holdings, L.P. and Riverstone V FT Corp Holdings, L.P. These individuals expressly disclaim any such beneficial ownership. The business address for each of the persons named in this footnote is c/o Riverstone Holdings, 712 Fifth Avenue, 36th Floor, New York, NY 10019.

(3) Represents beneficial ownership attributable to record ownership of 31,276,726 shares of common stock by Texas Oil & Gas Holdings LLC (“TOGH”). Each of RSB Limited (“RSB”), Access Industries Management, LLC (“AIM”) and Len Blavatnik may be deemed to beneficially own the shares of common stock held directly by TOGH. RSB holds a majority of the outstanding voting interests in TOGH and, as a result, may be deemed to share voting and investment power over the shares of common stock held directly by TOGH. AIM and Len Blavatnik control or own a majority of the outstanding voting interests in entities that directly or indirectly control RSB and Len Blavatnik controls AIM. As a result, AIM and Len Blavatnik may be deemed to share voting and investment power over the shares of common stock beneficially owned by TOGH and RSB. Because of their relationships with TOGH, RSB, AIM and Len Blavatnik, each of AI Energy Holding LLC (“AI Energy”), Altep 2014 L.P. (“Altep 2014”) and AI Altep Holdings, Inc. (“AI Altep”) may be deemed to share voting and investment power over the shares of common stock beneficially owned by TOGH, RSB, AIM and Len Blavatnik. Each of RSB, AIM, AI Energy, Altep 2014, AI Altep and Len Blavatnik, and each of their affiliated entities and the officers, partners, members, and managers thereof, other than TOGH, disclaims beneficial ownership of the shares held by TOGH.

Also represents beneficial ownership of 3,556,387 shares of common stock held directly by AI Energy. Each of AIM and Len Blavatnik may be deemed to beneficially own the shares of common stock held directly by AI Energy. AIM controls AI Energy and, as a result, may be deemed to share voting and investment power over the shares beneficially owned by AI Energy. Len Blavatnik controls AIM and, as a result, may be deemed to share voting and investment power over the shares of common stock beneficially owned by AI Energy. Because of their relationships with AI Energy, AIM and Len Blavatnik, each of TOGH, RSB, Altep 2014 and AI Altep may be deemed to share voting and investment power over the shares of common stock beneficially owned by AI Energy, AIM and Len Blavatnik. Each of TOGH, RSB, AIM, Altep 2014, AI Altep and Len Blavatnik, and each of their affiliated entities and the officers, partners, members and managers thereof, other than AI Energy, disclaims beneficial ownership of the shares held by AI Energy.

Also represents beneficial ownership of 109,991 shares of common stock held directly by Altep 2014. Each of AI Altep and Len Blavatnik may be deemed to beneficially own the shares of common stock held directly by Altep 2014. AI Altep is the general partner of Altep 2014 and, as a result, may be deemed to share voting and investment power over the shares owned directly by Altep 2014. Len Blavatnik controls AI Altep and, as a result, may be deemed to share voting and investment power over the shares of common stock held by Altep 2014. Because of their relationships with Altep 2014, AI Altep and Len Blavatnik, each of TOGH, RSB, AIM and AI Energy may be deemed to share voting and investment power over the shares of common stock beneficially owned by Altep 2014, AI Altep and Len Blavatnik. Each of TOGH, RSB, AIM, AI Energy, AI Altep and Len Blavatnik, and each of their affiliated entities and the officers, partners, members and managers thereof, other than Altep 2014, disclaims beneficial ownership of the shares held by Altep 2014.

The address for TOGH, RSB, AIM, AI Energy, Altep 2014, AI Altep and Len Blavatnik is c/o Access Industries, Inc., 40 West 57th Street, 28th Floor, New York, NY 10019.

(4) Represents 31,276,726 shares of our common stock owned by KNOC, the state‑owned oil and gas company of the Republic of Korea. Su Yeong Yang, Eui Sik Yoon, Gyu Jung Ko, Oh Kyeu Back, Dong Hwan Kim, Jang Hee Lee, Taek Hwan Kim, Ho Sung Chung, Young Kyung Suh as directors of KNOC (collectively, the “KNOC Directors” and each, a “KNOC Director”), exercise investment and voting power with respect to the shares of common stock owned by KNOC. Based on the foregoing relationships, each of the KNOC Directors may be deemed to be the beneficial owners of the shares of common stock owned by KNOC. Each KNOC Director disclaims beneficial ownership of such shares of common stock except to the extent of his or her pecuniary interest therein. KNOC’s business address is 305, Jongga‑ro, Jung‑gu, Ulsan, Korea 44538.

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ITEM 13.     CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

Related Party Transactions

Our Board has adopted a written related party transactions policy. The policy defines a related party transaction as one in which EP Energy is a participant, the amount involved equals or exceeds $120,000, and a related party has a direct or indirect material interest. The policy defines a related party as any executive officer, director or director nominee, person known to be the beneficial owner of 5% or more of EP Energy’s voting securities, immediate family member of any of the foregoing persons, or firm or corporation in which any of the foregoing persons is employed as an officer, is a general partner, or in which such person has a 10% or greater beneficial ownership interest.

The policy includes procedures to review and approve, as necessary, any related party transactions prior to the transaction being entered into, or ratify any related party transactions that have not been previously approved. Other than certain pre‑approved transactions specifically set forth in the policy, any related party transaction involving executive officers or their immediate family members other than the CEO or the general counsel are referred to the CEO and general counsel for approval. Any related person transaction involving the general counsel and his or her immediate family members will be referred to the CEO for approval. Any related person transaction involving 5% or greater stockholders, directors, director nominees or the CEO and their immediate family members will be referred to the Governance and Nominating Committee for approval. All related party transactions are reported annually to the Governance and Nominating Committee.

In determining whether to approve a related party transaction, the CEO, general counsel or Governance and Nominating Committee, as applicable, will consider whether:

• the terms of the transaction are fair to EP Energy and would be on the same basis if the transaction did not involve a related party;

• there are business reasons to enter into the transaction;

• the transaction would impair the independence of an outside director;

• the transaction would present an improper conflict of interest for any director or executive officer; and

• the transaction is material.

The policy for approval of related party transactions can be found on our website at www.epenergy.com.

In addition, under our stockholders agreement, the consummation of any transaction involving us, on the one hand, and any Sponsor, director or affiliate of any Sponsor or director, on the other hand (each such transaction, a “Related Person Transaction”), will in each case require the approval of a majority of the directors, other than those directors that are (or whose affiliates are) party to such Related Person Transaction or have been designated by the Sponsor who are party, or whose affiliates are party to, such Related Person Transaction. This approval is not required for (among other things): (i) any transaction that is consummated in the ordinary course of business, on arm’s length terms and de minimis in nature (it being understood that any transaction or series of related transactions that involves goods, services, property or other consideration valued in excess of $10,000 will not be deemed to be de minimis); and (ii) an acquisition of additional securities by a Sponsor pursuant to an exercise of its preemptive rights under the stockholders agreement.

Project Jeter Joint Venture

In 2017, we entered into an unincorporated drilling joint venture with Wolfcamp Drillco Operating L.P. (the Investor), which is majority-owned and controlled by an affiliate of Apollo Global Management LLC. Subsequently, Access Industries acquired a minority ownership interest in the Investor and therefore is indirectly responsible for funding a portion of the Investor’s capital commitments. The purpose of this joint venture was originally to fund future oil and natural gas development in the Permian basin. In April 2018, we amended the drilling joint venture to apply to certain planned wells in our Eagle Ford Shale assets as a second investment tranche. Subject to certain caps and other limitations, the Investor agreed to fund 60 percent of certain drilling, completion and equipping costs in the joint venture wells in exchange for 50 percent of our original working interest in the joint venture wells. The Investor’s capital commitment for each tranche is capped at approximately $225 million; however, the Investor has the option to participate in certain other wells in the vicinity of the joint venture wells. We are the operator of the joint venture assets. Once the Investor achieves a 12 percent internal rate of

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return on its invested capital in a tranche, its working interest in that tranche is reduced to 15 percent of our original working interest. We have completed our currently-planned activity in the first and second tranches. For the years ended December 31, 2019 and 2018, we recovered approximately $91 million and $138 million, respectively, related to capital costs of the joint venture wells from the Investor.

Drilling Services

During 2019, we made payments in the amount of approximately $4 million to Pegasus Optimization Partners, LLC, which for a portion of 2019 was an Apollo portfolio company, for the purchase and rental of certain enhanced oil recovery compressors used in our drilling operations. These payments were made in the ordinary course of the Company’s business as market-based, arm’s length transactions.

Interest Payments made to Sponsor Noteholders

As of December 31, 2019, affiliates of Apollo Global Management held approximately $675 million of the aggregate outstanding principal amount of approximately $2,092 million of our 9.375% 1.5 Lien Notes due 2024 and 8.000% 1.5 Lien Notes due 2025 and approximately $21 million of the outstanding principal amount of $500 million of our 8.000% 1.25 Lien Notes due 2024. Also as of December 31, 2019, affiliates of Access Industries held approximately $48 million of our 1.5 lien notes. As holders of such debt instruments, Apollo and Access received interest payments in 2019 in the ordinary course based on the amount of notes held at the time of the applicable interest payment dates.

Director Independence

In 2019, our Board affirmatively determined that each of Alan R. Crain, Carol Flaton, J. Barton Kalsu and Robert C. Reeves is independent in accordance with standards of independence contained in our Corporate Governance Guidelines. In reaching this determination, the Board reviewed each director’s commercial and charitable relationships as well as any potential related party transactions and determined that none of these relationships or transactions affect the independence of these directors.

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ITEM 14.     PRINCIPAL ACCOUNTANT FEES AND SERVICES

Aggregate fees for professional services rendered to us by Ernst & Young LLP for the years ended December 31 were (in thousands):

Principal Accountant Fees and Services

	2019		2018
Audit Fees	$	1,609	$	1,304
Audit-Related Fees	7		4
Total	$	1,616	$	1,308

Audit Fees for the years ended December 31, 2019 and 2018 were primarily for professional services rendered for the audit of consolidated financial statements of EP Energy Corporation and its subsidiaries; the review of documents filed with the SEC; consents; the issuance of comfort letters; and certain financial accounting and reporting consultations.

Audit Related Fees for the years ended December 31, 2019 and 2018 were primarily for professional services and other advisory services rendered not included in audit fees above.

The Audit Committee has adopted a pre‑approval policy for audit and non‑audit services and the fees set forth above are consistent with such pre‑approvals. See page 95 for a description of this policy.

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PART IV

ITEM 15. EXHIBITSAND FINANCIAL STATEMENT SCHEDULES

(a) The following documents are filed as a part of this report:

1. Financial statements: Refer to Item 8. “Financial Statements and Supplementary Data” in this Annual Report on Form 10-K.

2. Financial statement schedules: Refer to Item 8. “Financial Statements and Supplementary Data” in this Annual Report on Form 10-K.

3. and (b). Exhibits

The exhibits identified below are filed as part of this report and are hereby incorporated herein by reference. The list below is a list of those exhibits filed herewith, and includes and identifies management contracts or compensatory plans or arrangements required to be filed as exhibits to this Annual Report on Form 10-K by Item 601(b)(10)(iii) of Regulation S-K.

The agreements included as exhibits to this report are intended to provide information regarding their terms and not to provide any other factual or disclosure information about us or the other parties to the agreements. The agreements may contain representations and warranties by the parties to the agreements, including us, solely for the benefit of the other parties to the applicable agreements and:

•should not in all instances be treated as categorical statements of fact, but rather as a way of allocating the risk to one of the parties if those statements prove to be inaccurate;

•may have been qualified by disclosures that were made to the other party in connection with the negotiation of the applicable agreement, which disclosures are not necessarily reflected in the agreement;

•may apply standards of materiality in a way that is different from what may be viewed as material to certain investors; and

•were made only as of the date of the applicable agreement or such other date or dates as may be specified in the agreement and are subject to more recent developments. Accordingly, these representations and warranties may not describe the actual state of affairs as of the date they were made or at any other time.

Exhibits filed with this report are designated by “*”. All exhibits not so designated are incorporated herein by reference to a prior filing as indicated. Exhibits designated with a “+” constitute a management contract or compensatory plan or arrangement. Exhibits designated with a “†” indicate that a confidential treatment has been granted with respect to certain portions of the exhibit. Omitted portions have been filed separately with the SEC. Exhibits designated with a "#" have been omitted pursuant to Item 601(b)(2) of Regulation S-K. A list of these exhibits and schedules is included after the table of contents in the Participation and Development Agreement. The Company agrees to furnish a supplemental copy of any such omitted exhibit or schedule to the SEC upon request.

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Exhibit No.	Exhibit Description
2.1	Letter Agreement, dated as of January 24, 2017, by and among EP Energy E&P Company, L.P. and Wolfcamp DrillCo Operating L.P. (Exhibit 2.6 to Company’s Annual Report on Form 10-K filed with the SEC on March 3, 2017).
#2.2	Amended and Restated Participation and Development Agreement, dated as of April 27, 2018, by and among EP Energy E&P Company, L.P. and Wolfcamp DrillCo Operating L.P. (Exhibit 2.1 to Company’s Current Report on Form 8-K filed with the SEC on May 3, 2018).
#2.3	First Amendment to Amended and Restated Participation and Development Agreement, dated as of September 26, 2018, by and among EP Energy E&P Company, L.P. and Wolfcamp DrillCo Operating L.P. (Exhibit 2.1 to Company’s Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2018, filed with the SEC on November 8, 2018).
#2.4	Second Amendment to Amended and Restated Participation and Development Agreement, dated as of December 19, 2018, by and among EP Energy E&P Company, L.P. and Wolfcamp DrillCo Operating L.P. (Exhibit 2.4 to Company’s Annual Report on Form 10-K, filed with the SEC on March 18, 2019).
3.1	Second Amended and Restated Certificate of Incorporation of EP Energy Corporation (Exhibit 3.1 to Company’s Current Report on Form 8-K, filed with the SEC on January 23, 2014).
3.2	Amended and Restated Bylaws of EP Energy Corporation (Exhibit 3.2 to Company’s Current Report on Form 8-K, filed with the SEC on January 23, 2014).
4.1	Indenture, dated as of April 24, 2012, between EP Energy LLC (f/k/a Everest Acquisition LLC) and Everest Acquisition Finance Inc., as Co-Issuers, and Wilmington Trust, National Association, as Trustee, in respect of 9.375% Senior Notes due 2020 (Exhibit 4.2 to EP Energy LLC’s Registration Statement on Form S-4, filed with the SEC on September 11, 2012).
4.2	Indenture, dated as of August 13, 2012, between EP Energy LLC and Everest Acquisition Finance Inc., as Co-Issuers, and Wilmington Trust, National Association, as Trustee, in respect of 7.750% Senior Notes due 2022 (Exhibit 4.3 to EP Energy LLC’s Registration Statement on Form S-4, filed with the SEC on September 11, 2012).
4.3	Indenture, dated as of May 28, 2015, between EP Energy LLC and Everest Acquisition Finance Inc., as Co-Issuers, and Wilmington Trust, National Association, as Trustee, in respect of 6.375% Senior Notes due 2023 (Exhibit 4.3 to EP Energy LLC’s Registration Statement on Form S-4, filed with the SEC on June 24, 2015).
4.4	Indenture, dated as of November 29, 2016, by and among EP Energy LLC, Everest Acquisition Finance Inc., the Guarantors party thereto and Wilmington Trust, National Association, as trustee and collateral agent (Exhibit 4.1 to Company’s Current Report on Form 8-K, filed with the SEC on November 30, 2016).
4.5	Indenture, dated as of February 6, 2017, by and among EP Energy LLC, Everest Acquisition Finance Inc., the Guarantors party thereto and Wilmington Trust, National Association, as trustee and collateral agent (Exhibit 4.1 to Company’s Current Report on Form 8-K, filed with the SEC on February 7, 2017).
4.6	Second Supplemental Indenture, dated as of December 21, 2017, by and among EP Energy LLC, Everest Acquisition Finance Inc., and Wilmington Trust, National Association, as trustee (Exhibit 4.1 to EP Energy LLC's Current Report on Form 8-K, filed with the SEC on December 22, 2017).
4.7	Indenture, dated as of January 3, 2018, by and among EP Energy LLC, Everest Acquisition Finance Inc. the Subsidiary Guarantors thereto and Wilmington Trust, National Association, as trustee and collateral agent (Exhibit 4.1 to the Company's Current Report on Form 8-K, filed with the SEC on January 4, 2018).
4.8	Registration Rights Agreement, dated as of May 28, 2015, between EP Energy LLC, Everest Acquisition Finance Inc. and RBC Capital Markets, LLC, as representative of the several initial purchasers, in respect of 6.375% Senior Notes due 2023 (Exhibit 4.5 to EP Energy LLC’s Registration Statement on Form S-4, filed with the SEC on June 24, 2015).
4.9	Registration Rights Agreement, dated as of April 24, 2012, between EP Energy LLC (f/k/a Everest Acquisition LLC), Everest Acquisition Finance Inc. and Citigroup Global Markets Inc. and J.P. Morgan Securities LLC, as representatives of the several initial purchasers, in respect of 9.375% Senior Notes due 2020 (Exhibit 4.5 to EP Energy LLC’s Registration Statement on Form S-4, filed with the SEC on September 11, 2012).
4.10	Registration Rights Agreement, dated as of August 13, 2012, between EP Energy LLC, Everest Acquisition Finance Inc. and Citigroup Global Markets Inc., as representative of the several initial purchasers, in respect of 7.750% Senior Notes due 2022 (Exhibit 4.6 to EP Energy LLC’s Registration Statement on Form S-4, filed with the SEC on September 11, 2012).
4.11	Registration Rights Agreement, dated as of August 30, 2013, between EP Energy Corporation and the stockholders party thereto (Exhibit 4.8 to the Company’s Registration Statement on Form S-1, filed with the SEC on September 4, 2013).

109

Exhibit No.	Exhibit Description
4.12	Indenture, dated as of May 23, 2018, by and among EP Energy LLC, Everest Acquisition Finance Inc., the Subsidiary Guarantors thereto and Wilmington Trust, National Association, as trustee and collateral agent (Exhibit 4.1 to Company’s Current Report on Form 8-K filed with the SEC on May 24, 2018).
4.13*	Description of Registrant's Securities.
10.1	Credit Agreement, dated as of May 24, 2012, by and among EPE Holdings, LLC, as Holdings, EP Energy LLC (f/k/a Everest Acquisition LLC), as the Borrower, the Lenders party thereto, JPMorgan Chase Bank, N.A., as Administrative Agent and Collateral Agent, and the other parties party thereto (Exhibit 10.1 to EP Energy LLC’s Registration Statement on Form S-4, filed with the SEC on September 11, 2012).
10.2	Guarantee Agreement, dated as of May 24, 2012, by and among EPE Holdings LLC, the Domestic Subsidiaries of the Borrower signatory thereto and JPMorgan Chase Bank, N.A., as collateral agent for the Secured Parties referred to therein (Exhibit 10.2 to EP Energy LLC’s Registration Statement on Form S-4, filed with the SEC on September 11, 2012).
10.3	Collateral Agreement, dated as of May 24, 2012, by and among EPE Holdings LLC, EP Energy LLC (f/k/a Everest Acquisition LLC), each Subsidiary of EP Energy LLC identified therein and JPMorgan Chase Bank, N.A., as Collateral Agent (Exhibit 10.3 to EP Energy LLC’s Registration Statement on Form S-4, filed with the SEC on September 11, 2012).
10.4	Pledge Agreement, dated as of May 24, 2012, by and among EP Energy LLC (f/k/a Everest Acquisition LLC), each Subsidiary of EP Energy LLC identified therein and JPMorgan Chase Bank, N.A., as Collateral Agent (Exhibit 10.4 to EP Energy LLC’s Registration Statement on Form S-4, filed with the SEC on September 11, 2012).
10.5	Pledge Agreement, dated as of May 24, 2012, by and among El Paso Brazil, L.L.C., as Pledgor, and JPMorgan Chase Bank, N.A., as Collateral Agent (Exhibit 10.5 to EP Energy LLC’s Registration Statement on Form S-4, filed with the SEC on September 11, 2012).
10.6	Amendment, dated as of August 17, 2012, to the Credit Agreement, dated as of May 24, 2012, among EPE Holdings LLC, EP Energy LLC, the lenders party thereto and JPMorgan Chase Bank, N.A., as administrative agent and collateral agent (Exhibit 10.15 to EP Energy LLC’s Registration Statement on Form S-4, filed with the SEC on September 11, 2012).
10.7	Second Amendment, dated as of March 27, 2013, to the Credit Agreement, dated as of May 24, 2012, among EPE Holdings LLC, EP Energy LLC, the lenders party thereto and JPMorgan Chase Bank, N.A., as administrative agent and collateral agent (Exhibit 10.1 to EP Energy LLC’s Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2013, filed with the SEC on May 9, 2013).
10.8	Third Amendment, dated as of October 27, 2014, to the Credit Agreement, dated as of May 24, 2012, among EPE Acquisition, LLC, EP Energy LLC, the lenders party thereto and JPMorgan Chase Bank, N.A., as administrative agent and collateral agent (Exhibit 10.1 to Company’s Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2013, filed with the SEC on April 30, 2015).
10.9	Fourth Amendment, dated as of April 6, 2015, to the Credit Agreement, dated as of May 24, 2012, among EPE Acquisition, LLC, EP Energy LLC, the lenders party thereto and JPMorgan Chase Bank, N.A., as administrative agent and collateral agent (Exhibit 10.1 to Company’s Current Report on Form 8-K, filed with the SEC on April 7, 2015).
10.10	Fifth Amendment, dated as of May 2, 2016, to the Credit Agreement, dated as of May 24, 2012, among EPE Acquisition, LLC, EP Energy LLC, the lenders party thereto and JPMorgan Chase Bank, N.A., as administrative agent and collateral agent (Exhibit 10.1 to Company’s Current Report on Form 8-K, filed with the SEC on May 4, 2016).
10.11	Sixth Amendment, dated as of November 9, 2016, to the Credit Agreement, dated as of May 24, 2012, among EPE Acquisition, LLC, EP Energy LLC, the lenders party thereto and JPMorgan Chase Bank, N.A., as administrative agent and collateral agent (Exhibit 10.1 to Company’s Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2017, filed with the SEC on August 3, 2017).
10.12	Seventh Amendment, dated as of April 24, 2017, to the Credit Agreement, dated as of May 24, 2012, among EPE Acquisition, LLC, EP Energy LLC, the lenders party thereto and JPMorgan Chase Bank, N.A., as administrative agent and collateral agent (Exhibit 10.2 to Company’s Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2017, filed with the SEC on August 3, 2017).
10.13	Eighth Amendment to Credit Agreement and Amendment to Collateral Agreement, dated as of May 23, 2018, to the Credit Agreement, dated as of May 24, 2012 (as amended, amended and restated, modified or supplemented from time to time), among EPE Acquisition, LLC, EP Energy LLC, the lenders party thereto and JPMorgan Chase Bank, N.A., as administrative agent (Exhibit 10.13 to Company’s Annual Report on Form 10-K, filed with the SEC on March 18, 2019).

110

Exhibit No.	Exhibit Description
10.14	Consent and Agreement to Credit Agreement, dated as of June 7, 2013, among EPE Holdings LLC, EP Energy LLC, the lenders party thereto and JPMorgan Chase Bank, N.A., as administrative agent and collateral agent (Exhibit 10.3 to EP Energy LLC’s Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2013, filed with the SEC on August 14, 2013).
10.15	Assumption and Ratification Agreement, dated as of April 30, 2014, entered into by EPE Acquisition, LLC, in favor of the Secured Parties (as defined in the Credit Agreement) (Exhibit 10.9 to Company’s Annual Report on Form 10-K, filed with the SEC on February 23, 2015).
10.16	Senior Lien Intercreditor Agreement, dated as of May 24, 2012, among JPMorgan Chase Bank, N.A., as RBL Facility Agent and Applicable First Lien Agent, Citibank, N.A., as Term Facility Agent, Senior Secured Notes Collateral Agent and Applicable Second Lien Agent, Wilmington Trust, National Association, as Trustee under the Senior Secured Notes Indenture, EP Energy LLC and the Subsidiaries of EP Energy LLC named therein (Exhibit 10.6 to EP Energy LLC’s Registration Statement on Form S-4, filed with the SEC on September 11, 2012).
10.17	Term Loan Agreement, dated as of April 24, 2012, by and among EP Energy LLC (f/k/a Everest Acquisition LLC), as Borrower, the Lenders party thereto, Citibank, N.A., as Administrative Agent and Collateral Agent, and Citigroup Global Markets Inc. and J.P. Morgan Securities LLC, as Co-Lead Arrangers (Exhibit 10.7 to EP Energy LLC’s Registration Statement on Form S-4, filed with the SEC on September 11, 2012).
10.18	Guarantee Agreement, dated as of April 24, 2012, by and between Everest Acquisition Finance Inc., as Guarantor, and Citibank, N.A., as collateral agent for the Secured Parties referred to therein (Exhibit 10.8 to EP Energy LLC’s Registration Statement on Form S-4, filed with the SEC on September 11, 2012).
10.19	Collateral Agreement, dated as of May 24, 2012, by and among EP Energy LLC (f/k/a Everest Acquisition LLC), each Subsidiary of EP Energy LLC identified therein and Citibank, N.A., as Collateral Agent (Exhibit 10.9 to EP Energy LLC’s Registration Statement on Form S-4, filed with the SEC on September 11, 2012).
10.20	Pledge Agreement, dated as of May 24, 2012, by and among EP Energy LLC (f/k/a Everest Acquisition LLC), each Subsidiary of EP Energy LLC identified therein and Citibank, N.A., as Collateral Agent (Exhibit 10.10 to EP Energy LLC’s Registration Statement on Form S-4, filed with the SEC on September 11, 2012).
10.21	Amendment No. 1, dated as of August 21, 2012, to the Term Loan Agreement, dated as of April 24, 2012, among EP Energy LLC, the lenders party thereto and Citibank, N.A., as administrative agent and collateral agent (Exhibit 10.16 to EP Energy LLC’s Registration Statement on Form S-4, filed with the SEC on September 11, 2012).
10.22	Joinder Agreement, dated as of August 21, 2012, among Citibank, N.A., as Additional Tranche B-1 Lender, EP Energy LLC and Citibank, N.A., as administrative agent (Exhibit 10.17 to EP Energy LLC’s Registration Statement on Form S-4, filed with the SEC on September 11, 2012).
10.23	Incremental Facility Agreement, dated October 31, 2012, to the Term Loan Agreement, dated as of April 24, 2012 and amended by that certain Amendment No. 1 dated as of August 21, 2012, among EP Energy LLC, the lenders from time to time party thereto and Citibank, N.A., as administrative agent and collateral agent (Exhibit 10.1 to EP Energy LLC’s Current Report on Form 8-K, filed with the SEC on November 5, 2012).
10.24	Reaffirmation Agreement, dated as of October 31, 2012, among EP Energy LLC, each Subsidiary Party party thereto and Citibank, N.A., as administrative agent and collateral agent (Exhibit 10.2 to EP Energy LLC’s Current Report on Form 8-K, filed with the SEC on November 5, 2012).
10.25	Amendment No. 2, dated as of May 2, 2013, to the Term Loan Agreement, dated as of April 24, 2012, among EP Energy LLC, the lenders party thereto and Citibank, N.A., as administrative agent and collateral agent (Exhibit 10.1 to EP Energy LLC’s Current Report on Form 8-K filed with the SEC on May 28, 2013).
10.26	Joinder Agreement, dated as of May 2, 2013, among Citibank, N.A., as Additional Tranche B-1 Lender, EP Energy LLC and Citibank, N.A., as administrative agent (Exhibit 10.2 to EP Energy LLC’s Current Report on Form 8-K filed with the SEC on May 28, 2013).
10.27	Pari Passu Intercreditor Agreement, dated as of May 24, 2012, among Citibank, N.A., as Second Lien Agent, Citibank, N.A., as Authorized Representative for the Term Loan Agreement, Wilmington Trust, National Association, as the Initial Other Authorized Representative and each additional Authorized Representative from time to time party hereto (Exhibit 10.12 to EP Energy LLC’s Registration Statement on Form S-4, filed with the SEC on September 11, 2012).
10.28	Consent and Exchange Agreement, dated as of August 24, 2016, among EP Energy LLC, the other credit parties party thereto, the lenders party thereto, the additional lender party thereto, and Citibank, N.A. (Exhibit 10.1 to Company’s Current Report on Form 8-K, filed with the SEC on August 26, 2016).
10.29	Guarantee Agreement, dated as of August 24, 2016, among each Subsidiary of EP Energy LLC listed therein and Citibank, N.A., as collateral agent (Exhibit 10.2 to Company’s Current Report on Form 8-K, filed with the SEC on August 26, 2016).

111

Exhibit No.	Exhibit Description
10.30	Collateral Agreement, dated as of August 24, 2016, among EP Energy LLC, each Subsidiary of EP Energy LLC identified therein and Citibank, N.A., as collateral agent (Exhibit 10.3 to Company’s Current Report on Form 8-K, filed with the SEC on August 26, 2016).
10.31	Pledge Agreement, dated as of August 24, 2016, among EP Energy LLC, each Subsidiary of EP Energy LLC identified therein and Citibank, N.A., as collateral agent (Exhibit 10.4 to Company’s Current Report on Form 8-K, filed with the SEC on August 26, 2016).
10.32	Amended and Restated Senior Lien Intercreditor Agreement, dated as of August 24, 2016, among JP Morgan Chase Bank, N.A., as RBL Facility Agent and Applicable First Lien Agent, Citibank, N.A., as Term Facility Agent and Applicable Second Lien Agent, Citibank, N.A., as Priority Lien Term Facility Agent, EP Energy LLC and the Subsidiaries of EP Energy LLC named therein (Exhibit 10.5 to Company’s Current Report on Form 8-K, filed with the SEC on August 26, 2016).
10.33	Priority Lien Intercreditor Agreement, dated as of August 24, 2016, among JP Morgan Chase Bank, N.A., as RBL Facility Agent and Applicable First Lien Agent, Citibank, N.A., as Term Facility Agent and Applicable Second Lien Agent, EP Energy LLC and the Subsidiaries of EP Energy LLC named therein (Exhibit 10.6 to Company’s Current Report on Form 8-K, filed with the SEC on August 26, 2016).
10.34	Additional Priority Lien Intercreditor Agreement, dated as of November 29, 2016, by and among JPMorgan Chase Bank, N.A., as RBL Facility Agent and Applicable First Lien Agent, Wilmington Trust, National Association, as Notes Facility Agent and Applicable Second Lien Agent, EP Energy LLC and the Subsidiaries of EP Energy LLC named therein (Exhibit 10.1 to Company’s Current Report on Form 8-K filed with the SEC on November 30, 2016).
10.35	Consent and Acknowledgement, dated as of November 29, 2016, by Wilmington Trust, National Association, as an Other First-Priority Lien Obligations Agent, and acknowledged by JPMorgan Chase Bank, N.A., as Applicable First Lien Agent, Citibank, N.A., as Applicable Second Lien Agent, and EP Energy LLC, with respect to the Priority Lien Intercreditor Agreement dated as of August 24, 2016 (Exhibit 10.2 to Company’s Current Report on Form 8-K filed with the SEC on November 30, 2016).
10.36	Consent and Acknowledgement, dated as of November 29, 2016, by Wilmington Trust, National Association, as an Other First-Priority Lien Obligations Agent, and acknowledged by JPMorgan Chase Bank, N.A., as Applicable First Lien Agent, Citibank, N.A., as Applicable Second Lien Agent, and EP Energy LLC, with respect to the Amended and Restated Senior Lien Intercreditor Agreement dated as of August 24, 2016 (Exhibit 10.3 to Company’s Current Report on Form 8-K filed with the SEC on November 30, 2016).
10.37	Consent and Acknowledgement, dated as of February 6, 2017, by Wilmington Trust, National Association, as new Term Facility Agent and Applicable Second Lien Agent, and acknowledged by JPMorgan Chase Bank, N.A., as Applicable First Lien Agent, Citibank, N.A., as prior Term Facility Agent and prior Applicable Second Lien Agent, Wilmington Trust, National Association, as an Other First-Priority Lien Obligations Agent, and EP Energy LLC, with respect to the Priority Lien Intercreditor Agreement, dated as of August 24, 2016 and supplemented on November 29, 2016 (Exhibit 10.1 to Company’s Report on Form 8-K, filed with the SEC on February 7, 2017).
10.38	Consent and Acknowledgement, dated as of February 6, 2017, by Wilmington Trust, National Association, as an Other First-Priority Lien Obligations Agent, and acknowledged by JPMorgan Chase Bank, N.A., as Applicable First Lien Agent, Wilmington Savings Fund Society, FSB (as successor to Citibank, N.A.), as Applicable Second Lien Agent, Wilmington Trust, National Association, as an Other First-Priority Lien Obligations Agent, and EP Energy LLC, with respect to the Amended and Restated Senior Lien Intercreditor Agreement, dated as of August 24, 2016 and supplemented on November 29, 2016 (Exhibit 10.2 to Company’s Current Report on Form 8-K, filed with the SEC on February 7, 2017).
10.39	Consent and Acknowledgement, dated as of January 3, 2018, by Wilmington Trust, National Association, as an Other Second-Priority Lien Obligations Agent, and acknowledged by JPMorgan Chase Bank, N.A., as Applicable First Lien Agent, Wilmington Trust, National Association, as an Other First-Priority Lien Obligations Agent for the holders of the 8.00% 2024 Notes, Wilmington Trust, National Association, as Term Facility Agent for the holders of the 8.00% 2025 Notes and Applicable Second Lien Agent and EP Energy LLC (on behalf of itself and its subsidiaries), with respect to the Priority Lien Intercreditor Agreement dated as of August 24, 2016 and supplemented on November 29, 2016 and February 6, 2017 (Exhibit 10.1 to Company’s Current Report on Form 8-K, filed with the SEC on January 4, 2018).
10.40	Consent and Acknowledgement, dated as of January 3, 2018, by Wilmington Trust, National Association, as an Other First-Priority Lien Obligations Agent, and acknowledged by JPMorgan Chase Bank, N.A., as Applicable First Lien Agent, Wilmington Savings Fund Society, FSB (as successor to Citibank, N.A.), as Applicable Second Lien Agent, Wilmington Trust, National Association, as an Other First-Priority Lien Obligations Agent for the holders of the 8.00% 2024 Notes, Wilmington Trust, National Association, as an Other First-Priority Lien Obligations Agent for the holders of the 8.00% 2025 Notes, and EP Energy LLC (on behalf of itself and its subsidiaries), with respect to the Amended and Restated Senior Lien Intercreditor Agreement dated as of August 24, 2016 and supplemented on November 29, 2016 and February 6, 2017 (Exhibit 10.2 to Company’s Current Report on Form 8-K, filed with the SEC on January 4, 2018).

112

Exhibit No.	Exhibit Description
10.41	Collateral Agreement, dated as of November 29, 2016, by and among EP Energy LLC, the Subsidiaries of EP Energy LLC party thereto and Wilmington Trust, National Association, as collateral agent (Exhibit 10.4 to Company’s Current Report on Form 8-K, filed with the SEC on November 30, 2016).
10.42	Collateral Agreement, dated as of February 6, 2017, by and among EP Energy LLC, the Subsidiaries of EP Energy LLC party thereto and Wilmington Trust, National Association, as collateral agent (Exhibit 10.3 to Company’s Current Report on Form 8-K, filed with the SEC on February 7, 2017).
10.43	Pledge Agreement, dated as of November 29, 2016, by and among EP Energy LLC, the Subsidiaries of EP Energy LLC party thereto and Wilmington Trust, National Association, as collateral agent (Exhibit 10.5 to Company’s Current Report on Form 8-K filed with the SEC on November 30, 2016).
10.44	Pledge Agreement, dated as of February 6, 2017, by and among EP Energy LLC, the Subsidiaries of EP Energy LLC party thereto and Wilmington Trust, National Association, as collateral agent (Exhibit 10.4 to Company’s Current Report on Form 8-K, filed with the SEC on February 7, 2017).
10.45	Collateral Agreement, dated as of May 23, 2018, among EP Energy LLC, each Subsidiary of EP Energy LLC identified therein and Wilmington Trust, National Association, as collateral agent (Exhibit 10.2 to Company’s Current Report on Form 8-K filed with the SEC on May 24, 2018).
10.46	Pledge Agreement, dated as of May 23, 2018, among EP Energy LLC, each Subsidiary of EP Energy LLC identified therein and Wilmington Trust, National Association, as collateral agent (Exhibit 10.3 to Company’s Current Report on Form 8-K filed with the SEC on May 24, 2018).
10.47	Senior Priority Lien Intercreditor Agreement, dated as of May 23, 2018, by and among JPMorgan Chase Bank, N.A., as RBL Facility Agent and Applicable First Lien Agent, Wilmington Trust, National Association, as Notes Facility Agent and Applicable Second Lien Agent, EP Energy LLC and the Subsidiaries of EP Energy LLC named therein (Exhibit 10.4 to Company’s Current Report on Form 8-K filed with the SEC on May 24, 2018).
10.48	Consent and Acknowledgement, dated as of May 23, 2018, by Wilmington Trust, National Association, as an Other First-Priority Lien Obligations Agent, and acknowledged by JPMorgan Chase Bank, N.A., as Applicable First Lien Agent, Wilmington Trust, National Association, as Notes Facility Agent for holders of 8.00% Senior Secured Notes due 2024 and as Applicable Second Lien Agent, and EP Energy LLC (on behalf of itself and its subsidiaries), with respect to the Additional Priority Lien Intercreditor Agreement dated as of November 29, 2016 (Exhibit 10.5 to Company’s Current Report on Form 8-K filed with the SEC on May 24, 2018).
10.49	Consent and Acknowledgement, dated as of May 23, 2018, by Wilmington Trust, National Association, as an Other First-Priority Lien Obligations Agent, and acknowledged by JPMorgan Chase Bank, N.A., as Applicable First Lien Agent, Wilmington Trust, National Association, as an Other First-Priority Lien Obligations Agent for the holders of the 8.00% Senior Secured Notes due 2024, Wilmington Trust, National Association, as Term Facility Agent for the holders of the 8.00% Senior Secured Notes due 2025 and Applicable Second Lien Agent, Wilmington Trust, National Association, as an Other Second-Priority Lien Obligations Agent for the holders of the 9.375% Senior Secured Notes due 2024 and EP Energy LLC (on behalf of itself and its subsidiaries), with respect to the Priority Lien Intercreditor Agreement dated as of August 24, 2016 (Exhibit 10.6 to Company’s Current Report on Form 8-K filed with the SEC on May 24, 2018).
10.50	Consent and Acknowledgement, dated as of May 23, 2018, by Wilmington Trust, National Association, as an Other First-Priority Lien Obligations Agent, and acknowledged by JPMorgan Chase Bank, N.A., as Applicable First Lien Agent, Wilmington Savings Fund Society, FSB (as successor to Citibank, N.A.), as Applicable Second Lien Agent, Wilmington Trust, National Association, as an Other First-Priority Lien Obligations Agent for the holders of the 8.00% Senior Secured Notes due 2024, Wilmington Trust, National Association, as an Other First-Priority Lien Obligations Agent for the holders of the 8.00% Senior Secured Notes due 2025, Wilmington Trust, National Association, as an Other First-Priority Lien Obligations Agent for the holders of the 9.375% Senior Secured Notes due 2024, and EP Energy LLC (on behalf of itself and its subsidiaries), with respect to the Amended and Restated Senior Lien Intercreditor Agreement dated as of August 24, 2016 (Exhibit 10.7 to Company’s Current Report on Form 8-K filed with the SEC on May 24, 2018).
10.51+	Employment Agreement dated as of November 1, 2017 by and between EP Energy Corporation and Russell Parker (Exhibit 10.1 to Company’s Current Report on Form 8-K filed with the SEC on November 2, 2017).
10.52+	Employment Agreement dated as of November 1, 2017 by and between EP Energy Corporation and Ray Ambrose (Exhibit 10.2 to Company’s Current Report on Form 8-K filed with the SEC on November 2, 2017).
10.53+	Employment Agreement dated as of November 1, 2017 by and between EP Energy Corporation and Chad England (Exhibit 10.3 to Company’s Current Report on Form 8-K filed with the SEC on November 2, 2017).

113

Exhibit No.	Exhibit Description
10.54+	Employment Agreement dated as of May 24, 2012 by and between EP Energy Corporation and Kyle A. McCuen (Exhibit 10.54 to Company’s Annual Report on Form 10-K, filed with the SEC on March 18, 2019).
10.55+	Senior Executive Survivor Benefit Plan adopted as of May 24, 2012 (Exhibit 10.23 to EP Energy LLC’s Registration Statement on Form S-4, filed with the SEC on September 11, 2012).
10.56+	Management Incentive Plan Agreement, dated as of August 30, 2013, between EP Energy Corporation and EPE Employee Holdings, LLC (Exhibit 10.31 to Amendment No. 2 to the Company’s Registration Statement on Form S-1, filed with the SEC on November 1, 2013).†
10.57+	Form of EPE Employee Holdings, LLC Management Incentive Unit Agreement (Exhibit 10.26 to EP Energy LLC’s Registration Statement on Form S-4 filed with the SEC on September 11, 2012).
10.58+	Form of Notice to MIPs Holders regarding Corporate Reorganization (Exhibit 10.33 to the Company’s Registration Statement on Form S-1, filed with the SEC on September 4, 2013).
10.59+	Third Amended and Restated Limited Liability Company Agreement of EPE Employee Holdings, LLC dated as of August 30, 2013 (Exhibit 10.34 to Amendment No. 2 to the Company’s Registration Statement on Form S-1, filed with the SEC on November 1, 2013).†
10.60+	Form of EP Energy Employee Holdings II, LLC Class B Incentive Pool Program Award Agreement (Exhibit 10.37 to Amendment No. 1 to the Company’s Registration Statement on Form S-1, filed with the SEC on October 11, 2013).
10.61+	EP Energy Corporation 2014 Omnibus Incentive Plan, as amended and restated effective May 11, 2016 (Exhibit 10.1 to EP Energy Corporation’s Current Report on Form 8-K, filed with the SEC on May 13, 2016).
10.62+	Form of Notice Stock Option Grant and Stock Option Award Agreement under EP Energy Corporation 2014 Omnibus Incentive Plan (Exhibit 10.39 to Company’s Annual Report on Form 10-K filed with the SEC on February 27, 2014).
10.63+	Form of Notice Restricted Stock Grant and Restricted Stock Award Agreement under EP Energy Corporation 2014 Omnibus Incentive Plan (Exhibit 10.40 to Company’s Annual Report on Form 10-K filed with the SEC on February 28, 2014).
10.64+	Form of Performance Unit Award Agreement under EP Energy Corporation 2014 Omnibus Incentive Plan. (Exhibit 10.42 to Company’s Annual Report on Form 10-K filed with the SEC on February 22, 2016).
10.65+	Form of 2017 Performance Unit Award Agreement under EP Energy Corporation 2014 Omnibus Incentive Plan (Exhibit 10.52 to Company’s Annual Report on Form 10-K filed with the SEC on March 3, 2017).
10.66+	EP Energy Corporation Employment Inducement Plan (Exhibit 10.4 to Company’s Current Report on Form 8-K filed with the SEC on November 2, 2017).
10.67+	Form of Performance Share Unit Grant Notice and Performance Share Unit Agreement under the EP Energy Corporation Employment Inducement Plan (Exhibit 10.5 to Company’s Current Report on Form 8-K filed with the SEC on November 2, 2017).
10.68+	Form of Restricted Stock Grant Notice and Restricted Stock Agreement under the EP Energy Corporation Employment Inducement Plan (Exhibit 10.6 to Company’s Current Report on Form 8-K filed with the SEC on November 2, 2017).
10.69+	Form of Performance Share Unit Award Agreement under EP Energy Corporation 2014 Omnibus Incentive Plan (Exhibit 10.1 to Company’s Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2018, filed with the SEC on August 9, 2018).
10.70+	Form of Performance-Based Restricted Stock Award Agreement under EP Energy Corporation 2014 Omnibus Incentive Plan (Exhibit 10.2 to Company’s Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2018, filed with the SEC on August 9, 2018).
10.71	Stockholders Agreement, dated as of August 30, 2013, between EP Energy Corporation and the stockholders party thereto (Exhibit 10.39 to Amendment No. 1 to the Company’s Registration Statement on Form S-1, filed with the SEC on October 11, 2013).
10.72	Addendum Agreement, dated as of September 18, 2013, to the Stockholders Agreement, between EP Energy Corporation and EP Energy Employee Holdings II, LLC (Exhibit 10.40 to Amendment No. 1 to the Company’s Registration Statement on Form S-1, filed with the SEC on October 11, 2013).
10.73	Form of Director and Officer Indemnification Agreement between EP Energy Corporation and each of the officers and directors thereof (Exhibit 10.41 to Amendment No. 4 to the Company’s Registration Statement on Form S-1, filed with the SEC on January 6, 2014).

114

Exhibit No.	Exhibit Description
10.74+	Form of Key Employee Retention Plan for Officers (Exhibit 10.1 to Company’s Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2019, filed with the SEC on August 9, 2019).
10.75	Forbearance Agreement, dated September 14, 2019, by and among EP Energy LLC, Everest Acquisition Finance Inc., the guarantors under the Indenture and the Noteholders (Exhibit 10.1 to Company’s Current Report on Form 8-K, filed with the SEC on September 16, 2019).
10.76	Forbearance Agreement, dated as of September 14, 2019, among EPE Acquisition, LLC, EP Energy LLC, as borrower, and the Credit Agreement Forbearing Parties (Exhibit 10.2 to Company’s Current Report on Form 8-K, filed with the SEC on September 16, 2019).
10.77	Plan Support Agreement, dated October 18, 2019, by and among the Company, the other Debtors party thereto, and the Supporting Noteholders party thereto (Exhibit 10.1 to Company’s Current Report on Form 8-K, filed with the SEC on October 21, 2019).
10.78	Backstop Commitment Agreement, dated October 18, 2019, by and among the Company, the other Debtors party thereto, and the Commitment Parties party thereto (Exhibit 10.2 to Company’s Current Report on Form 8-K, filed with the SEC on October 21, 2019).
10.79	Joint Chapter 11 Plan of Reorganization of EP Energy Corporation and its Affiliated Debtors (Exhibit 99.1 to Company’s Current Report on Form 8-K, filed with the SEC on November 19, 2019).
10.80	Disclosure Statement for Joint Chapter 11 Plan of Reorganization of EP Energy Corporation and its Affiliated Debtors (Exhibit 99.2 to Company’s Current Report on Form 8-K, filed with the SEC on November 19, 2019).
10.81	Senior Secured Superpriority Debtor-in-Possession Credit Agreement (Exhibit 10.1 to Company’s Current Report on Form 8-K, filed with the SEC on November 27, 2019).
10.82	Amended Joint Chapter 11 Plan of EP Energy Corporation and its Affiliated Debtors (Exhibit 99.1 to Company’s Current Report on Form 8-K, filed with the SEC on December 16, 2019).
10.83	Disclosure Statement for Amended Joint Chapter 11 Plan of Reorganization of EP Energy Corporation and its Affiliated Debtors (Exhibit 99.2 to Company’s Current Report on Form 8-K, filed with the SEC on December 16, 2019).
10.84	Modified Third Amended Joint Chapter 11 Plan of EP Energy Corporation and its Affiliated Debtors (Exhibit 99.1 to Company’s Current Report on Form 8-K, filed with the SEC on January 9, 2020).
10.85	Modified Disclosure Statement for Modified Third Amended Joint Chapter 11 Plan of Reorganization of EP Energy Corporation and its Affiliated Debtors (Exhibit 99.2 to Company’s Current Report on Form 8-K, filed with the SEC on January 9, 2020).
10.86	Fourth Amended Joint Chapter 11 Plan of EP Energy Corporation and its Affiliated Debtors (Exhibit 99.1 to Company’s Current Report on Form 8-K, filed with the SEC on January 14, 2020).
10.87	Disclosure Statement for Fourth Amended Joint Chapter 11 Plan of Reorganization of EP Energy Corporation and its Affiliated Debtors (Exhibit 99.2 to Company’s Current Report on Form 8-K, filed with the SEC on January 14, 2020).
10.88	Plan Supplement in Connection with Fourth Amended Joint Chapter 11 Plan of EP Energy Corporation and its Affiliated Debtors (Exhibit 99.1 to Company’s Current Report on Form 8-K, filed with the SEC on February 10, 2020).
21.1*	Subsidiaries of EP Energy Corporation.
23.2*	Consent of Ryder Scott Company, L.P.
31.1*	Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2*	Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1*	Certification of Chief Executive Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2*	Certification of Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
99.1*	Ryder Scott Company, L.P. reserve report for EP Energy Corporation as of December 31, 2019.
101.INS*	XBRL Instance Document.
101.SCH*	XBRL Schema Document.
101.CAL*	XBRL Calculation Linkbase Document.

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101.DEF*	XBRL Definition Linkbase Document.
101.LAB*	XBRL Labels Linkbase Document.
101.PRE*	XBRL Presentation Linkbase Document.

(c) Financial statement schedules

Financial statement schedules have been omitted because they are either not required or not applicable.

ITEM 16. FORM 10-K SUMMARY

None.

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SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, EP Energy Corporation has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized on the 25th day of March 2020. 

EP ENERGY CORPORATION
By:	/s/ Russell E. Parker
	Russell E. Parker
	President and Chief Executive Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of EP Energy Corporation and in the capacities and on the dates indicated:

Signature	Title	Date
/s/ Russell E. Parker
Russell E. Parker	President, Chief Executive Officer and Director (Principal Executive Officer)	March 25, 2020
/s/ Kyle A. McCuen
Kyle A. McCuen	Senior Vice President, Chief Financial Officer and Treasurer (Principal Financial and Accounting Officer)	March 25, 2020
/s/ Alan R. Crain, Jr.
Alan R. Crain, Jr.	Chairman of the Board	March 25, 2020
/s/ Gregory A. Beard
Gregory A. Beard	Director	March 25, 2020
/s/ Scott R. Browning
Scott R. Browning	Director	March 25, 2020
/s/ Carol Flaton
Carol Flaton	Director	March 25, 2020
/s/ Jae Hwii Gwag
Jae Hwii Gwag	Director	March 25, 2020
/s/ Wilson B. Handler
Wilson B. Handler	Director	March 25, 2020
/s/ J. Barton Kalsu
J. Barton Kalsu	Director	March 25, 2020
/s/ Robert C. Reeves
Robert C. Reeves	Director	March 25, 2020
/s/ Robert M. Tichio
Robert M. Tichio	Director	March 25, 2020
/s/ Donald A. Wagner
Donald A. Wagner	Director	March 25, 2020
/s/ Rakesh Wilson
Rakesh Wilson	Director	March 25, 2020

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EX-4.13

Exhibit 4.13

DESCRIPTION OF REGISTRANT’S SECURITIES

As of March 25, 2020, EP Energy Corporation (hereinafter, the “Company”) had one class of securities registered pursuant to Section 12 of the U.S. Securities Exchange Act of 1934, as amended: Class A Common Stock, $0.01 par value per share (the “Class A Common Stock”). The following summary includes a brief description of the Common Stock, as well as certain related additional information.

General. The Company has the authority to issue 550,000,000 shares of Class A Common Stock, 878,304 shares of Class B Common Stock, $0.01 par value per share (the “Class B Common Stock”), and 50,000,000 shares of preferred stock, $0.01 par value per share (the “Preferred Stock”).

Voting Rights. The holders of Class A Common Stock are entitled to one vote per share of Class A Common Stock on each matter properly submitted to the stockholders on which the holders of shares of Class A Common Stock are entitled to vote. Subject to the director nomination rights described in that certain Stockholders Agreement, dated as of August 30, 2013, between the Company and the stockholders party thereto (as may be amended from time to time, the “Stockholders Agreement”) and the rights of holders of any series of Preferred Stock to elect directors under specified circumstances, at any annual or special meeting of the stockholders, holders of Class A Common Stock will have the exclusive right to vote for the election of directors and on all other matters properly submitted to a vote of the stockholders. There is no cumulative voting.

Dividend Rights. All shares of Class A Common Stock will be entitled to share equally in any dividends that the board of directors (the “Board”) may declare from legally available sources, subject to the terms of any outstanding Preferred Stock and Class B Common Stock. Provisions of the Company’s debt agreements and other contracts, including requirements under the Second Amended and Restated Certificate of Incorporation (the “Certificate of Incorporation”) and the Stockholders Agreement, may impose restrictions on the Company’s ability to declare dividends with respect to the Class A Common Stock.

Liquidation Rights. Upon a liquidation or dissolution of the Company, whether voluntary or involuntary and subject to the rights of the holders of Class B Common Stock and any Preferred Stock, all shares of the Class A Common Stock will be entitled to share equally in the assets available for distribution to holders of Class A Common Stock after payment of all of the Company’s prior obligations, including any then-outstanding Preferred Stock.

Registration Rights. Pursuant to that certain Registration Rights Agreement, dated as of August 30, 2013, between the Company and the stockholders party thereto (the “Registration Rights Agreement”), the Company granted the direct and indirect holders of Class A Common Stock and their permitted transferees party thereto demand registration rights and/or incidental registration rights, in each case, with respect to certain shares of Class A Common Stock owned by them.

Sinking Fund Provisions; Redemption Provisions; Preemptive Rights. Pursuant to the Stockholders Agreement, certain of thedirect and indirect holders of Class A Common Stock and their permitted transferees as of the effective time of the registration statement (the “Effective Time”) for the Company’s initial public offering (the “Legacy Class A Stockholders”) have, subject to certain exceptions, preemptive rights to acquire their pro rata portion of any future issuances of additional

securities of the Company. Except as provided by the Stockholders Agreement with respect to the Legacy Class A Stockholders, the holders of the Class A Common Stock have no preemptive rights, and the Class A Common Stock is not subject to further calls or assessments by us. There are no redemption or sinking fund provisions applicable to the Class A Common Stock.

Preemptive Rights; Redemption or Sinking Fund Provisions. Except as provided by the Stockholders Agreement with respect to the Legacy Class A Stockholders, the holders of the Class A Common Stock have no preemptive rights, and the Class A Common Stock is not subject to further calls or assessments by the Company. There are no redemption or sinking fund provisions applicable to the Class A Common Stock.

Anti-Takeover Effects of the Certificate of Incorporation and Bylaws

Certain provisions of the Company’s Certificate of Incorporation, Amended and Restated Bylaws (the “Bylaws”), and the Stockholders Agreement summarized below may be deemed to have an anti-takeover effect and may delay, deter or prevent a tender offer or takeover attempt that a stockholder might consider to be in its best interests, including attempts that might result in a premium being paid over the market price for the shares held by stockholders.

“Blank Check” Preferred Stock. The Certificate of Incorporation provides that, for so long as For so long as the Legacy Class A Stockholders hold at least 25% of the Company’s outstanding Class A Common Stock and either Apollo Global Management, LLC (together with its subsidiaries, “Apollo”) or or Riverstone Holdings LLC (together with its subsidiaries, “Riverstone”) are entitled to designate at least one director pursuant to the Stockholders Agreement (the "Negative Control Condition") is satisfied, the Board may by the approval by a majority of the Board, which majority includes (i) at least one director designated to the Board by Apollo and (ii) at least one director designated to the Board by one of Access Industries (“Access”) or Korea National Oil Corporation (“KNOC”, and together with Apollo, Riverstone and Access, the “Sponsors”) or one replacement director designated to the Board by a vote of the Legacy Class A Stockholders holding a majority in interest of the outstanding Class A Common Stock then held by the Legacy Class A Stockholders (a “Replacement Director”) in the event a Sponsor has lost its right to designate its applicable director and the Legacy Class A Stockholders hold at least 50% of the outstanding Class A Common Stock (“Special Board Approval”), and in the event the Negative Control Condition is no longer satisfied, the Board may by a majority vote, issue shares of Preferred Stock. Preferred Stock could be issued by the Board to increase the number of outstanding shares making a takeover more difficult and expensive.

No Cumulative Voting. The Certificate of Incorporation provides that stockholders do not have the right to cumulative votes in the election of directors.

Removal of Directors; Vacancies. Each of the Sponsors, for so long as it beneficially owns certain percentages of their current ownership of Class A Common Stock as of the Effective Time, will have the right to designate a certain number of directors, and each Legacy Class A Stockholder has agreed to vote its shares of Class A Common Stock in favor of such designee. Each of the Sponsors shall have the sole right to remove any director designated by it, with or without cause, and to fill any vacancy caused by the removal of any such director. If any Sponsor has lost its right to designate the applicable director nominee and the Legacy Class A Stockholders hold more than 50% of the outstanding Class A Common Stock, the Legacy Class A Stockholders will have the right to designate a Replacement Director by a vote of the Legacy Class A Stockholders holding a majority-in-interest of the outstanding Class A Common Stock

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then held by the Legacy Class A Stockholders. For so long as the Sponsors or a majority-in-interest of the Legacy Class A Stockholders, as applicable, have the right to designate directors, the governance and nominating committee of the Board shall only nominate a director after consulting with the Sponsor or majority-in-interest of the Legacy Class A Stockholders, as applicable, that is entitled to designate such director. Subject to the exceptions described above, directors may be removed only for cause, and only by the affirmative vote of the holders of Class A Stock that together hold at least two-thirds of the voting power entitled to vote in any annual election of directors or class of directors; provided, however, that for so long as the Legacy Class A Stockholders beneficially own more than 50% of the outstanding Class A Common Stock, directors may be removed only for cause, and only by the affirmative vote of the holders of Class A Stock that together hold at least a majority of the voting power entitled to vote in any annual election of directors or class of directors.

Stockholder Action by Written Consent. The Certificate of Incorporation provides that for so long as the Legacy Class A Stockholders beneficially own more than 50% of the outstanding shares of Class A Common Stock, any action required to be or that may be taken at any meeting of stockholders may be taken without a meeting, without prior notice and without a vote, if and only if a consent in writing, setting forth the action so taken, shall be signed by the stockholders having not less than the minimum number of votes necessary to take such action.

Classified Board. The Certificate of Incorporation, Bylaws and Stockholders Agreement provide that the Board has three classes of directors:

• Class I consists of two directors designated by Apollo, one director designated by Riverstone and one independent director designated by Apollo, each of whom serves an initial one-year term;

• Class II consists of one director designated by Apollo, one director designated by KNOC, one director designated by Access and one independent director designated by Riverstone, each of whom serves an initial two-year term; and

• Class III consists of two directors designated by Apollo, one director designated by Riverstone, one independent director designated by Apollo and the Chief Executive Officer, each of whom serves an initial three-year term.

For so long as the Negative Control Condition is satisfied, the number of directors on the Board may be fixed only by Special Board Approval. If the Negative Control Condition is no longer satisfied, the number of directors on the Board may be fixed by a majority of the Board. Any additional directorships resulting from an increase in the number of directors will be distributed among the three classes so that, as nearly as possible, each class will consist of one-third of the directors.

Advance Notice Requirements for Stockholder Proposals and Director Nominations. The Bylaws provide that stockholders seeking to bring business before an annual meeting of stockholders, or to nominate candidates for election as directors at an annual meeting of stockholders, must provide timely notice thereof in writing. To be timely, a stockholder's notice generally must be delivered to and received at the Company’s principal executive offices not less than 90 days nor more than 120 days prior to the first anniversary of the preceding year's annual meeting; provided, that, in the event that the date of such meeting is advanced more than 30 days prior to, or delayed by more than 60 days after, the anniversary of the preceding year's annual meeting of the Company’s stockholders, a stockholder's notice to be timely must be so delivered not earlier than the close of business on the 120th day prior to such meeting and not later than the close of business on the later of the 90th day prior to such meeting or, if the first public announcement of the date of such annual meeting is less than 100 days prior to the date of such annual

3

meeting, the 10th day following the day on which public announcement of the date of such meeting is first made. The Company’s Bylaws also specify certain requirements as to the form and content of a stockholder's notice. These provisions may preclude stockholders from bringing matters before an annual meeting of stockholders or from making nominations for directors at an annual meeting of stockholders.

Special Meetings of Stockholders. Subject to the rights of the Preferred Stock, special meetings of stockholders may be called only by a majority of the Board pursuant to a resolution approved by the Board and business transacted at any special meeting of stockholders shall be limited to the purposes stated in the notice of such special meeting.

Special Board Approval. For so long as the Negative Control Condition is satisfied, certain significant business decisions require Special Board Approval, including the issuance of Preferred Stock.

Limitation of Officer and Director Liability and Indemnification Arrangements. The Certificate of Incorporation limits the liability of the directors to the maximum extent permitted by Delaware law. However, if Delaware law is amended to authorize corporate action further limiting or eliminating the personal liability of directors, then the liability of the directors will be limited or eliminated to the fullest extent permitted by Delaware law, as so amended. The Certificate of Incorporation provides that the Company will, from time to time, to the fullest extent permitted by law, indemnify its directors, officers and Board observers against all liabilities and expenses in any suit or proceeding, arising out of their status as an officer or director or their activities in these capacities. The Company also will indemnify any person who, at the Company’s request, is or was serving as a director, officer, trustee, employee or agent of another corporation or of a partnership, joint venture, trust or other enterprise, including service with respect to employee benefit plans maintained or sponsored by the Company. The Company has entered into separate indemnification agreements with each of the Company’s directors and executive officers, which may be broader than the specific indemnification provisions contained in Delaware law.

Delaware Anti-Takeover Law. The Company has elected to be exempt from the restrictions imposed under Section 203 of the General Corporation Law of the State of Delaware (the “DGCL”). Section 203 of the DGCL provides that, subject to exceptions specified therein, an "interested stockholder" of a Delaware corporation shall not engage in any "business combination," including general mergers or consolidations or acquisitions of additional shares of the corporation, with the corporation for a three-year period following the time that such stockholder becomes an interested stockholder.

Amendment of the Certificate of Incorporation. For so long as the Negative Control Condition is satisfied, the Certificate of Incorporation may be amended with a Special Board Approval and the affirmative vote of holders of at least 80% of the outstanding shares of Class A Common Stock entitled to vote thereon. If the Negative Control Condition is no longer satisfied, the Certificate of Incorporation may be amended by the affirmative vote of at least 90% of the outstanding shares of Class A Common Stock entitled to vote thereon and by the vote of the holders of a majority of the Board.

The Stockholders Agreement further provides that each of the Legacy Stockholders will not vote to amend or modify any provision of the Certificate of Incorporation in a manner that would disproportionally and materially adversely affect the interests of any Legacy Stockholder (in relation to any other Legacy Stockholder after taking into account the rights of such Legacy Stockholder) without the written approval of such Legacy Stockholder. Further, the Stockholders Agreement provides that the Legacy Stockholders will vote and take all other necessary actions to ensure that the Certificate of

4

Incorporation does not conflict with the Stockholders Agreement and to give effect to the provisions of the Stockholders Agreement.

Amendment of the Bylaws. For so long as the Negative Control Condition is satisfied, the Bylaws may be amended with a Special Board Approval and the affirmative vote of holders of at least 80% of the outstanding shares of Class A Common Stock entitled to vote thereon. If the Negative Control Condition is no longer satisfied, the Bylaws may be amended by the affirmative vote of at least 90% of the outstanding shares of Class A Common Stock entitled to vote thereon and by the vote of the holders of a majority of the Board.

The Stockholders Agreement further provides that each of the Legacy Stockholders will not vote to amend or modify any provision of the Bylaws in a manner that would disproportionally and materially adversely affect the interests of any Legacy Stockholder (in relation to any other Legacy Stockholder after taking into account the rights of such Legacy Stockholder) without the written approval of such Legacy Stockholder. Further, the Stockholders Agreement provides that the Legacy Stockholders will vote and take all other necessary actions to ensure that the Bylaws do not conflict with the Stockholders Agreement and to give effect to the provisions of the Stockholders Agreement.

Corporate Opportunity. Under the Certificate of Incorporation, to the extent permitted by law:

• any Legacy Class A Stockholder or any director who is also, without limitation, an employee, partner, officer or director of a Legacy Class A Stockholder or any of their affiliates (each, a "Covered Person") has the right to, and has no duty to abstain from, exercising such right to, conduct business with any business that is competitive or in the same line of business as the Company, do business with any of the Company’s clients or customers, or invest or own any interest publicly or privately in, or develop a business relationship with, any business that is competitive or in the same line of business as the Company;

• if a Covered Person acquires knowledge of a potential transaction that could be a corporate opportunity, he has no duty to offer such corporate opportunity to the Company; and

• the Company has renounced any interest or expectancy in, or in being offered an opportunity to participate in, such corporate opportunities.

The Stockholders Agreement

The Company entered into the Stockholders Agreement with the Legacy Class A Stockholders and the holder of the Class B Common Stock and its permitted transferees (the "Legacy Class B Stockholder") in connection with the reorganization that occurred on August 30, 2013. The Stockholders Agreement contains, among other things, the agreement among the stockholders to restrict their ability to transfer the stock of the Company as well as rights of first refusal, tag-along rights and drag-along rights. Pursuant to the Stockholders Agreement, certain of the Legacy Class A Stockholders have, subject to certain exceptions, preemptive rights to acquire their pro rata portion of any future issuances of additional securities of EP Energy. The Stockholders Agreement also permits the Company to repurchase Class A Common Stock and Class B Common Stock beneficially owned by management, and allows such beneficially owned shares to be forfeited, under certain conditions.

Preemptive Rights. Each Legacy Class A Stockholder has the right to purchase its pro rata share of any new shares of Class A Common Stock or any other equity or debt securities that the Company may propose to sell and issue. Legacy Class A Stockholders will not have preemptive rights with respect to the

5

following issuances of securities by the Company: (i) any issuance of securities upon the exercise of options, warrants, debentures or other convertible securities outstanding as of August 30, 2013 or issued after August 30, 2013 in a transaction that complies with the preemptive rights provisions of the Stockholders Agreement, (ii) any issuance of securities to the Company’s officers, employees, managers or consultants pursuant to such person's employment or consulting arrangements with us, (iii) any issuance of securities as part of (a) any direct or indirect consolidation, business combination or other acquisition transaction or (b) any joint venture or strategic partnership entered into primarily for purposes other than raising capital, in each case, to the extent approved by a majority of directors on the Board, other than those directors that are a party, or affiliated with a party, to such transaction or have otherwise been designated by a Legacy Class A Stockholder that is a party to such transaction, (iv) any issuance of securities in connection with any share split, share dividend or similar distribution or recapitalization, (v) any issuance of securities pursuant to a registered public offering or in connection with an initial public offering, (vi) any issuance of shares of Class A Common Stock in exchange for shares of Class B Common Stock, and (vii) the issuance of 70,000 shares of Class B Common Stock to EPE Employee Holdings II, LLC contemplated by the Stockholders Agreement. These preemptive rights will terminate upon the earlier of a Qualified Offering (as defined in the Stockholders Agreement) and a change of control of the Company.

Composition of the Board. The Stockholders Agreement also provides the Sponsors with certain rights with respect to the designation of directors to serve on the Board. The Board is currently comprised of 13 directors, (i) five designated by Apollo, (ii) two designated by Riverstone, (iii) one designated by Access, (iv) one designated by KNOC, (vi) the chief executive officer and (vii) three independent directors. Pursuant to the Stockholders Agreement, Apollo has the right to designate any director as the Chairman of the Board. The three independent directors are "independent" of the Company, the Legacy Stockholders and their affiliates under the rules of the NYSE.

As ownership in the Company by a Sponsor decreases, the Stockholders Agreement provides for the reduction in the number of directors such Sponsor may designate. The tables below state the number of director(s) that each Sponsor may designate to the Board pursuant to the Stockholders Agreement based on such Sponsor's ownership of Class A Common Stock, in each case, expressed as a percentage of its ownership of Class A Common Stock as of the Effective Time (e.g., 75% means that the Sponsor holds 75% of the Class A Common Stock that it held as of the Effective Time).

6

Apollo Ownership	Non-Independent Directors	Independent Directors
At least 75%	5	2
Between 50% and 75%	4	2
Between 25% and 50%	2	1
Between 10% and 25%	1	0
Less than 10%	0	0
Riverstone Ownership	Non-Independent Directors	Independent Directors
50%	2	1
Between 20% and 50%	0	1
Less than 20%	0	0
Access Ownership	Non-Independent Directors	Independent Directors
At least 50%	1	0
Less than 50%	0	0
KNOC Ownership	Non-Independent Directors	Independent Directors
At least 50%	1	0
Less than 50%	0	0

A director that is designated by any Sponsor pursuant to the Stockholders Agreement may be removed and replaced at any time and for any reason (or for no reason) only at the direction and upon the approval of such Sponsor for so long as such Sponsor has the right to designate the applicable director. The replacement of any director will be designated by the Sponsor that designated any such vacant seat unless such Sponsor has lost its right to designate the applicable director pursuant to the above. If the Sponsor has lost its right to designate the applicable director and the Legacy Class A Stockholders hold at least 50% of the outstanding Class A Common Stock, the Legacy Class A Stockholders will have the right to designate a Replacement Director; provided, that such Replacement Director is "independent" of us, the Legacy Stockholders and their affiliates under the rules of the NYSE.

Composition of Board Committees. The Stockholders Agreement also provides that for so long as each Sponsor has the right to designate a director or an observer to the Board (as described below), the Company will cause any committee of the Board to include in its membership such number of members that are consistent with, and reflects, the right of each Sponsor to designate directors or observers to the Board, except to the extent that such membership would violate applicable securities laws or stock exchange or stock market rules. The members of any committee can exclude any board observer from any committee meeting to protect attorney-client privilege, in connection with a conflict of interest, or for any other reason with the consent of the Legacy Class A Stockholder that appointed the board observer, which consent cannot be unreasonably withheld, conditioned or delayed. In addition, for so long as the Negative Control Condition is satisfied, the delegation of power to a committee of the Board will be consistent with

7

and will not circumvent the consent rights described under "—Consent Rights." The Board may not designate an executive committee.

Board Observers. The Stockholders Agreement provides certain Sponsors and Legacy Class A Stockholders with certain rights with respect to the designation of observers to the Board. Each observer generally may attend the meetings of the Board as an observer (and not as a director) and receive the same information given to directors of the Board. No observer has a vote on the Board. The members of the board can exclude any board observer from any board meeting to protect attorney-client privilege, in connection with a conflict of interest, or for any other reason with the consent of the Legacy Class A Stockholder that appointed the board observer, which consent cannot be unreasonably withheld, conditioned or delayed. The tables below state the number of board observers that each Sponsor (other than Apollo which has no such right) and other significant Legacy Class A Stockholders may designate pursuant to the Stockholders Agreement based on such Legacy Class A Stockholder's ownership of Class A Common Stock, in each case, expressed as a percentage of its ownership of Class A Common Stock as of the Effective Time (e.g., 50% means that the Legacy Class A Stockholder holds 50% of the Class A Common Stock that it held as of the Effective Time).

Riverstone Ownership	Board Observer
Between 20% and 50%	2
Less than 20%	0
Access Ownership	Board Observer
Between 20% and 50%	1
Less than 20%	0
KNOC Ownership	Board Observer
Between 20% and 50%	1
Less than 20%	0
Other Significant Legacy Class A Stockholders	Board Observer
Between 20% and 50%	1
Less than 20%	0

Consent Rights. The Stockholders Agreement also provides that for so long as the Negative Control Condition is satisfied, Special Board Approval is required for certain of the significant business decisions, including each of the following:

• change the size or composition of the Board;

• any fundamental changes to the nature of the Company’s business as of the date of the Stockholders Agreement;

• the Company’s or any of its subsidiaries' entry into any voluntary liquidation, dissolution or commencement of bankruptcy or insolvency proceedings, the adoption of a plan with respect to any of the foregoing or the decision not to oppose any similar proceeding commenced by a third party;

• the consummation of a change of control (including a drag-along sale);

8

• consummating any material acquisition or disposition by us of the assets or equity interests of any other entity involving consideration payable or receivable by us in excess of $100 million in the aggregate in any single transaction or series of transactions during any twelve-month period;

• any redemption, repurchase or other acquisition by us of the Company’s equity securities, other than (i) a redemption, repurchase or forfeiture of Class A Common Stock or Class B Common Stock held by EPE Management Investors, LLC and the Legacy Class B Stockholder, respectively, (ii) pursuant to a pro rata offer to all Legacy Stockholders or (iii) pursuant to the exercise of the right of first refusal, in each case, pursuant to the Stockholders Agreement;

• incurring any indebtedness by us (including through capital leases, the issuance of debt securities or the guarantee of indebtedness of another entity) in excess of $250 million or that would otherwise result in us having a leverage ratio of 2.5 to 1.0 or greater;

• hiring or firing the Company’s chief executive officer, chief financial officer or any other member of senior management or approving the compensation arrangements of the Company’s chief executive officer, chief financial officer or any other member of senior management (subject to the prior approval of the Compensation Committee of the Board), in accordance with all applicable governance rules;

• any payment or declaration of any dividend or other distribution on any of the Company’s equity securities or entering into a recapitalization transaction the primary purpose of which is to pay a dividend, other than intra-company dividends among us and the Company’s subsidiaries;

• approval of the Company’s annual budget;

• any authorization, creation (by way of reclassification, merger, consolidation or otherwise) or issuance of any of the Company’s or its subsidiaries' equity securities of any kind (other than any issuance of shares of Class B Common Stock to EPE Employee Holdings II or pursuant to any equity compensation plan of the Company approved by the Compensation Committee, the issuance of equity of a subsidiary of the Company to the Company or one of its wholly owned subsidiaries or a Class B Exchange (as defined in the Stockholders Agreement)), including any designation of the rights (including special voting rights) of one or more classes of the Company’s preferred stock;

• entry by the Company or any of its subsidiaries into any agreement that would restrict any Legacy Class A Stockholders (or any of their affiliates) from entering into or continuing to operate in any line of business or in any geographic area;

• changing any of the Company’s significant accounting policies, except as required by GAAP;

• settle, compromise or initiate any material litigation;

• any adoption, approval or issuance of any "poison pill" or similar rights plan or any amendment of such plan after the adoption thereof has received Special Board Approval;

• any amendment, modification or waiver of the Stockholders Agreement;

• any amendment, modification or waiver of the Certificate of Incorporation or Bylaws; and

• the creation by us of a non-wholly owned subsidiary, other than any non-wholly owned subsidiary that is an operating joint venture entered into by us in the ordinary course of business.

Amendment. The Stockholders Agreement may be amended by a Special Board Approval and the affirmative vote of the Legacy Class A Stockholders holding at least two-thirds of the shares of Class A Common Stock held by the Legacy Class A Stockholders. Further, the Stockholders Agreement may not be amended in a manner that would disproportionally and materially adversely affect the interests of any Legacy Stockholder (in relation to any other Legacy Stockholder after taking into account the rights of such Legacy Stockholder) without the written approval of such Legacy Stockholder.

9

Other Provisions. The Stockholders Agreement further provides that each of the Legacy Stockholders will not vote to amend or modify any provision of the Certificate of Incorporation or Bylaws in a manner that would disproportionally and materially adversely affect the interests of any Legacy Stockholder (in relation to any other Legacy Stockholder after taking into account the rights of such Legacy Stockholder) without the written approval of such Legacy Stockholder. Further, the Stockholders Agreement provides that the Legacy Stockholders will vote and take all other necessary actions to ensure that the Certificate of Incorporation or Bylaws do not conflict with the Stockholders Agreement and to give effect to the provisions of the Stockholders Agreement.

Registration Rights Agreement

The Company entered into the Registration Rights Agreement with the Sponsors and the other Legacy Class A Stockholders in connection with the reorganization that occurred on August 30, 2013. Pursuant to the Registration Rights Agreement, the Company granted the Sponsors and the other Legacy Class A Stockholders the right, under certain circumstances and subject to certain restrictions, to require the Company to register under the Securities Act the shares of Class A Common Stock that are held or acquired by them.

The foregoing summary does not purport to be complete and is subject to, and qualified in its entirety by, the full text of the Certificate of Incorporation and Bylaws. For additional information we encourage you to read the Certificate of Incorporation and Bylaws, including amendments, all of which are exhibits to the Company’s Annual Report on Form 10-K, and applicable provisions of the DGCL.

10

EX-21.1

Exhibit 21.1

Subsidiaries of EP Energy Corporation

As of March 25, 2020

Subsidiary	Jurisdiction	% Owned
EPE Acquisition, LLC	Delaware	100	%
EP Energy LLC	Delaware	100	%
EP Energy Global LLC	Delaware	100	%
EP Energy Management, L.L.C.	Delaware	100	%
EP Energy Resale Company, L.L.C.	Delaware	100	%
EP Energy E&P Company, L.P.1	Delaware	99	%
Everest Acquisition Finance Inc.	Delaware	100	%
EPE Employee Holdings II, LLC	Delaware	100	%

¹ 1% held by EP Energy Management, L.L.C., as general partner

EX-23.2

Exhibit 23.2

TBPE REGISTERED ENGINEERING FIRM F-1580        FAX (713) 651-0849

1100 LOUISIANA SUITE 4600    HOUSTON, TEXAS 77002-5294    TELEPHONE (713) 651-9191

CONSENT OF RYDER SCOTT COMPANY, L.P.

As independent petroleum engineers, Ryder Scott Company, L.P. hereby consents to the reference to us and our report under the captions “Part I. Business – Oil and Natural Gas Properties” and “Part II. Item 8. Financial Statements and Supplementary Data – Supplemental Oil and Natural Gas Operations (Unaudited)” and the inclusion of our reserve report as Exhibit 99.1 in the Annual Report on Form 10-K of EP Energy Corporation for the year ended December 31, 2019.

/s/ Ryder Scott Company, L.P.

RYDER SCOTT COMPANY, L.P.

TBPE Firm Registration No. F-1580

Houston, Texas

March 25, 2020

SUITE 800, 7TH AVENUE, S.W.    CALGARY, ALBERTA T2P 39N    TEL (403) 262-2799    FAX (403) 262-2790

621 17TH STREET, SUITE 1550    DENVER, COLORADO 80293-1501    TEL (303) 623-9147    FAX (303) 623-4258

EX-31.1

Exhibit 31.1

CERTIFICATION

I, Russell E. Parker, certify that:

1. I have reviewed this Annual Report on Form 10-K of EP Energy Corporation;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a 15(f) and 15d 15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; and

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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; and

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting.

5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:	March 25, 2020
		/s/ Russell E. Parker
		Russell E. Parker
		President and Chief Executive Officer
		EP Energy Corporation

EX-31.2

Exhibit 31.2

CERTIFICATION

I, Kyle A. McCuen, certify that:

1. I have reviewed this Annual Report on Form 10-K of EP Energy Corporation;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a 15(f) and 15d 15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; and

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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; and

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting.

5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:	March 25, 2020
		/s/ Kyle A. McCuen
		Kyle A. McCuen
		Senior Vice President, Chief Financial Officer and Treasurer
		EP Energy Corporation

EX-32.1

Exhibit 32.1

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO SECTION 906

OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Annual Report on Form 10-K for the period ending December 31, 2019, of EP Energy Corporation (the “Company”) as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Russell E. Parker, President and Chief Executive Officer, certify (i) that the Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended, and (ii) that the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ Russell E. Parker
Russell E. Parker
President and Chief Executive Officer
EP Energy Corporation
Date:	March 25, 2020

A signed original of this written statement required by Section 906 has been provided to the Company and will be retained by the Company and furnished to the Securities and Exchange Commission or its staff upon request.

EX-32.2

Exhibit 32.2

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO SECTION 906

OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Annual Report on Form 10-K for the period ending December 31, 2019, of EP Energy Corporation (the “Company”) as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Kyle A. McCuen, Senior Vice President, Chief Financial Officer and Treasurer certify (i) that the Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended, and (ii) that the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ Kyle A. McCuen
Kyle A. McCuen
Senior Vice President, Chief Financial
Officer and Treasurer
EP Energy Corporation
Date:	March 25, 2020

A signed original of this written statement required by Section 906 has been provided to the Company and will be retained by the Company and furnished to the Securities and Exchange Commission or its staff upon request.

EX-99.1

Exhibit 99.1

EP ENERGY CORPORATION

SUMMARY REPORT

Estimated

Future Reserves and Income

Attributable to Certain

Leasehold and Royalty Interests

SEC Parameters

As of

December 31, 2019

\s\ Marsha E. Wellmann

Marsha E. Wellmann, P.E.

TBPE License No. 116149

Vice President

[SEAL]

RYDER SCOTT COMPANY, L.P.

TBPE Firm Registration No. F-1580

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

EP Energy Corporation

February 13, 2020

Page 1

TBPE REGISTERED ENGINEERING FIRM F-1580        FAX (713) 651-0849

1100 LOUISIANA SUITE 4600    HOUSTON, TEXAS 77002-5294    TELEPHONE (713) 651-9191

February 13, 2020

EP Energy Corporation

1001 Louisiana

Houston, Texas 77002

Ladies and Gentlemen:

At your request, Ryder Scott Company, L.P. (Ryder Scott) has prepared an estimate of the proved reserves, future production, and income attributable to certain leasehold and royalty interests of EP Energy Corporation (EP Energy) as of December 31, 2019. The subject properties are located in the Eagle Ford shale and Permian Basin in the state of Texas and the Uinta Basin in the state of Utah. The reserves and income data were estimated based on the definitions and disclosure guidelines of the United States Securities and Exchange Commission (SEC) contained in Title 17, Code of Federal Regulations, Modernization of Oil and Gas Reporting, Final Rule released January 14, 2009 in the Federal Register (SEC regulations). Our third party study, completed on February 10, 2020 and presented herein, was prepared for public disclosure by EP Energy in filings made with the SEC in accordance with the disclosure requirements set forth in the SEC regulations.

The properties evaluated by Ryder Scott represent 100 percent of the total net proved liquid hydrocarbon reserves and 100 percent of the total net proved gas reserves of EP Energy as of December 31, 2019.

The estimated reserves and future net income amounts presented in this report, as of December 31, 2019 are related to hydrocarbon prices. The hydrocarbon prices used in the preparation of this report are based on the average prices during the 12-month period prior to the “as of date” of this report, determined as the unweighted arithmetic averages of the prices in effect on the first-day-of-the-month for each month within such period, unless prices were defined by contractual arrangements, as required by the SEC regulations. Actual future prices may vary considerably from the prices required by SEC regulations. The recoverable reserves volumes and the income attributable thereto have a direct relationship to the hydrocarbon prices actually received; therefore, volumes of reserves actually recovered and the amounts of income actually received may differ significantly from the estimated quantities presented in this report. The results of this study are summarized as follows.

SUITE 800, 350 7TH AVENUE, S.W.    CALGARY, ALBERTA T2P 3N9    TEL (403) 262-2799    FAX (403) 262-2790

633 17TH STREET, SUITE 1700    DENVER, COLORADO 80202    TEL (303) 339-8110

EP Energy Corporation

February 13, 2020

Page 2

SEC PARAMETERS

Estimated Net Reserves and Income Data

Certain Leasehold and Royalty Interests of

EP Energy Corporation

As of December 31, 2019

	Total
	Proved
	Producing
Net Reserves
Oil/Condensate – MBBL	92,882
Plant Products – MBBL	39,528
Gas – MMCF	343,847
MBOE	189,718
Income Data (M$)
Future Gross Revenue		$5,718,965
Deductions	2,861,580
Future Net Income (FNI)		$2,857,385
Discounted FNI @ 10%		$1,699,373

Liquid hydrocarbons are expressed in standard 42 U.S. gallon barrels and shown herein as thousands of barrels (MBBL). All gas volumes are reported on an “as sold basis” expressed in millions of cubic feet (MMCF) at the official temperature and pressure bases of the areas in which the gas reserves are located. The net reserves are also shown herein on an equivalent unit basis wherein natural gas is converted to oil equivalent using a factor of 6,000 cubic feet of natural gas per one barrel of oil equivalent. In this report, the revenues, deductions, and income data are expressed as thousands of U.S. dollars (M$).

The estimates of the reserves, future production, and income attributable to properties in this report were prepared using the economic software packageARIES^TM Petroleum Economics and Reserves Software, a copyrighted program of Halliburton. The program was used at the request of EP Energy. Ryder Scott has found this program to be generally acceptable, but notes that certain summaries and calculations may vary due to rounding and may not exactly match the sum of the properties being summarized. Furthermore, one line economic summaries may vary slightly from the more detailed cash flow projections of the same properties, also due to rounding. The rounding differences are not material.

The future gross revenue is after the deduction of production taxes. The deductions incorporate the normal direct costs of operating the wells, ad valorem taxes, certain gas transportation and processing fees which are shown as “Other” deductions in the cash flow projections and certain abandonment costs net of salvage. The future net income is before the deduction of U.S. state and federal income taxes and general administrative overhead, and has not been adjusted for outstanding loans that may exist nor does it include any adjustment for cash on hand or undistributed income.

Liquid hydrocarbon reserves account for approximately 94 percent and gas reserves account for the remaining 6 percent of total future gross revenue from proved reserves.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

EP Energy Corporation

February 13, 2020

Page 3

The discounted future net income shown above was calculated using a discount rate of 10 percent per annum compounded monthly. Future net income was discounted at four other discount rates which were also compounded monthly. These results are shown in summary form as follows.

	Discounted Future Net Income (M$)
	As of December 31, 2019
Discount Rate		Total
Percent		Proved
5		$2,124,753
9		$1,768,931
15		$1,427,624
20		$1,240,326

The results shown above are presented for your information and should not be construed as our estimate of fair market value.

Reserves Included in This Report

The proved reserves included herein conform to the definition as set forth in the Securities and Exchange Commission’s Regulations Part 210.4-10(a). An abridged version of the SEC reserves definitions from 210.4-10(a) entitled “PETROLEUM RESERVES DEFINITIONS” is included as an attachment to this report.

The various reserves status categories are defined in the attachment entitled “PETROLEUM RESERVES STATUS DEFINITIONS AND GUIDELINES” in this report.

No attempt was made to quantify or otherwise account for any accumulated gas production imbalances that may exist. The provedgas volumes presented herein do not include volumes of gas consumed in operations as reserves.

Reserves are “estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations.” All reserves estimates involve an assessment of the uncertainty relating the likelihood that the actual remaining quantities recovered will be greater or less than the estimated quantities determined as of the date the estimate is made. The uncertainty depends chiefly on the amount of reliable geologic and engineering data available at the time of the estimate and the interpretation of these data. The relative degree of uncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or unproved. Unproved reserves are less certain to be recovered than proved reserves and may be further sub-categorized as probable and possible reserves to denote progressively increasing uncertainty in their recoverability. At EP Energy’s request, this report addresses only the proved reserves attributable to the properties evaluated herein.

Proved oil and gas reserves are “those quantities of oil and gas which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward.” The proved reserves included herein were estimated using deterministic methods. The SEC has defined reasonable certainty for proved reserves, when based on deterministic methods, as a “high degree of confidence that the quantities will be recovered.”

Proved reserves estimates will generally be revised only as additional geologic or engineering data become available or as economic conditions change. For proved reserves, the SEC states that “as changes

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

EP Energy Corporation

February 13, 2020

Page 4

due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to the estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease.” Moreover, estimates of proved reserves may be revised as a result of future operations, effects of regulation by governmental agencies or geopolitical or economic risks. Therefore, the proved reserves included in this report are estimates only and should not be construed as being exact quantities, and if recovered, the revenues therefrom, and the actual costs related thereto, could be more or less than the estimated amounts.

EP Energy’s operations may be subject to various levels of governmental controls and regulations. These controls and regulations may include, but may not be limited to, matters relating to land tenure and leasing, the legal rights to produce hydrocarbons, drilling and production practices, environmental protection, marketing and pricing policies, royalties, various taxes and levies including income tax and are subject to change from time to time. Such changes in governmental regulations and policies may cause volumes of proved reserves actually recovered and amounts of proved income actually received to differ significantly from the estimated quantities.

The estimates of proved reserves presented herein were based upon a detailed study of the properties in which EP Energy owns an interest; however, we have not made any field examination of the properties. No consideration was given in this report to potential environmental liabilities that may exist nor were any costs included for potential liabilities to restore and clean up damages, if any, caused by past operating practices.

Estimates of Reserves

The estimation of reserves involves two distinct determinations. The first determination results in the estimation of the quantities of recoverable oil and gas and the second determination results in the estimation of the uncertainty associated with those estimated quantities in accordance with the definitions set forth by the Securities and Exchange Commission’s Regulations Part 210.4-10(a). The process of estimating the quantities of recoverable oil and gas reserves relies on the use of certain generally accepted analytical procedures. These analytical procedures fall into three broad categories or methods: (1) performance-based methods, (2) volumetric-based methods and (3) analogy. These methods may be used individually or in combination by the reserves evaluator in the process of estimating the quantities of reserves. Reserves evaluators must select the method or combination of methods which in their professional judgment is most appropriate given the nature and amount of reliable geoscience and engineering data available at the time of the estimate, the established or anticipated performance characteristics of the reservoir being evaluated, and the stage of development or producing maturity of the property.

In many cases, the analysis of the available geoscience and engineering data and the subsequent interpretation of this data may indicate a range of possible outcomes in an estimate, irrespective of the method selected by the evaluator. When a range in the quantity of reserves is identified, the evaluator must determine the uncertainty associated with the incremental quantities of the reserves. If the reserves quantities are estimated using the deterministic incremental approach, the uncertainty for each discrete incremental quantity of the reserves is addressed by the reserves category assigned by the evaluator. Therefore, it is the categorization of reserves quantities as proved, probable and/or possible that addresses the inherent uncertainty in the estimated quantities reported. For proved reserves, uncertainty is defined by the SEC as reasonable certainty wherein the “quantities actually recovered are much more likely to be achieved than not.” The SEC states that “probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.” The SEC states that “possible reserves are those additional reserves that are less certain to be recovered than probable reserves and the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves.” All quantities of reserves within the same reserves category must meet the SEC definitions as noted above.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

EP Energy Corporation

February 13, 2020

Page 5

Estimates of reserves quantities and their associated reserves categories may be revised in the future as additional geoscience or engineering data become available. Furthermore, estimates of reserves quantities and their associated reserves categories may also be revised due to other factors such as changes in economic conditions, results of future operations, effects of regulation by governmental agencies or geopolitical or economic risks as previously noted herein.

The proved producing reserves were estimated by performance methods alone or a combination of methods including analogy where there were inadequate historical performance data to establish a definitive trend and where the use of production performance data as the sole basis for the reserve estimates was considered to be inappropriate. Decline curve analysis was used as the primary methodology for all of the proved producing reserves.

The data utilized in this analysis, available through December 2019, were furnished to Ryder Scott by EP Energy or obtained from public data sources and were considered sufficient for the purpose thereof.

To estimate economically recoverable proved oil and gas reserves and related future net cash flows, we consider many factors and assumptions including, but not limited to, the use of reservoir parameters derived from geological, geophysical and engineering data which cannot be measured directly, economic criteria based on current costs and SEC pricing requirements, and forecasts of future production rates. Under the SEC regulations 210.4-10(a)(22)(v) and (26), proved reserves must be anticipated to be economically producible from a given date forward based on existing economic conditions including the prices and costs at which economic producibility from a reservoir is to be determined. While it may reasonably be anticipated that the future prices received for the sale of production and the operating costs and other costs relating to such production may increase or decrease from those under existing economic conditions, such changes were, in accordance with rules adopted by the SEC, omitted from consideration in making this evaluation.

EP Energy has informed us that they have furnished us all of the material accounts, records, geological and engineering data, and reports and other data required for this investigation. In preparing our forecast of future proved production and income, we have relied upon data furnished by EP Energy with respect to property interests owned, production and well tests from examined wells, normal direct costs of operating the wells or leases, other costs such as transportation and/or processing fees, ad valorem and production taxes, abandonment costs after salvage, product prices based on the SEC regulations, adjustments or differentials to product prices, geological structural and isochore maps, well logs, core analyses, and pressure measurements. Ryder Scott reviewed such factual data for its reasonableness; however, we have not conducted an independent verification of the data furnished by EP Energy. We consider the factual data used in this report appropriate and sufficient for the purpose of preparing the estimates of reserves and future net revenues herein.

In summary, we consider the assumptions, data, methods and analytical procedures used in this report appropriate for the purpose hereof, and we have used all such methods and procedures that we consider necessary and appropriate to prepare the estimates of reserves herein. The proved reserves included herein were determined in conformance with the United States Securities and Exchange Commission (SEC) Modernization of Oil and Gas Reporting; Final Rule, including all references to Regulation S-X and Regulation S-K, referred to herein collectively as the “SEC Regulations.” In our opinion, the proved reserves presented in this report comply with the definitions, guidelines and disclosure requirements as required by the SEC regulations.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

EP Energy Corporation

February 13, 2020

Page 6

Future Production Rates

For wells currently on production, our forecasts of future production rates are based on historical performance data. If no production decline trend has been established, future production rates were adjusted for the effects of curtailment where appropriate and were based on analogue performance data until a decline in ability to produce was anticipated. An estimated rate of decline was applied until depletion of the reserves. If a decline trend has been established, this trend was used as the basis for estimating future production rates.

The future production rates from wells currently on production may be more or less than estimated because of changes including, but not limited to, reservoir performance, operating conditions related to surface facilities, compression and artificial lift, pipeline capacity and/or operating conditions, producing market demand and/or allowables or other constraints set by regulatory bodies.

Hydrocarbon Prices

The hydrocarbon prices used herein are based on SEC price parameters using the average prices during the 12-month period prior to the “as of date” of this report, determined as the unweighted arithmetic averages of the prices in effect on the first-day-of-the-month for each month within such period, unless prices were defined by contractual arrangements. For hydrocarbon products sold under contract, the contract prices, including fixed and determinable escalations, exclusive of inflation adjustments, were used until expiration of the contract. Upon contract expiration, the prices were adjusted to the 12-month unweighted arithmetic average as previously described.

EP Energy furnished us with the above mentioned average prices in effect on December 31, 2019. These initial SEC hydrocarbon prices were determined using the 12-month average first-day-of-the-month benchmark prices appropriate to the geographic area where the hydrocarbons are sold. These benchmark prices are prior to the adjustments for differentials as described herein. The table below summarizes the “benchmark prices” and “price reference” used for the geographic area included in the report. In certain geographic areas, the price reference and benchmark prices may be defined by contractual arrangements.

The product prices which were actually used to determine the future gross revenue for each property reflect adjustments to the benchmark prices for gravity, quality, local conditions, and/or distance from market, referred to herein as “differentials.” The differentials used in the preparation of this report were furnished to us by EP Energy. The differentials furnished to us were accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an independent verification of the data used by EP Energy to determine these differentials.

In addition, the table below summarizes the net volume weighted benchmark prices adjusted for differentials and referred to herein as the “average realized prices.” The average realized prices shown in the table below were determined from the total future gross revenue before production taxes and the total net reserves for the geographic area and presented in accordance with SEC disclosure requirements for each of the geographic areas included in the report.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

EP Energy Corporation

February 13, 2020

Page 7

Geographic Area	Product	Price Reference	Average Benchmark Prices	Average Realized Prices
North America
	Oil/Condensate	WTI Cushing	$55.69/BBL	$55.34/BBL
United States	NGLs	WTI Cushing	$55.69/BBL	$13.37/BBL
	Gas	Henry Hub	$2.577/MMBTU	$1.04/MCF

The effects of derivative instruments designated as price hedges of oil and gas quantities are not reflected in our individual property evaluations.

Costs

Operating costs for the leases and wells in this report are based on the operating expense reports of EP Energy and include only those costs directly applicable to the leases or wells. The operating costs for non-operated properties include the COPAS overhead costs that are allocated directly to the leases and wells under terms of operating agreements. The operating costs used in the preparation of this report were estimated by us based on information furnished by EP Energy.No deduction was made for loan repayments or interest expenses, or exploration and development prepayments that were not charged directly to the leases or wells.

The estimated net cost of abandonment after salvage was included for properties where abandonment costs net of salvage were material. The estimates of the net abandonment costs furnished by EP Energy were accepted without independent verification.

Current costs used by EP Energy were held constant throughout the life of the properties.

Standards of Independence and Professional Qualification

Ryder Scott is an independent petroleum engineering consulting firm that has been providing petroleum consulting services throughout the world since 1937. Ryder Scott is employee-owned and maintains offices in Houston, Texas; Denver, Colorado; and Calgary, Alberta, Canada. We have approximately eighty engineers and geoscientists on our permanent staff. By virtue of the size of our firm and the large number of clients for which we provide services, no single client or job represents a material portion of our annual revenue. We do not serve as officers or directors of any privately-owned or publicly-traded oil and gas company and are separate and independent from the operating and investment decision-making process of our clients. This allows us to bring the highest level of independence and objectivity to each engagement for our services.

Ryder Scott actively participates in industry-related professional societies and organizes an annual public forum focused on the subject of reserves evaluations and SEC regulations. Many of our staff have authored or co-authored technical papers on the subject of reserves related topics. We encourage our staff to maintain and enhance their professional skills by actively participating in ongoing continuing education.

Prior to becoming an officer of the Company, Ryder Scott requires that staff engineers and geoscientists have received professional accreditation in the form of a registered or certified professional engineer’s license or a registered or certified professional geoscientist’s license, or the equivalent thereof, from an appropriate governmental authority or a recognized self-regulating professional organization.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

EP Energy Corporation

February 13, 2020

Page 8

Regulating agencies require that, in order to maintain active status, a certain amount of continuing education hours be completed annually, including an hour of ethics training. Ryder Scott fully supports this technical and ethics training with our internal requirement mentioned above.

We are independent petroleum engineers with respect to EP Energy. Neither we nor any of our employees have any financial interest in the subject properties and neither the employment to do this work nor the compensation is contingent on our estimates of reserves for the properties which were reviewed.

The results of this study, presented herein, are based on technical analysis conducted by teams of geoscientists and engineers from Ryder Scott. The professional qualifications of the undersigned, the technical person primarily responsible for overseeing the evaluation of the reserves information discussed in this report, are included as an attachment to this letter.

Terms of Usage

The results of our third party study, presented in report form herein, were prepared in accordance with the disclosure requirements set forth in the SEC regulations and intended for public disclosure as an exhibit in filings made with the SEC by EP Energy.

EP Energy makes periodic filings on Form 10-K with the SEC under the 1934 Exchange Act. Furthermore, EP Energy has certain registration statements filed with the SEC under the 1933 Securities Actinto which any subsequently filed Form 10-K is incorporated by reference. We have consented to the incorporation by reference in the registration statements on Forms S-3 and S-8of EP Energy, of the references to our name, as well as to the references to our third party report for EP Energy, which appears in the December 31, 2019 annual report on Form 10-Kof EP Energy. Our written consent for such use is included as a separate exhibit to the filings made with the SEC by EP Energy.

We have provided EP Energy with a digital version of the original signed copy of this report letter. In the event there are any differences between the digital version included in filings made by EP Energy and the original signed report letter, the original signed report letter shall control and supersede the digital version.

The data and work papers used in the preparation of this report are available for examination by authorized parties in our offices. Please contact us if we can be of further service.

Very truly yours,

RYDER SCOTT COMPANY, L.P.

TBPE Firm Registration No. F-1580

\s\ Marsha E. Wellmann

Marsha E. Wellmann, P.E.

TBPE License No. 116149

Vice President                [SEAL]

MEW (LPC)/pl

Professional Qualifications of Primary Technical Person

The conclusions presented in this report are the result of technical analysis conducted by teams of geoscientists and engineers from Ryder Scott Company, L.P. Ms. Marsha E. Wellmann was the primary technical person responsible for overseeing the estimate of the reserves, future production and income prepared by Ryder Scott presented herein.

Ms. Wellmann, an employee of Ryder Scott Company L.P. (Ryder Scott) since 2012, is a Vice President responsible for coordinating and supervising staff and consulting engineers of the company in ongoing reservoir evaluation studies throughout North America and the Gulf of Mexico. Before joining Ryder Scott, Ms. Wellmann served in a number of engineering positions. For more information regarding Ms. Wellmann geographic and job specific experience, please refer to the Ryder Scott Company website at www.ryderscott.com/Company/Employees.

Ms. Wellmann earned a Bachelor of Science degree in Petroleum Engineering and a Business Foundations Certificate from The University of Texas at Austin in 2002 and is a registered Professional Engineer in the State of Texas. She is also a member of the Society of Petroleum Engineers.

In addition to gaining experience and competency through prior work experience, the Texas Board of Professional Engineers requires a minimum of fifteen hours of continuing education annually, including at least one hour in the area of professional ethics, which Ms. Wellmann fulfills. As part of her 2019 continuing education hours, Ms. Wellmann attended 18hours of formalized training including various professional society presentations covering such topics as the definitions and disclosure guidelines contained in the United States Securities and Exchange Commission Title 17, Code of Federal Regulations, Modernization of Oil and Gas Reporting, Final Rule released January 14, 2009 in the Federal Register, the SPE/WPC/AAPG/SPEE Petroleum Resources Management System, reservoir engineering, geoscience and petroleum economics evaluation methods, procedures and software and ethics for consultants.

Based on her educational background, professional training and more than 15 years of practical experience in the estimation and evaluation of petroleum reserves, Ms. Wellmann has attained the professional qualifications as a Reserves Estimator set forth in Article III of the “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information” promulgated by the Society of Petroleum Engineers as of February 19, 2007.

PETROLEUM RESERVES DEFINITIONS

As Adapted From:

RULE 4-10(a) of REGULATION S-X PART 210

UNITED STATES SECURITIES AND EXCHANGE COMMISSION (SEC)

PREAMBLE

On January 14, 2009, the United States Securities and Exchange Commission (SEC) published the “Modernization of Oil and Gas Reporting; Final Rule” in the Federal Register of National Archives and Records Administration (NARA). The “Modernization of Oil and Gas Reporting; Final Rule” includes revisions and additions to the definition section in Rule 4-10 of Regulation S-X, revisions and additions to the oil and gas reporting requirements in Regulation S-K, and amends and codifies Industry Guide 2 in Regulation S-K. The “Modernization of Oil and Gas Reporting; Final Rule”, including all references to Regulation S-X and Regulation S-K, shall be referred to herein collectively as the “SEC regulations”. The SEC regulations take effect for all filings made with the United States Securities and Exchange Commission as of December 31, 2009, or after January 1, 2010. Reference should be made to the full text under Title 17, Code of Federal Regulations, Regulation S-X Part 210, Rule 4-10(a) for the complete definitions (direct passages excerpted in part or wholly from the aforementioned SEC document are denoted in italics herein).

Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations.All reserve estimates involve an assessment of the uncertainty relating the likelihood that the actual remaining quantities recovered will be greater or less than the estimated quantities determined as of the date the estimate is made. The uncertainty depends chiefly on the amount of reliable geologic and engineering data available at the time of the estimate and the interpretation of these data. The relative degree of uncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or unproved. Unproved reserves are less certain to be recovered than proved reserves and may be further sub-classified as probable and possible reserves to denote progressively increasing uncertainty in their recoverability. Under the SEC regulations as of December 31, 2009, or after January 1, 2010, a company may optionally disclose estimated quantities of probable or possible oil and gas reserves in documents publicly filed with the SEC. The SEC regulations continue to prohibit disclosure of estimates of oil and gas resources other than reserves and any estimated values of such resources in any document publicly filed with the SEC unless such information is required to be disclosed in the document by foreign or state law as noted in §229.1202 Instruction to Item 1202.

Reserves estimates will generally be revised only as additional geologic or engineering data become available or as economic conditions change.

Reserves may be attributed to either natural energy or improved recovery methods. Improved recovery methods include all methods for supplementing natural energy or altering natural forces in the reservoir to increase ultimate recovery. Examples of such methods are pressure maintenance, natural gas cycling, waterflooding, thermal methods, chemical flooding, and the use of miscible and immiscible displacement fluids. Other improved recovery methods may be developed in the future as petroleum technology continues to evolve.

Reserves may be attributed to either conventional or unconventional petroleum accumulations. Petroleum accumulations are considered as either conventional or unconventional based on the nature of their in-place characteristics, extraction method applied, or degree of processing prior to sale. Examples of unconventional petroleum accumulations include coalbed or coalseam methane (CBM/CSM), basin-centered gas, shale gas, gas hydrates, natural bitumen and oil shale deposits. These unconventional accumulations may require specialized extraction technology and/or significant processing prior to sale.

Reserves do not include quantities of petroleum being held in inventory.

Because of the differences in uncertainty, caution should be exercised when aggregating quantities of petroleum from different reserves categories.

RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(26) defines reserves as follows:

Reserves. Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.

Note to paragraph (a)(26): Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir, or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).

PROVED RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(22) defines proved oil and gas reserves as follows:

Proved oil and gas reserves. Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

(i) The area of the reservoir considered as proved includes:

(A) The area identified by drilling and limited by fluid contacts, if any, and

(B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.

(ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.

(iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.

(iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when:

(A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and

(B) The project has been approved for development by all necessary parties and entities, including governmental entities.

(v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

PETROLEUM RESERVES STATUS DEFINITIONS AND GUIDELINES

As Adapted From:

RULE 4-10(a) of REGULATION S-X PART 210

UNITED STATES SECURITIES AND EXCHANGE COMMISSION (SEC)

and

2018 PETROLEUM RESOURCES MANAGEMENT SYSTEM (SPE-PRMS)

Sponsored and Approved by:

SOCIETY OF PETROLEUM ENGINEERS (SPE)

WORLD PETROLEUM COUNCIL (WPC)

AMERICAN ASSOCIATION OF PETROLEUM GEOLOGISTS (AAPG)

SOCIETY OF PETROLEUM EVALUATION ENGINEERS (SPEE)

SOCIETY OF EXPLORATION GEOPHYSICISTS (SEG)

SOCIETY OF PETROPHYSICISTS AND WELL LOG ANALYSTS (SPWLA)

EUROPEAN ASSOCIATION OF GEOSCIENTISTS & ENGINEERS (EAGE)

Reserves status categories define the development and producing status of wells and reservoirs. Reference should be made to Title 17, Code of Federal Regulations, Regulation S-X Part 210, Rule 4-10(a) and the SPE-PRMS as the following reserves status definitions are based on excerpts from the original documents (direct passages excerpted from the aforementioned SEC and SPE-PRMS documents are denoted in italics herein).

DEVELOPED RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(6) defines developed oil and gas reserves as follows:

Developed oil and gas reserves are reserves of any category that can be expected to be recovered:

(i) Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and

(ii) Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

Developed Producing (SPE-PRMS Definitions)

While not a requirement for disclosure under the SEC regulations, developed oil and gas reserves may be further sub-classified according to the guidance contained in the SPE-PRMS as Producing or Non-Producing.

Developed Producing Reserves

Developed Producing Reserves are expected quantities to be recovered from completion intervals that are open and producing at the effective date of the estimate.

Improved recovery reserves are considered producing only after the improved recovery project is in operation.

Developed Non-Producing

Developed Non-Producing Reserves include shut-in and behind-pipe Reserves.

Shut-In

Shut-in Reserves are expected to be recovered from:

(1) completion intervals that are open at the time of the estimate but which have not yet started producing;

(2) wells which were shut-in for market conditions or pipeline connections; or

(3) wells not capable of production for mechanical reasons.

Behind-Pipe

Behind-pipe Reserves are expected to be recovered from zones in existing wells that will require additional completion work or future re-completion before start of production with minor cost to access these reserves.

In all cases, production can be initiated or restored with relatively low expenditure compared to the cost of drilling a new well.

UNDEVELOPED RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(31) defines undeveloped oil and gas reserves as follows:

Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

(i) Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.

(ii) Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time.

(iii) Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined in paragraph (a)(2) of this section, or by other evidence using reliable technology establishing reasonable certainty.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

XML

Incentive Compensation / 401(k) Retirement Plan - Restricted Stock Narrative (Details) $ in Millions	12 Months Ended
	Dec. 31, 2019 USD ($)
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Recognition period of fair value as compensation cost	1 year
Restricted Stock
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period	3 years
Unrecognized compensation cost	$ 6
Recognition period of fair value as compensation cost	2 years

XML

Incentive Compensation / 401(k) Retirement Plan - Key Employee Retention Program Narrative (Details) - USD ($) $ in Millions	1 Months Ended		12 Months Ended
	Jul. 31, 2019	Jul. 31, 2018	Dec. 31, 2019
Share-based Payment Arrangement [Abstract]
KERP payments	$ 21
Target performance dollar of actual payout	10
Retention bonus payout	$ 11
Deferred compensation plan assets			$ 10
KERP agreement term		13 months
KERP compensation expense			$ 10

XML

Income Taxes - Federal and State Net Operating Loss and Tax Credit Carryovers (Details) $ in Millions	Dec. 31, 2019 USD ($)
U.S.
Income Taxes
Net operating loss carryover	$ 2,953
U.S. | 2031 - 2037
Income Taxes
Net operating loss carryover	2,524
U.S. | No Expiration
Income Taxes
Net operating loss carryover	429
State | 2026 - 2038
Income Taxes
Net operating loss carryover	$ 480

XML

Income Taxes - Pretax Loss and the Components of Income Tax Benefit (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Income Tax Disclosure [Abstract]
Pretax Loss	$ (943)	$ (1,003)
Current
Federal	0	0
State	0	0
Current income tax benefit	0	0
Deferred
Federal	0	0
State	0	0
Total income tax expense	$ 0	$ 0

XML

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Cash flows from operating activities
Net loss	$ (943)	$ (1,003)
Adjustments to reconcile net loss to net cash provided by operating activities
Depreciation, depletion and amortization	418	507
Gain on sale of assets	0	(3)
Impairment charges	458	1,103
Gain on extinguishment/modification of debt	(10)	(73)
Write-off of debt discount and deferred issue costs	90	0
Reorganization items, net	24	0
Other non-cash income items	23	30
Asset and liability changes
Accounts receivable	85	(56)
Owner and royalties payable	(72)	32
Accounts payable and accrued expenses	21	(24)
Derivative instruments	105	(109)
Accrued interest	86	8
Other asset changes	(37)	8
Other liability changes	(21)	2
Net cash provided by operating activities	227	422
Cash flows from investing activities
Cash paid for capital expenditures	(497)	(690)
Proceeds from the sale of assets	0	192
Cash paid for acquisitions	(21)	(292)
Net cash used in investing activities	(518)	(790)
Cash flows from financing activities
Proceeds from issuance of long-term debt	923	2,090
Repayments and repurchases of long-term debt	(765)	(1,654)
Proceeds from borrowing under DIP Facility	298	0
Repayment of borrowings from DIP Facility	(150)	0
DIP Facility costs	(6)	0
Fees/costs on debt exchange	0	(62)
Other debt issue costs	(2)	(22)
Other	(1)	(2)
Net cash provided by financing activities	297	350
Change in cash, cash equivalents and restricted cash	6	(18)
Cash, cash equivalents and restricted cash - beginning of period	27	45
Cash, cash equivalents and restricted cash - end of period	33	27
Supplemental cash flow information
Interest paid, net of amounts capitalized	226	337
Income tax refunds	$ 0	$ (9)

XML

Basis of Presentation and Significant Accounting Policies, Voluntary Reorganization under Chapter 11 Cases (Polices)

12 Months Ended

Dec. 31, 2019

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Basis of Presentation

Our consolidated financial statements are prepared in accordance with United States generally accepted accounting principles (“U.S. GAAP”) and include the accounts of all consolidated subsidiaries after the elimination of all significant intercompany accounts and transactions. 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. The consolidated financial statements included herein have been prepared as if we were a going concern and in accordance with Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) Topic No. 852, Reorganizations. For a further discussion of our Chapter 11 filing, see Note 1A.

Consolidation

We consolidate entities when we have the ability to control the operating and financial decisions of the entity or when we have a significant interest in the entity that gives us the ability to direct the activities that are significant to that entity. The determination of our ability to control, direct or exert significant influence over an entity involves the use of judgment.

Segment Reporting

We are engaged in the exploration for and the acquisition, development, and production of oil, natural gas and NGLs in the United States. Our oil and natural gas properties are managed as a single operating segment rather than through discrete operating segments or business units. We track basic operational data by area and allocate capital resources on a project-by-project basis across our entire asset base without regard to individual areas.  We assess financial performance as a single enterprise and not on a geographical area basis.

New Accounting Pronouncements Issued But Not Yet Adopted

New Accounting Pronouncements Issued But Not Yet Adopted

Income Taxes. In December 2019, the FASB issued ASU No. 2019-12, Income Taxes (Topic 740): Simplifying the Accounting for Income Taxes, which is intended to simplify various aspects related to accounting for income taxes by eliminating certain exceptions within ASC 740, Income Taxes, and clarifying certain aspects of the current guidance. This standard is effective beginning for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2020, with early adoption permitted. The Company is in the process of assessing the impact the adoption of this guidance may have on our consolidated financial statements.

Use of Estimates

Use of Estimates

The preparation of our financial statements requires the use of estimates and assumptions that affect the amounts we report as assets, liabilities, revenues and expenses and our disclosures in these financial statements. Actual results can, and often do, differ from those estimates.

Revenue Recognition

Revenue Recognition

Our revenues are generated primarily through the physical sale of oil, natural gas and NGLs to third party customers at spot or market prices under both short and long-term contracts. We recognize revenue upon satisfaction of our contractual performance obligation requiring us to deliver oil, natural gas and NGLs to a delivery point. Our performance obligation is satisfied upon transfer of control of the commodity to the customer. Transfer of control varies depending on the product and delivery method, but typically occurs when delivery and passage of title and risk of loss have occurred at a pipeline or gathering line delivery point interconnect when delivered via pipeline or at the wellhead or tank battery to purchasers who transport the oil via truck. Realized prices for each barrel of oil, MMcf of natural gas or MMBtu of NGLs are based upon index prices (WTI, LLS, Henry Hub and Mt. Belvieu) or refiners' posted prices at various delivery points across our producing basins. Realized transaction prices received (not considering the effects of hedges) are generally less than the stated index price as a result of contractual deductions, differentials from the index to the delivery point, adjustments for time, and/or discounts for quality or grade.

Revenue is recorded net of any royalty interests or other profit interests in the produced product. Revenues related to products delivered, but not yet billed, are estimated each month. These estimates are based on contract data, commodity prices and preliminary throughput and allocation measurements. When actual sales volumes exceed our entitled share of sales volumes, an overproduced imbalance occurs. To the extent the overproduced imbalance exceeds our share of the remaining estimated proved natural gas reserves for a given property, we record a liability. 

Costs associated with the transportation and delivery of production between the wellhead and its intended sale location are generally included in transportation costs.  We also purchase and sell oil and natural gas on a monthly basis to manage our overall oil and natural gas production and sales. These transactions are undertaken to optimize prices we receive for our oil and natural gas, to physically move oil and gas to its intended sales point, or to manage firm transportation agreements. Revenue related to these transactions are recorded in oil and natural gas sales in operating revenues and associated purchases reflected in oil and natural gas purchases in operating expenses in our consolidated income statements.

For the years ended December 31, 2019 and 2018, we had two and three customers, respectively, that individually accounted for 10 percent or more of our total revenues. The loss of any one customer would not have an adverse effect on our ability to sell our oil, natural gas and NGLs production.

While most of our physical production is priced off of market indices, we actively manage the volatility of market pricing through our risk management program whereby we enter into financial derivatives contracts. All of our derivatives are marked-to-market each period. The change in the fair value of our commodity-based derivatives, as well as any realized amounts, are reflected in operating revenues as financial derivative revenues (see Derivatives below and Note 6).

Cash and Cash Equivalents and Restricted Cash

Cash and Cash Equivalents and Restricted Cash

We consider short-term investments with an original maturity of less than three months to be cash equivalents.

Allowance for Doubtful Accounts

Allowance for Doubtful Accounts

We establish provisions for losses on accounts receivable and for natural gas imbalances with other parties if we determine that we will not collect all or part of the outstanding balance. We regularly review collectability and establish or adjust our allowance as necessary using the specific identification method.

Oil and Natural Gas Properties

Oil and Natural Gas Properties

We account for oil and natural gas properties in accordance with the successful efforts method of accounting for oil and natural gas exploration and development activities.

Under the successful efforts method, we capitalize (i) lease acquisition costs, all development costs and exploratory drilling costs until results are determined, (ii) certain internal costs directly identified with the acquisition, successful drilling of exploratory wells and development activities, and (iii) interest costs related to financing oil and natural gas projects actively being developed until the projects are evaluated or substantially complete and ready for their intended use if the projects were evaluated as successful. Non-drilling exploratory costs, including certain geological and geophysical costs such as seismic costs and delay rentals, are expensed as incurred.

We provide for depreciation, depletion, and amortization on the basis of common geological structure or stratigraphic conditions applied to total capitalized costs, plus future abandonment costs, net of salvage value, using the unit of production method.  Lease acquisition costs are amortized over total proved reserves, while other exploratory drilling and all developmental costs are amortized over total proved developed reserves.

We evaluate capitalized costs related to proved properties upon a triggering event to determine if impairment of such properties is necessary.  Our evaluation of recoverability is made on the basis of common geological structure or stratigraphic conditions and considers estimated future cash flows primarily from all proved developed (producing and non-producing) and proved undeveloped reserves in comparison to the carrying amount of the proved properties. Estimated future cash flows are determined based on estimates of future oil and gas production, estimated or published commodity prices as of the date of the estimate, adjusted for geographical location, contractual and quality price differentials, and estimates of future operating and development costs. If the carrying amount of a property exceeds these estimated undiscounted future cash flows, the carrying amount is reduced to its estimated fair value through a charge to income. Fair value is calculated by discounting the estimated future cash flows using a risk-adjusted discount rate. This 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. Leasehold acquisition costs associated with non-producing areas are also assessed for impairment based on our estimated drilling plans and anticipated capital expenditures related to potential lease expirations.

Property, Plant and Equipment (Other than Oil and Natural Gas Properties)

Property, Plant and Equipment (Other than Oil and Natural Gas Properties)

Our property, plant and equipment, other than our assets accounted for under the successful efforts method, are recorded at their original cost of construction or, upon acquisition, at the fair value of the assets acquired. We capitalize the major units of property replacements or improvements and expense minor items. We depreciate our non-oil and natural gas property, plant and equipment using the straight-line method over the useful lives of the assets which range from four to seven years. 

Accounting for Asset Retirement Obligations

Accounting for Asset Retirement Obligations

We record a liability for legal obligations associated with the replacement, removal or retirement of our long-lived assets in the period the obligation is incurred and is estimable. Our asset retirement liabilities are initially recorded at their estimated fair value with a corresponding increase to property, plant and equipment. This increase in property, plant and equipment is then depreciated over the useful life of the asset to which that liability relates. An ongoing expense is recognized for changes in the value of the liability as a result of the passage of time, which we record as depreciation, depletion and amortization expense in our consolidated income statements.

Accounting for Long-Term Incentive Compensation

Accounting for Long-Term Incentive Compensation

We measure the cost of long-term incentive compensation based on the fair value of the award on the day it is granted.  Awards issued under our incentive compensation programs are recognized as either equity awards or liability awards based on their characteristics.  Expense is recognized in our consolidated financial statements as general and administrative expense over the period of service required by the award. See Note 10 for further discussion of our long-term incentive compensation.

Environmental Costs, Legal and Other Contingencies

Environmental Costs, Legal and Other Contingencies

Environmental Costs. We record environmental liabilities at their undiscounted amounts on our consolidated balance sheet in other current and long-term liabilities when we assess that remediation efforts are probable and the costs can be reasonably estimated. Estimates of our environmental liabilities are based on current available facts, existing technology and presently enacted laws and regulations, taking into consideration the likely effects of other societal and economic factors, and include estimates of associated legal costs. These amounts also consider prior experience in remediating contaminated sites, other companies’ clean-up experience and data released by the Environmental Protection Agency (EPA) or other organizations. Our estimates are subject to revision in future periods based on actual costs or new circumstances. We capitalize costs that benefit future periods and expense costs that do not in general and administrative expense.

We evaluate any amounts paid directly or reimbursed by government sponsored programs and potential recoveries or reimbursements of remediation costs from third parties, including insurance coverage, separately from our liability. Recovery is evaluated based on the creditworthiness or solvency of the third party, among other factors. When recovery is assured, we record and report an asset separately from the associated liability on our consolidated balance sheet.

Legal and Other Contingencies.  We recognize liabilities for legal and other contingencies when we have an exposure that indicates it is both probable that a liability has been incurred and the amount of the loss can be reasonably estimated. Where the most likely outcome of a contingency can be reasonably estimated, we accrue a liability for that amount. Where the most likely outcome cannot be estimated, a range of potential losses is established and if no one amount in that range is more likely than any other to occur, the low end of the range is accrued.

Derivatives

Derivatives

We enter into derivative contracts on our oil and natural gas products primarily to stabilize cash flows and reduce the risk and financial impact of downward commodity price movements on commodity sales.  Derivative instruments are reflected on our consolidated balance sheet at their fair value as assets and liabilities. We classify our derivatives as either current or non-current based on their anticipated settlement date. We net derivative assets and liabilities with counterparties where we have a legal right of offset.

All of our derivatives are marked-to-market each period and changes in the fair value of our commodity based derivatives, as well as any realized amounts, are reflected as operating revenues. We classify cash flows related to derivative contracts based on the nature and purpose of the derivative. As the derivative cash flows are considered an integral part of our oil and natural gas operations, they are classified as cash flows from operating activities. In our consolidated balance sheet, receivables and payables resulting from the settlement of our derivative instruments are reported as trade receivables and payables. See Note 6 for a further discussion of our derivatives.

Income Tax

Income Taxes

We record current income taxes based on our estimates of current taxable income and provide for deferred income taxes to reflect estimated future income tax payments and receipts. Changes in tax laws are recorded in the period they are enacted. Deferred taxes represent the tax impacts of differences between the financial statement and tax bases of assets and liabilities and carryovers at each year end. We classify all deferred tax assets and liabilities, along with any related valuation allowance, as non-current on the consolidated balance sheet. We account for tax credits under the flow-through method, which reduces the provision for income taxes in the year the tax credits first become available.

The realization of our deferred tax assets depends on recognition of sufficient future taxable income during periods in which those temporary differences are deductible. We record a valuation allowance against deferred tax assets when, based on our estimates, it is more likely than not that a portion of those assets will not be realized in a future period. The estimates utilized in recognition of deferred tax assets are subject to revision, either up or down, in future periods based on new facts or circumstances. In evaluating our valuation allowances, we consider cumulative book losses, the reversal of existing temporary differences, the existence of taxable income in carryback years, tax planning strategies and future taxable income for each of our taxable jurisdictions, the latter two of which involve the exercise of significant judgment. Changes to our valuation allowances could materially impact our results of operations.

Fair Value Measurements

Fair Value Measurements

We use various methods to determine the fair values of our financial instruments. The fair value of a financial instrument depends on a number of factors, including the availability of observable market data over the contractual term of the underlying instrument. We separate the fair value of our financial instruments into three levels (Levels 1, 2 and 3) based on our assessment of the availability of observable market data and the significance of non-observable data used to determine fair value. Each of the levels are described below:

• Level 1 instruments’ fair values are based on quoted prices in actively traded markets.

• Level 2 instruments’ fair values are based on pricing data representative of quoted prices for similar assets and liabilities in active markets (or identical assets and liabilities in less active markets).

• Level 3 instruments’ fair values are partially calculated using pricing data that is similar to Level 2 instruments, but also reflect adjustments for being in less liquid markets or having longer contractual terms.

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Document and Entity Information - USD ($)	12 Months Ended
	Dec. 31, 2019	Feb. 28, 2020	Jun. 28, 2019
Entity Registrant Name	EP Energy Corp
Entity Central Index Key	0001584952
Document Type	10-K
Document Period End Date	Dec. 31, 2019
Amendment Flag	false
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	No
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Filer Category	Non-accelerated Filer
Entity Emerging Growth Company	false
Entity Small Business	true
Entity Shell Company	false
Entity Public Float			$ 20,418,558
Document Fiscal Year Focus	2019
Document Fiscal Period Focus	FY
Class A Stock
Entity Common Stock, Shares Outstanding (in shares)		254,582,481
Class B Stock
Entity Common Stock, Shares Outstanding (in shares)		237,256

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Impairment Charges

12 Months Ended

Dec. 31, 2019

Impairment or Disposal of Tangible Assets Disclosure [Abstract]

Impairment Charges

Impairment Charges

We evaluate capitalized costs related to proved properties upon a triggering event (e.g., a significant continued decline in forward commodity prices or significant reduction to development capital) to determine if an impairment of such properties has occurred. Commodity price declines may cause changes to our capital spending levels, production rates, levels of proved reserves and development plans, which may result in an impairment of the carrying value of our proved properties in the future.

For the year ended December 31, 2019, as a result of the filing of our Chapter 11 Cases (see Note 1A) and the uncertainties surrounding the availability of financing that would be available to develop our proved undeveloped reserves, we performed an impairment assessment of our asset groups under ASC 360. As a result, the undiscounted future cash flows related to our NEU proved properties were not in excess of the related carrying value of the asset. Accordingly, we have recorded a non-cash impairment charge of approximately $458 million related to this asset group, reflecting a reduction in the net book value of the proved property in this area to its estimated fair value.

During the fourth quarter of 2018, due to the significant reduction to future development capital in the Permian basin in light of the depressed oil price environment, we recorded non-cash impairment charges of approximately (i) $1,044 million on our proved properties, reflecting a reduction in the net book value of the proved property in this area to its estimated fair value and (ii) $59 million on our unproved properties.

Subsequent to December 31, 2019, the COVID-19 outbreak has had a material impact on the demand for oil and the price of oil has significantly decreased as a result of the decrease in demand and the failure of OPEC and Russia to reach an agreement with respect to production cuts. These recent events will continue to have an impact on oil price volatility, the scale and duration of which remain uncertain. If oil prices remain at or below current levels for an extended period of time, this may result in further impairments of the carrying value of our proved properties in the future.

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Income Taxes

12 Months Ended

Dec. 31, 2019

Income Tax Disclosure [Abstract]

Income Taxes

Income Taxes

Pretax Income (Loss) and Income Tax (Expense) Benefit.  The tables below show the pretax loss and the components of income tax expense for the following periods:

	Year Ended December 31,
	2019			2018
	(in millions)
Pretax Loss	$	(943	)	$	(1,003	)
Components of Income Tax Expense
Current
Federal	$	—		$	—
State	—			—
	$	—		$	—
Deferred
Federal	$	—		$	—
State	—			—
Total income tax expense	$	—		$	—

Effective Tax Rate Reconciliation.  Our income taxes included in net income differ from the amount computed by applying the statutory federal income tax rate of 21% for the following reasons:

	Year Ended December 31,
	2019			2018
	(in millions)
Income taxes at the statutory federal rate	$	198		$	211
Increase (decrease)
State income taxes, net of federal income tax effect	11			8
Change in valuation allowance	(207		)	(213		)
Capital loss expiration	—			(5		)
Other	(2		)	(1		)
Income tax expense	$	—		$	—

The effective tax rate for both the years ended December 31, 2019 and 2018 was 0%. Our effective tax rate differed from the statutory rate of 21% primarily due to the change in our valuation allowance on our net deferred tax assets, non-deductible compensation expenses, and a non-deductible loss carryover. 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.

Deferred Tax Assets and Liabilities.  The following are the components of net deferred tax assets and liabilities:

	December 31,   2019			December 31,   2018
	(in millions)
Deferred tax assets
Property, plant and equipment	$	238		$	157
Net operating loss carryovers	642			611
Employee benefits	1			2
Lease obligations	4			—
Legal and other reserves	17			9
Asset retirement obligations	10			9
Interest deduction limitation	125			76
Transaction costs	33			14
Total deferred tax assets	1,070			878
Valuation allowance	(1,064		)	(857		)
Net deferred tax assets	6			21
Deferred tax liabilities
Operating lease assets	4			—
Financial derivatives	2			21
Total deferred tax liabilities	6			21
Net deferred tax liabilities	$	—		$	—

Unrecognized Tax Benefits. At December 31, 2019 and 2018, the total amount of unrecognized tax benefits was $46 million and $0, respectively. The $46 million recorded in 2019 related to tax positions taken in the current year and reflects the potential impact on the classification of certain tax attributes recorded within the components of net deferred assets and liabilities.  We do not expect the settlement of the unrecognized tax benefit to have an impact on the Company's earnings or liquidity. 

We did not recognize any interest and penalties related to unrecognized tax benefits (classified as income taxes in our consolidated income statement) in 2019 or 2018, nor do we have any accrued interest and penalties associated with income taxes in our consolidated balance sheets as of December 31, 2019 and 2018. The Company's and certain subsidiaries' income tax years after 2015 remain open and subject to examination by both federal and state tax authorities.

Net Operating Loss and Tax Credit Carryovers. The table below presents the details of our federal and state net operating loss carryover periods as of December 31, 2019 (in millions): 

	Expiration Period
	2031 - 2037		No expiration(1)		Total
U.S. federal net operating loss carryover(1)	$	2,524	$	429	$	2,953

	2026 - 2038
State net operating loss carryover	$	480

(1) U.S. federal net operating loss carryovers generated since 2018 do not expire but are limited to 80% of taxable income per year.

At December 31, 2019, we have no federal net operating loss carryovers subject to the limitations provided under Sections 382 of the Internal Revenue Code. Additionally, there are no alternative minimum tax credits at December 31, 2019.

Valuation Allowances. As of December 31, 2019 and 2018, we have a valuation allowance on our deferred tax assets of $1,064 million and $857 million, respectively. These amounts are recorded based on our evaluation of whether it was more likely than not that our deferred tax assets would be realized. Our evaluations considered cumulative book losses, the reversal of existing temporary differences, the existence of taxable income in prior carryback years, tax planning strategies and future taxable income for each of our taxable jurisdictions.

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Debt

12 Months Ended

Dec. 31, 2019

Debt Disclosure [Abstract]

Debt

Debt

Listed below are our debt obligations as of the periods presented:

	Interest Rate		December 31, 2019			December 31, 2018
			(in millions)
Prepetition RBL credit facility - due November 23, 2021(1)	Variable		$	315		$	100
Senior secured term loans:
2.0 Lien due April 30, 2019(2)	Variable		—			8
Senior secured notes:
1.5 Lien due May 1, 2024	9.375	%	1,092			1,092
1.25 Lien due November 29, 2024	8.00	%	500			500
1.5 Lien due February 15, 2025	8.00	%	1,000			1,000
1.125 Lien due May 15, 2026	7.75	%	1,000			1,000
Senior unsecured notes:
Due May 1, 2020	9.375	%	182			232
Due September 1, 2022	7.75	%	182			182
Due June 15, 2023	6.375	%	324			324
Unamortized discount and debt issue costs(3)			—			(95		)
Total debt			4,595			4,343
Current portion of long-term debt(3)			(1,815		)	(58		)
Amounts reclassified as liabilities subject to compromise(4)			(2,780		)	—
Total long-term debt			$	—		$	4,285
Debtor-in-possession facility	Variable		$	148		$	—

(1) Carries interest at a specified margin over LIBOR of 2.50%to 3.50%, based on borrowing utilization and 0.375% commitment fee on unused capacity. Such margins will fluctuate based on the utilization of the facility.

(2) Carries interest at a specified margin over the LIBOR of 3.50%, with a minimum LIBOR floor of 1.00%.  As of December 31, 2018, the effective interest rate for the term loan was 6.21%. In April 2019, we retired the note in full.

(3) Due to uncertainties at September 30, 2019 regarding default, event of default and cross-default provisions under our indentures and RBL Facility, we reclassified our debt as current and wrote off approximately $90 million in unamortized debt discount and debt issue costs in the third quarter 2019. Amounts written off are included in interest expense in the consolidated statement of operations.

(4) As a result of the Chapter 11 Cases, the principal balance on the 1.5 lien notes and senior unsecured notes of approximately $2,092 million and $688 million, respectively, has been reclassified as liabilities subject to compromise as of December 31, 2019. In addition, accrued and unpaid interest of approximately $117 million related to the 1.5 lien notes and senior unsecured notes has been reclassified from accrued liabilities to liabilities subject to compromise as of December 31, 2019. For a further discussion of the Chapter 11 Cases, see Note 1A.

Gain on extinguishment/modification of debt. During 2018, we completed an exchange of approximately $1.1 billion of certain senior unsecured notes for new 1.5 Lien Notes maturing in 2024. The exchange transaction was accounted for as a modification of debt and an extinguishment of debt depending on the senior unsecured notes exchanged. In conjunction with the exchange, we recorded a $12 million loss on debt considered modified for accounting purposes and a net gain of $53 million on debt considered extinguished for accounting purposes.

Additionally, during the year ended December 31, 2019 and 2018, we recorded a net gain on extinguishment/modification of debt of $10 million and $32 million, respectively, primarily related to repurchased debt. In the first quarter of 2019, we paid approximately $40 million in cash to repurchase a total of $50 million in aggregate principal amount of our senior unsecured notes due 2020. In 2018, we paid approximately $49 million in cash to repurchase a total of approximately $84 million in aggregate principal amount of our senior unsecured notes due 2022 and 2023.

Covenant Violations and Chapter 11 Cases. On August 15, 2019, we did not make the approximately $40 million cash interest payment due with respect to the 2025 1.5 Lien Notes. On September 3, 2019, we did not make the approximately $7 million cash interest payment due with respect to 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 RBL Facility.

On September 14, 2019, we entered into forbearance agreements, extending through October 3, 2019, with the Noteholders and the RBL Forbearing Parties, pursuant to which each Noteholder and RBL Forbearing Party temporarily agreed, subject to certain terms and conditions, to forbear from exercising any rights or remedies they may have in respect of the failure to make the approximately $40 million cash interest payment.

On October 3, 2019, the Debtors filed the Chapter 11 Cases in the Bankruptcy Court seeking relief under the Bankruptcy Code. 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 the RBL Facility and indentures governing 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. For a further discussion of the Chapter 11 Cases, see Note 1A.

Debtor-in-possession financing. As noted in Note 1A, on November 25, 2019, EPE Acquisition, LLC and EP Energy LLC entered into a Senior Secured Superpriority Debtor-In-Possession 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 (as amended or modified from time to time, the “DIP Credit Agreement”). 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 commitments under the DIP Credit Agreement which provides for an approximately $315 million debtor-in-possession senior secured superpriority revolving credit facility, 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.

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.

The DIP Loans bear interest at a rate per annum equal to (i) adjusted LIBOR plus an applicable margin of 3.50% or (ii) an alternative base rate plus an applicable margin of 2.50%, in each case, as selected by EP Energy LLC. Any unused revolving commitments will be subject to a commitment fee at a rate per annum equal to 0.50% on the Available Commitment (as defined in the DIP Credit Agreement) in effect on such day. The DIP Facility is secured by a senior secured superpriority perfected security interest on substantially all assets of EP Energy LLC and any subsidiary guarantors. The security interests and liens are further subject to certain carve-outs and permitted liens, as set forth in the DIP Credit Agreement and the DIP Order.

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.

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Property, Plant and Equipment (Tables)

12 Months Ended

Dec. 31, 2019

Oil and Gas Exploration and Production Industries Disclosures [Abstract]

Capitalized costs related to proved and unproved oil and natural gas properties by area

Our capitalized costs related to proved oil and natural gas properties by area for the periods ended December 31 were as follows:

	2019			2018
	(in millions)
Proved
Eagle Ford	$	4,266		$	3,898
Northeastern Utah	1,331			1,659
Permian	1,791			1,787
Total Proved	7,388			7,344
Less accumulated depletion	(3,990		)	(3,607		)
Net capitalized costs for oil and natural gas properties	$	3,398		$	3,737

Changes in net asset retirement liability

The net asset retirement liability as of December 31 on our consolidated balance sheet in other current and non-current liabilities and the changes in the net liability for the periods ended December 31 were as follows:

	2019			2018
	(in millions)
Net asset retirement liability at January 1	$	42		$	35
Liabilities incurred	1			1
Liabilities settled	(1		)	—
Accretion expense	3			3
Changes in estimate	—			3
Net asset retirement liability at December 31	$	45		$	42

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Basis of Presentation and Significant Accounting Policies, Voluntary Reorganization under Chapter 11 Cases - Basis of Presentation and Significant Accounting Policies Narrative (Details)	12 Months Ended
	Dec. 31, 2019 USD ($) segment	Dec. 31, 2018 USD ($)
Basis Of Presentation And Summary Of Significant Accounting Policies [Line Items]
Number of operating segments | segment	1
Restricted cash | $	$ 1,000,000	$ 0
Minimum
Basis Of Presentation And Summary Of Significant Accounting Policies [Line Items]
Estimated useful lives of the assets	4 years
Maximum
Basis Of Presentation And Summary Of Significant Accounting Policies [Line Items]
Estimated useful lives of the assets	7 years

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Related Party Transactions - Joint Venture Narrative (Details) - Wolfcamp Drillco Operating L.P. $ in Millions	12 Months Ended
	Dec. 31, 2019 USD ($)	Dec. 31, 2018 USD ($) tranche
Related party transactions
Percent of estimated drilling, completion, and equipping costs of wells contributed by investor		60.00%
Number of investment tranches | tranche		2
Working interest in joint venture wells		50.00%
Internal rate of return on invested capital in each tranche		12.00%
Working interest		15.00%
Capital costs reimbursed to company from related party	$ 91	$ 138
Accounts receivable from related parties	3	47
Accounts payable from related parties	7	20
Investment Tranche One
Related party transactions
Funding from related party		$ 225
Investment Tranche Two
Related party transactions
Funding from related party	$ 225

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Commitments and Contingencies - Leases Narrative (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Commitments and Contingencies Disclosure [Abstract]
Finance lease, interest expense	$ 4
Finance Lease, right-of-use asset, amortization	3
Finance lease payments	4
Operating lease, cost	11
Operating lease, payments	10
Variable lease, cost	3
Short-term lease, cost	$ 20
Rental expense		$ 7

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Property, Plant and Equipment - Changes in Net Asset Retirement Liability (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Changes in net asset retirement liability
Net asset retirement liability at January 1	$ 42	$ 35
Liabilities incurred	1	1
Liabilities settled	(1)	0
Accretion expense	3	3
Changes in estimate	0	3
Net asset retirement liability at December 31	$ 45	$ 42

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Debt (Tables)

12 Months Ended

Dec. 31, 2019

Debt Disclosure [Abstract]

Debt obligations

Listed below are our debt obligations as of the periods presented:

	Interest Rate		December 31, 2019			December 31, 2018
			(in millions)
Prepetition RBL credit facility - due November 23, 2021(1)	Variable		$	315		$	100
Senior secured term loans:
2.0 Lien due April 30, 2019(2)	Variable		—			8
Senior secured notes:
1.5 Lien due May 1, 2024	9.375	%	1,092			1,092
1.25 Lien due November 29, 2024	8.00	%	500			500
1.5 Lien due February 15, 2025	8.00	%	1,000			1,000
1.125 Lien due May 15, 2026	7.75	%	1,000			1,000
Senior unsecured notes:
Due May 1, 2020	9.375	%	182			232
Due September 1, 2022	7.75	%	182			182
Due June 15, 2023	6.375	%	324			324
Unamortized discount and debt issue costs(3)			—			(95		)
Total debt			4,595			4,343
Current portion of long-term debt(3)			(1,815		)	(58		)
Amounts reclassified as liabilities subject to compromise(4)			(2,780		)	—
Total long-term debt			$	—		$	4,285
Debtor-in-possession facility	Variable		$	148		$	—

(1) Carries interest at a specified margin over LIBOR of 2.50%to 3.50%, based on borrowing utilization and 0.375% commitment fee on unused capacity. Such margins will fluctuate based on the utilization of the facility.

(2) Carries interest at a specified margin over the LIBOR of 3.50%, with a minimum LIBOR floor of 1.00%.  As of December 31, 2018, the effective interest rate for the term loan was 6.21%. In April 2019, we retired the note in full.

(3) Due to uncertainties at September 30, 2019 regarding default, event of default and cross-default provisions under our indentures and RBL Facility, we reclassified our debt as current and wrote off approximately $90 million in unamortized debt discount and debt issue costs in the third quarter 2019. Amounts written off are included in interest expense in the consolidated statement of operations.

(4) As a result of the Chapter 11 Cases, the principal balance on the 1.5 lien notes and senior unsecured notes of approximately $2,092 million and $688 million, respectively, has been reclassified as liabilities subject to compromise as of December 31, 2019. In addition, accrued and unpaid interest of approximately $117 million related to the 1.5 lien notes and senior unsecured notes has been reclassified from accrued liabilities to liabilities subject to compromise as of December 31, 2019. For a further discussion of the Chapter 11 Cases, see Note 1A.

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Basis of Presentation and Significant Accounting Policies, Voluntary Reorganization under Chapter 11 Cases - Voluntary Reorganization under Chapter 11 Proceedings Narrative (Details) - USD ($) $ in Millions			12 Months Ended
	Oct. 18, 2019	Sep. 14, 2019	Dec. 31, 2019	Dec. 31, 2018	Nov. 25, 2019	Sep. 03, 2019	Aug. 15, 2019	Jan. 31, 2018
Restructuring Cost and Reserve [Line Items]
Equity Rights Offering amount backstopped	$ 463
Debtor-in possession financing, loans outstanding			$ 148	$ 0
Maximum borrowing capacity	629
Reorganization items			65	0
Liabilities subject to compromise			2,932	0
Liabilities subject to compromise, debt			2,780	0
Contractual interest expense on prepetition liabilities			235
Interest expense on prepetition liabilities recognized in Statement of Operations			211
Senior Unsecured Notes due September 1, 2022
Restructuring Cost and Reserve [Line Items]
Cash interest payment due, not paid						$ 7
Senior Secured Note due May 1, 2024
Restructuring Cost and Reserve [Line Items]
Principal amount issued								$ 1,100
Senior Secured Notes due February 15, 2025
Restructuring Cost and Reserve [Line Items]
Cash interest payment due, not paid							$ 40
Purchase price of new common shares	325
Principal amount issued	$ 138
Debtor-In-Possession Senior Secured Superpriority Revolving Credit Facility
Restructuring Cost and Reserve [Line Items]
Principal amount issued					$ 629
Debtor-in-possession financing, amount arranged					315
Debtor-in possession financing, remaining borrowing capacity			150
Debtor-in possession financing, loans outstanding			148	$ 0
Senior Unsecured Notes
Restructuring Cost and Reserve [Line Items]
Liabilities subject to compromise, debt			688
Letter of Credit
Restructuring Cost and Reserve [Line Items]
Debtor-in-possession financing, amount arranged					$ 50
Debtor-in-possession letter of credit outstanding			$ 17
Beneficial Owner | Senior Secured Notes due November 29, 2024
Restructuring Cost and Reserve [Line Items]
Percent of aggregate principal amount	52.00%
Beneficial Owner | Senior Secured Note due May 1, 2024
Restructuring Cost and Reserve [Line Items]
Percent of aggregate principal amount	79.30%
Beneficial Owner | Senior Secured Notes due February 15, 2025
Restructuring Cost and Reserve [Line Items]
Percent of aggregate principal amount		70.00%

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Commitments and Contingencies - Legal and Other Matters Narrative (Details) - USD ($) $ in Millions			1 Months Ended
	May 29, 2018	Mar. 03, 2014	Jul. 31, 2019	Dec. 31, 2019
Legal Matters
Loss Contingencies [Line Items]
Amount accrued				$ 26.0
Storey Minerals V. EP Energy, MFN Clause Accrual
Loss Contingencies [Line Items]
Amount accrued				4.0
Damages sought	$ 4.0
Storey Minerals V. EP Energy, MFN Clause Disputed Amount
Loss Contingencies [Line Items]
Damages sought			$ 43.8
Indemnification and Other Matters
Loss Contingencies [Line Items]
Amount accrued				12.0
FairfieldNodal V. EP Energy E&P, Company L.P. | Pending Litigation
Loss Contingencies [Line Items]
Amount accrued				$ 21.0
Damages sought		$ 21.0

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Property, Plant and Equipment - Capitalized Costs Related to Proved and Unproved Oil and Natural Gas Properties by Area (Details) - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Property, Plant and Equipment [Line Items]
Proved	$ 7,388	$ 7,344
Less accumulated depletion	(3,990)	(3,607)
Net capitalized costs for oil and natural gas properties	3,398	3,737
Eagle Ford
Property, Plant and Equipment [Line Items]
Proved	4,266	3,898
Northeastern Utah
Property, Plant and Equipment [Line Items]
Proved	1,331	1,659
Permian
Property, Plant and Equipment [Line Items]
Proved	$ 1,791	$ 1,787

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Incentive Compensation / 401(k) Retirement Plan - Summary of Changes in Non-Vested Restricted Shares (Details) - Restricted Stock	12 Months Ended
	Dec. 31, 2019 $ / shares shares
Number of Shares
Non-vested at beginning of period (in shares) | shares	7,060,334
Granted (in shares) | shares	103,000
Vested (in shares) | shares	(2,648,390)
Forfeited (in shares) | shares	(1,000,409)
Non-vested at end of period (in shares) | shares	3,514,535
Weighted Average Grant Date Fair Value per Share
Non-vested at beginning of period (in dollars per share) | $ / shares	$ 2.69
Granted (in dollars per share) | $ / shares	0.70
Vested (in dollars per share) | $ / shares	3.22
Forfeited (in dollars per share) | $ / shares	2.45
Non-vested at end of period (in dollars per share) | $ / shares	$ 2.30

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Incentive Compensation / 401(k) Retirement Plan - Other Narrative (Details)	12 Months Ended
	Dec. 31, 2019 USD ($) $ / shares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unrecognized compensation cost for options and PSUs (less than)	$ 1,000,000
Recognition period of fair value as compensation cost	1 year
EPE Holdings II
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Option strike price (in dollars per share) | $ / shares	$ 19.82
Class B Stock
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unrecognized compensation cost	$ 1,000,000
Class B Stock | EPE Holdings II
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Investment return rate	1

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Income Taxes - Components of Deferred Tax Assets and Liabilities (Details) - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Deferred tax assets
Property, plant and equipment	$ 238	$ 157
Net operating loss carryovers	642	611
Employee benefits	1	2
Lease obligations	4
Legal and other reserves	17	9
Asset retirement obligations	10	9
Interest deduction limitation	125	76
Transaction costs	33	14
Total deferred tax assets	1,070	878
Valuation allowance	(1,064)	(857)
Net deferred tax assets	6	21
Deferred tax liabilities
Operating lease assets	4
Financial derivatives	2	21
Total deferred tax liabilities	6	21
Net deferred tax liabilities	$ 0	$ 0

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Impairment Charges (Details) - USD ($) $ in Millions	3 Months Ended	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2019
Impairment or Disposal of Tangible Assets Disclosure [Abstract]
Impairment of proved properties	$ 1,044	$ 458
Impairment of unproved properties	$ 59

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Acquisitions and Divestitures

12 Months Ended

Dec. 31, 2019

Business Combinations [Abstract]

Acquisitions and Divestitures

Acquisitions and Divestitures

Acquisitions. In 2018, we completed acquisitions of (i) producing properties and proved undeveloped acreage in Eagle Ford for approximately $246 million and (ii) additional working interests in certain producing properties in Eagle Ford for approximately $31 million. Our consolidated balance sheet reflects the cost of each of these assets acquired during the year as proved properties.

Divestitures. During 2018, we also completed the sale of certain assets in Northeastern Utah (“NEU”) for approximately $177 million. We treated this sale as a normal retirement reflecting the difference between net cash proceeds and the underlying net book value of the assets sold in accumulated depreciation rather than recording a gain on sale of assets.

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Earnings Per Share

12 Months Ended

Dec. 31, 2019

Earnings Per Share [Abstract]

Earnings Per Share

Earnings Per Share

We exclude potentially dilutive securities from the determination of diluted earnings per share (as well as their related income statement impacts) when their impact on net income per common share is antidilutive. Potentially dilutive securities consist of our stock options, restricted stock, performance share unit awards and performance unit awards. For both the years ended December 31, 2019 and 2018, we incurred net losses and accordingly excluded all potentially dilutive securities from the determination of diluted earnings per share as their impact on loss per common share was antidilutive.

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Commitments and Contingencies

12 Months Ended

Dec. 31, 2019

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies

Commitments and Contingencies

Chapter 11 Cases

On October 3, 2019, the Debtors filed the Chapter 11 Cases in the Bankruptcy Code seeking relief under the Bankruptcy Code. We expect to continue operations in the normal course during the pendency of the Chapter 11 Cases. In addition, commencement of the Chapter 11 Cases automatically stayed all of the proceedings and actions against the Company, including those noted below. For a further discussion of the Chapter 11 Cases, see Note 1A. Any claims filed, or to be filed in relation to the Chapter 11 Cases, will be investigated and addressed in connection with the claims resolution process. The Company will continue to evaluate these liabilities throughout the Chapter 11 process and adjust amounts as necessary.

Legal Matters

We and our subsidiaries and affiliates are parties to various legal actions and claims that arise in the ordinary course of our business. For each matter, we evaluate the merits of the case or claim, our exposure to the matter, possible legal or settlement strategies and the likelihood of an unfavorable outcome.  If we determine that an unfavorable outcome is probable and can be estimated, we establish the necessary accruals. While the outcome of our current matters cannot be predicted with certainty and there are still uncertainties related to the costs we may incur, based upon our evaluation and experience to date, we believe we have established appropriate reserves for these matters. It is possible, however, that new information or future developments could require us to reassess our potential exposure and adjust our accruals accordingly, and these adjustments could be material. As of December 31, 2019, we had approximately $26 million accrued for all outstanding legal matters, which also represents our best estimate of the allowed claims for these legal matters which have been reclassified as liabilities subject to compromise on our balance sheet at December 31, 2019.

FairfieldNodal v. EP Energy E&P Company, L.P. On March 3, 2014, Fairfield filed suit against one of our subsidiaries in the 157th District Court of Harris County, Texas, claiming we were contractually obligated to pay a transfer fee of approximately $21 million for seismic licensing, triggered by a change in control with the Sponsors' acquisition of our predecessor entity in 2012. Prior to the change in control, we had unilaterally terminated the seismic licensing agreements, and we returned the applicable seismic data. Fairfield also claimed EP Energy did not properly maintain the confidentiality of the seismic data and interpretations made from it. In April 2015, the district court granted summary judgment to EP Energy, and Fairfield then appealed. On July 6, 2017, an intermediate court of appeals in Texas reversed the judgment related to the transfer fee and denied rehearing on October 5, 2017. We filed a petition for review in the Texas Supreme Court, which denied review in June 2019. We filed a motion for rehearing in the Texas Supreme Court on July 31, 2019. If denied, the case will be remanded to the trial court for further proceedings. As of December 31, 2019, we had accrued approximately $21 million related to this matter.

Storey Minerals, Ltd., et al. v. EP Energy E&P Company, L.P. On May 29, 2018, Storey Minerals, Ltd., Maltsberger/ Storey Ranch, LLC, and Rene R. Barrientos, Ltd. (collectively, “MSB”) filed suit against EP Energy in the 81st Judicial District Court of La Salle County, Texas. MSB alleged that by acquiring certain oil and gas leases within the perimeter of the Storey Altito Ranch, EP Energy triggered the most favored nation clause (“MFN clause”) in the leases. After investigation, EP Energy agreed that the MFN clause had been triggered and tendered a lease amendment with a check for $4 million for increased lease bonus. EP Energy's calculation confirmed that no delay rentals were due. MSB, however, did not accept the tender and asserts that the MFN clause operates retroactively to the date of the lease and applies to all of the acreage leased at that time. EP Energy maintains that the unambiguous language in the MFN clause operates prospectively and supports its tendered amendment and calculation. The parties filed cross-motions for summary judgment. In June 2019, the court entered an order agreeing with EP Energy on delay rentals, but with MSB on lease bonus. The court entered a final judgment in July 2019 ordering EP Energy to pay MSB $43.8 million in increased lease bonus, attorney’s fees, expenses and interest to date. EP Energy filed an appeal to the Fourth Circuit Court of Appeals in San Antonio, Texas on July 17, 2019 and intends to pursue fully its appeal. As of December 31, 2019, EP Energy's accrual of approximately $4 million related to this matter reflects the amount tendered to MSB with the lease amendment noted above, which EP Energy believes is the appropriate amount of increased bonus due to MSB.

Environmental Matters

We are subject to existing federal, state and local laws and regulations governing environmental quality, pollution control and greenhouse gas emissions. Numerous governmental agencies, such as the EPA, issue regulations which often require difficult and costly compliance measures that carry substantial administrative, civil and criminal penalties and may result in injunctive obligations for non-compliance. Our management believes that we are in substantial compliance with applicable environmental laws and regulations, and we have not experienced any material adverse effect from compliance with these environmental requirements. For additional details on certain environmental matters, including matters related to climate change, air quality and other emissions, hydraulic fracturing regulations and waste handling, refer to Part I, Item 1A. "Risk Factors".

While our reserves for environmental matters are currently not material, there are still uncertainties related to the ultimate costs we may incur in the future in order to comply with increasingly strict environmental laws, regulations, and orders of regulatory agencies, as well as claims for damages to property and the environment or injuries to employees and other persons resulting from our current or past operations. Based upon our evaluation and experience to date, however, we believe our accruals for these matters are adequate. It is possible that new information or future developments could result in substantial additional costs and liabilities which could require us to reassess our potential exposure related to these matters and to adjust our accruals accordingly, and these adjustments could be material.

Other Matters

As of December 31, 2019, we had approximately $12 million accrued (in other accrued liabilities in our consolidated balance sheet) related to other contingent matters including, but not limited to, a number of examinations by taxing authorities on non-income matters and indemnifications that we periodically enter into as part of the divestiture of assets or businesses. These arrangements include, but are not limited to, indemnifications for income taxes, the resolution of existing disputes and other contingent matters. In addition, the decline in commodity prices has created an environment where there is an increased risk that owners and/or operators of assets previously purchased from us may no longer be able to satisfy plugging and abandonment obligations that attach to such assets. In that event, under various laws or regulations, we could be required to assume all, or a portion of the plugging or abandonment obligations on assets we no longer own or operate.

Lease Obligations

In the first quarter of 2019, we adopted ASU No. 2016-02, Leases on a modified retrospective basis, allowing us to account for leases entered into before adoption under prior ASC 840 guidance. The adoption did not have a material impact on our consolidated financial statements, nor did the adoption result in a cumulative-effect adjustment to retained earnings. In addition, we made certain permitted elections upon adoption, the most significant of which were (i) exempting short-term leases (i.e., leases with an initial term of less than 12 months) from balance sheet recognition, (ii) maintaining existing accounting treatment for existing or expired land easements not previously accounted for as leases under prior guidance and (iii) accounting for lease and non-lease components in a contract as a single lease component when not readily determinable.

Our noncancellable leases classified as finance leases for accounting purposes include certain compressors under long-term arrangements which were capitalized upon commencement of the lease term at the fair value of the leased asset, which was lower than the present value of the minimum lease payments. The discount rate used for our finance leases was the incremental borrowing rate adjusted so that the present value of the corresponding lease payments did not exceed the fair value of the leased asset. For the year ended December 31, 2019, interest and depreciation expense associated with our finance leases were approximately $4 million and $3 million, respectively, and related cash payments were approximately $4 million.

Our noncancellable leases classified as operating leases and capitalized upon commencement of the lease term for accounting purposes include those for office space, drilling rigs and field equipment. The discount rate used for our operating leases is either the discount rate implicit in the contract, or the applicable interest rate on a collateralized basis if not determinable. Operating lease costs for minimum lease payments are recognized as capital or expense on a straight-line basis over the lease term depending on the nature of the payment. For the year ended December 31, 2019, operating lease costs and related cash payments were approximately $11 million and $10 million, respectively. These were primarily capitalized as part of our oil and natural gas properties. Variable lease costs (amounts incurred beyond minimum lease payments such as utilities, usage, maintenance, mobilization fees, etc.) are recognized in the period incurred. For the year ended December 31, 2019, variable lease cost was approximately $3 million.

Short-term lease cost for the year ended December 31, 2019 was approximately $20 million, and was primarily capitalized as part of our oil and natural gas properties.

Supplemental balance sheet information related to leases was as follows:

	December 31, 2019
	(in millions)
Operating lease assets(1)(4)	$	18
Finance lease assets(2)	10
Total lease assets	$	28
Operating leases(3)(4)
Current liability	$	9
Noncurrent liability	9
Total operating lease liability	$	18
Finance leases(3)
Current liability	$	2
Noncurrent liability	9
Total finance lease liability	$	11
Weighted average remaining lease term
Operating leases	3 years
Finance leases	4 years
Weighted average discount rate
Operating leases	9.06		%
Finance leases	26.53		%

(1) Operating lease assets are reflected in Operating lease assets and other in our consolidated balance sheet as of December 31, 2019.

(2) Finance lease assets are reflected in Other property, plant and equipment in our consolidated balance sheet as of December 31, 2019.

(3) Current and noncurrent operating and finance lease liabilities are reflected in Other current liabilities and Lease obligations and other, respectively, in our consolidated balance sheet as of December 31, 2019.

(4) Upon adoption of ASU 2016-02 effective January 1, 2019, we recognized operating leases of approximately $10 million. For the year ended December 31, 2019, we also recorded an additional $16 million of operating leases.

Future minimum annual rental commitments under non-cancelable future operating and finance lease commitments at December 31, 2019, were as follows:

Year Ending December 31,	Operating Leases			Finance Leases
	(in millions)
2020	$	10		$	5
2021	3			5
2022	2			5
2023	2			2
Thereafter	4			—
Total	$	21		$	17
Less: imputed interest	(3		)	(6		)
Present value of operating and finance lease obligations	$	18		$	11

Rental expense for the year ended December 31, 2018 was $7 million.

Other Commercial Commitments

At December 31, 2019, we have various commercial commitments totaling $134 million primarily related to commitments and contracts associated with volume and transportation, completion activities and seismic activities. Our annual obligations under these arrangements are $44 million in 2020, $35 million in 2021, $27 million in 2022, $9 million in 2023, and $19 million thereafter.

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CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Accounts receivable
Allowance for customer accounts receivable	$ 1	$ 1
Allowance for other accounts receivable	$ 1	$ 1
Preferred stock
Preferred stock, par value (in dollars per share)	$ 0.01	$ 0.01
Preferred stock, shares authorized (in shares)	50,000,000	50,000,000
Preferred stock, shares issued (in shares)	0	0
Preferred stock, shares outstanding (in shares)	0	0
Treasury stock
Treasury stock, shares held (less than) (in shares)	1,000,000	1,000,000
Class A Stock
Common stock
Common stock, par value (in dollars per share)	$ 0.01	$ 0.01
Common stock, shares authorized (less than for Class B shares) (in shares)	550,000,000	550,000,000
Common stock, shares issued (less than for Class B shares) (in shares)	256,000,000	256,000,000
Common stock, shares outstanding (less than for Class B shares) (in shares)	255,000,000	256,000,000
Class B Stock
Common stock
Common stock, par value (in dollars per share)	$ 0.01	$ 0.01
Common stock, shares authorized (less than for Class B shares) (in shares)	1,000,000	1,000,000
Common stock, shares issued (less than for Class B shares) (in shares)	1,000,000	1,000,000
Common stock, shares outstanding (less than for Class B shares) (in shares)	1,000,000	1,000,000

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Basis of Presentation and Significant Accounting Policies, Voluntary Reorganization under Chapter 11 Cases (Tables)

12 Months Ended

Dec. 31, 2019

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Schedule of Reorganization Items

For the year ended December 31, 2019, reorganization items, net were $65 million and consisted of:

	Year ended   December 31,   2019
	(in millions)
Professional fees	$	44
Rejection of executory contracts approved by Bankruptcy Court	16
DIP Facility costs	5
Total reorganization items, net	$	65

Schedule of Liabilities Subject To Compromise

As of December 31, 2019, liabilities subject to compromise were $2,932 million and consisted of:

	Year ended   December 31,   2019
	(in millions)
Senior secured 1.5 lien notes	$	2,092
Senior unsecured notes	688
Prepetition accrued interest on senior secured 1.5 lien and unsecured notes	117
Allowed claims, prepetition accounts payable and other	35
Total liabilities subject to compromise	$	2,932

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Basis of Presentation and Significant Accounting Policies, Voluntary Reorganization under Chapter 11 Cases - Schedule of Liabilities Subject to Compromise (Details) - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Debt Instrument [Line Items]
Liabilities subject to compromise, debt	$ 2,780	$ 0
Allowed claims, prepetition accounts payable and other	35
Total liabilities subject to compromise	2,932	$ 0
Senior Secured Notes
Debt Instrument [Line Items]
Liabilities subject to compromise, debt	2,092
Senior Unsecured Notes
Debt Instrument [Line Items]
Liabilities subject to compromise, debt	688
Senior Secured Term Loans and Senior Notes
Debt Instrument [Line Items]
Prepetition accrued interest on senior secured 1.5 lien and unsecured notes	$ 117

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Fair Value Measurements (Tables)

12 Months Ended

Dec. 31, 2019

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Carrying amounts and estimated fair values of financial instruments

The following table presents the carrying amounts and estimated fair values of our financial instruments:

	December 31, 2019				December 31, 2018
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	(in millions)
Debt obligations:
Debtor-in-possession credit facility(1)	$	148	$	148	$	—	$	—
Liabilities subject to compromise(2)	$	2,780	$	53	$	—	$	—
Current portion of long-term debt(1)	$	1,815	$	1,285	$	58	$	44
Long-term debt(1)	$	—	$	—	$	4,380	$	2,532
Derivative instruments	$	9	$	9	$	114	$	114

(1) Current portion of long-term debt includes $315 million of the RBL Facility and the principal balance of the 2024 1.25 Lien Notes and 7.750% Senior Secured Notes due 2026 reflected in current portion of long-term debt on our balance sheet as of December 31, 2019. For a further discussion on our Chapter 11 Cases, reclassification of debt and DIP Facility, see Notes 1A and 8.

(2) Amount includes the principal balance on the 1.5 lien notes and senior unsecured notes totaling approximately $2,780 million reclassified as liabilities subject to compromise as of December 31, 2019.

Fair value associated with derivative financial instruments

The following table presents the fair value associated with our derivative financial instruments as of December 31, 2019 and 2018.  All of our derivative instruments are subject to master netting arrangements which provide for the unconditional right of offset for all derivative assets and liabilities with a given counterparty in the event of default. We present assets and liabilities related to these instruments in our consolidated balance sheets as either current or non-current assets or liabilities based on their anticipated settlement date, net of the impact of master netting agreements.  On derivative contracts recorded as assets in the table below, we are exposed to the risk that our counterparties may not perform.

	Level 2
	Derivative Assets									Derivative Liabilities
	Gross Fair Value					Balance Sheet Location				Gross Fair Value					Balance Sheet Location
			Impact of Netting			Current		Non-current					Impact of Netting		Current		Non-current
			(in millions)										(in millions)
December 31, 2019
Derivative instruments	$	14	$	(5	)	$	9	$	—	$	(5	)	$	5	$	—	$	—
December 31, 2018
Derivative instruments	$	116	$	(2	)	$	101	$	13	$	(2	)	$	2	$	—	$	—

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Incentive Compensation / 401(k) Retirement Plan (Tables)

12 Months Ended

Dec. 31, 2019

Retirement Benefits [Abstract]

Summary of Changes in Non-Vested Restricted Shares

A summary of the changes in our non-vested restricted shares for the year ended December 31, 2019 is presented below:

	Number of Shares		Weighted Average Grant Date Fair Value per Share
Non-vested at December 31, 2018	7,060,334		$	2.69
Granted	103,000		$	0.70
Vested	(2,648,390	)	$	3.22
Forfeited	(1,000,409	)	$	2.45
Non-vested at December 31, 2019	3,514,535		$	2.30

Summary of Significant Assumptions Used to Calculate Fair Value

he following table summarizes the significant assumptions used to calculate the grant date fair value of the PSUs:

	2018 Awards		2017 Awards
Expected Term in Years	4		6
Expected Volatility	89.62	%	100.03	%
Risk-Free Interest Rate	2.75	%	1.89	%

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Debt - Debt Obligations (Details) - USD ($) $ in Millions	3 Months Ended	12 Months Ended
	Sep. 30, 2019	Dec. 31, 2019	Dec. 31, 2018	Jan. 31, 2018
Debt Instrument [Line Items]
Total debt		$ 4,595	$ 4,343
Unamortized discount and debt issue costs		0	(95)
Current portion of long-term debt		(1,815)	(58)
Amounts reclassified as liabilities subject to compromise		2,780	0
Total long-term debt		0	4,285
Debtor-in-possession financing		148	0
Write off of deferred debt issuance cost	$ 90
Senior Secured Term Loans due April 30, 2019
Debt Instrument [Line Items]
Total debt		$ 0	8
Effective interest rate		6.21%
Senior Secured Term Loans due April 30, 2019 | LIBOR
Debt Instrument [Line Items]
Specified margin on reference rate		3.50%
Senior Secured Term Loans due April 30, 2019 | LIBOR | Minimum
Debt Instrument [Line Items]
Floor on variable rate		1.00%
Senior Secured Note due May 1, 2024
Debt Instrument [Line Items]
Interest Rate		9.375%
Total debt			1,092	$ 1,092
Senior Secured Notes due November 29, 2024
Debt Instrument [Line Items]
Interest Rate		8.00%
Total debt		$ 500	500
Senior Secured Notes due February 15, 2025
Debt Instrument [Line Items]
Interest Rate		8.00%
Total debt		$ 1,000	1,000
Senior Secured Notes due May 15, 2026
Debt Instrument [Line Items]
Interest Rate		7.75%
Total debt		$ 1,000	1,000
Senior Unsecured Notes due May 1, 2020
Debt Instrument [Line Items]
Interest Rate		9.375%
Total debt		$ 182	232
Senior Unsecured Notes due September 1, 2022
Debt Instrument [Line Items]
Interest Rate		7.75%
Total debt		$ 182	182
Senior Unsecured Notes due June 15, 2023
Debt Instrument [Line Items]
Interest Rate		6.375%
Total debt		$ 324	324
Senior Secured Notes
Debt Instrument [Line Items]
Amounts reclassified as liabilities subject to compromise		2,092
Senior Unsecured Notes
Debt Instrument [Line Items]
Amounts reclassified as liabilities subject to compromise		688
Senior Secured Term Loans and Senior Notes
Debt Instrument [Line Items]
Prepetition accrued interest on senior secured 1.5 lien and unsecured notes		117
Debtor-In-Possession Senior Secured Superpriority Revolving Credit Facility
Debt Instrument [Line Items]
Debtor-in-possession financing		$ 148	0
Reserve-Based Loan Facility, Due November 2021
Debt Instrument [Line Items]
Unused capacity, commitment fee percentage		0.375%
Line of Credit | Reserve-Based Loan Facility, Due November 2021
Debt Instrument [Line Items]
Total debt		$ 315	$ 100
Line of Credit | Reserve-Based Loan Facility, Due November 2021 | LIBOR | Minimum
Debt Instrument [Line Items]
Specified margin on reference rate		2.50%
Line of Credit | Reserve-Based Loan Facility, Due November 2021 | LIBOR | Maximum
Debt Instrument [Line Items]
Specified margin on reference rate		3.50%

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Fair Value Measurements - Fair Value Associated With Derivative Financial Instruments (Details) - Level 2 - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Derivative Assets
Gross Fair Value	$ 14	$ 116
Impact of Netting	(5)	(2)
Derivative Liabilities
Gross Fair Value	(5)	(2)
Impact of Netting	5	2
Current Assets
Derivative Assets
Derivatives instruments	9	101
Non-current Assets
Derivative Assets
Derivatives instruments	0	13
Current Liabilities
Derivative Liabilities
Derivatives instruments	0	0
Non-current Liabilities
Derivative Liabilities
Derivatives instruments	$ 0	$ 0

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Commitments and Contingencies - Schedule of Lease Supplemental Balance Sheet Information (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Jan. 01, 2019
Lessee, Lease, Description [Line Items]
Operating lease assets	$ 18
Finance lease assets	10
Total lease assets	28
Operating leases
Current liability	9
Noncurrent liability	9
Total operating lease liability	18
Finance leases
Current liability	2
Noncurrent liability	9
Total finance lease liability	$ 11
Weighted average remaining lease term
Operating leases	3 years
Finance leases	4 years
Weighted average discount rate
Operating leases	9.06%
Finance leases	26.53%
Right-of-use asset obtained in exchange for operating lease liability	$ 16
ASU 2016-02
Lessee, Lease, Description [Line Items]
Operating lease assets		$ 10
Operating leases
Total operating lease liability		$ 10

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Related Party Transactions - Chapter 11 Proceedings Narrative (Details) - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018	Jan. 31, 2018
Related party transactions
Total debt	$ 4,595	$ 4,343
Senior Secured Notes due May 1 2024 and February 15 2025
Related party transactions
Total debt	2,092
Senior Secured Notes due May 1 2024 and February 15 2025 | Investor Apollo
Related party transactions
Total debt	675
Senior Secured Notes due May 1 2024 and February 15 2025 | Investor Access
Related party transactions
Total debt	$ 48
Senior Secured Note due May 1, 2024
Related party transactions
Total debt		1,092	$ 1,092
Interest rate	9.375%
Senior Secured Notes due November 29, 2024
Related party transactions
Total debt	$ 500	$ 500
Interest rate	8.00%
Senior Secured Note due May 1, 2024 | Investor Apollo
Related party transactions
Total debt	$ 21

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Incentive Compensation / 401(k) Retirement Plan - Overview Narrative (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Authorized number of awards to grant (in shares)	36,832,525
Shares remaining for issuance (in shares)	10,579,000
Compensation expense recorded	$ 9	$ 14
Income tax benefit	$ 0	0
Class B Stock
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Additional shares of common stock available for issuance (in shares)	0
EP Energy Corporation
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Income tax benefit	$ 2	$ 4

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Incentive Compensation / 401(k) Retirement Plan - Summary of Significant Assumptions Used to Calculate Fair Value (Details) - Performance Share Units	12 Months Ended
	Dec. 31, 2019
2018 Awards
Assumptions used for estimating weighted-average grant-date fair value of stock options
Expected Term in Years	4 years
Expected Volatility	89.62%
Risk-Free Interest Rate	2.75%
2017 Awards
Assumptions used for estimating weighted-average grant-date fair value of stock options
Expected Term in Years	6 years
Expected Volatility	100.03%
Risk-Free Interest Rate	1.89%

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Property, Plant and Equipment

12 Months Ended

Dec. 31, 2019

Oil and Gas Exploration and Production Industries Disclosures [Abstract]

Property, Plant and Equipment

Property, Plant and Equipment

Oil and Natural Gas Properties.  As of December 31, 2019 and 2018, we had approximately $3.4 billion and $3.8 billion, respectively, of total property, plant, and equipment, net of accumulated depreciation, depletion, and amortization on our balance sheet, substantially all of which relates to proved oil and natural gas properties.

Our capitalized costs related to proved oil and natural gas properties by area for the periods ended December 31 were as follows:

	2019			2018
	(in millions)
Proved
Eagle Ford	$	4,266		$	3,898
Northeastern Utah	1,331			1,659
Permian	1,791			1,787
Total Proved	7,388			7,344
Less accumulated depletion	(3,990		)	(3,607		)
Net capitalized costs for oil and natural gas properties	$	3,398		$	3,737

As of December 31, 2019, we did not have any suspended wells and as of December 31, 2018, suspended well costs were not material.

Asset Retirement Obligations.  We have legal asset retirement obligations associated with the retirement of our oil and natural gas wells and related infrastructure. We settle these obligations when production on those wells is exhausted, when we no longer plan to use them or when we abandon them. We accrue these obligations when we can estimate the timing and amount of their settlement.

In estimating the liability associated with our asset retirement obligations, we utilize several assumptions, including a credit-adjusted risk-free rate between 7 percent and 9 percent on a majority of our obligations and a projected inflation rate of 2.5 percent. Changes in estimates in the table below represent changes to the expected amount and timing of payments to settle our asset retirement obligations. Typically, these changes primarily result from obtaining new information about the timing of our obligations to plug and abandon oil and natural gas wells and the costs to do so, or reassessing our assumptions in light of changing market conditions. The net asset retirement liability as of December 31 on our consolidated balance sheet in other current and non-current liabilities and the changes in the net liability for the periods ended December 31 were as follows:

	2019			2018
	(in millions)
Net asset retirement liability at January 1	$	42		$	35
Liabilities incurred	1			1
Liabilities settled	(1		)	—
Accretion expense	3			3
Changes in estimate	—			3
Net asset retirement liability at December 31	$	45		$	42

Capitalized Interest.  Interest expense is reflected in our financial statements net of capitalized interest. We capitalize interest primarily on the costs associated with drilling and completing wells until production begins using a weighted average interest rate on our outstanding borrowings. Capitalized interest for both the years ended December 31, 2019 and 2018 was approximately $5 million. Subsequent to filing for Chapter 11 relief as further described in Note 1A, we only capitalize interest on those debt obligations for which interest will continue to be paid and which are not classified as liabilities subject to compromise.

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Related Party Transactions

12 Months Ended

Dec. 31, 2019

Related Party Transactions [Abstract]

Related Party Transactions

Related Party Transactions

Chapter 11 Cases. As of December 31, 2019, affiliates of Apollo held approximately $675 million of the aggregate outstanding principal amount of approximately $2,092 million of our 2024 1.5 Lien Notes and 2025 1.5 Lien Notes, and approximately $21 million of the outstanding principal amount of $500 million of our 2024 1.25 Lien Notes. As of December 31, 2019, affiliates of Access held approximately $48 million of our 1.5 lien notes. On October 18, 2019, we entered into the (i) PSA, to support a restructuring on the terms of the Plan described therein, and (ii) BCA, pursuant to which the Commitment Parties agreed to backstop the Rights Offering, in each case, with holders of certain of our debt, including affiliates of, or funds managed by, Apollo and Access. 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 the Stipulation. On March 23, 2020, the Bankruptcy Court approved the Stipulation. The Debtors are working with their constituents to explore various alternatives. For a discussion of the Chapter 11 Cases, refer to Note 1A.

Joint Venture. We are party to a drilling joint venture to fund future oil and natural gas development with Wolfcamp Drillco Operating L.P. (the Investor, which is managed and controlled by an affiliate of Apollo) and indirectly through Access (through an indirect minority ownership interest in the Investor). The Investor agreed to fund 60 percent of the estimated drilling, completion and equipping costs in the joint venture wells, divided into two approximately $225 million investment tranches, in exchange for a 50 percent working interest. We are the operator of the joint venture assets. Once the Investor achieves a 12 percent internal rate of return on its invested capital in each tranche, its working interest reverts to 15 percent.  In 2018, we completed the planned activity in the first tranche and amended the drilling joint venture to direct the second tranche investment to the Eagle Ford. As of the second quarter 2019, we had drilled and completed all wells under the amended agreement. For the years ended December 31, 2019 and 2018, we recovered approximately $91 million and $138 million, respectively, related to capital costs of the joint venture wells from the Investor. At December 31, 2019 and 2018, we had accounts receivable of $3 million and $47 million, respectively, from our Investor and accounts payable of $7 million and $20 million, respectively, to our Investor reflected in our consolidated balance sheet.

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CONSOLIDATED STATEMENT OF CHANGES IN EQUITY - USD ($) $ in Millions	Total	Class A Stock	Class B Stock	Common Stock Class A Stock	Common Stock Class B Stock	Treasury Stock	Additional Paid-in Capital	Retained Earnings (Accumulated Deficit)
Balance (in shares) at Dec. 31, 2017				252,000,000	300,000
Balance at Dec. 31, 2017	$ 392			$ 3	$ 0	$ (3)	$ 3,526	$ (3,134)
Increase (Decrease) in Stockholders' Equity
Share-based compensation (in shares)				4,000,000	0
Share-based compensation	12			$ 0		2	10
Net loss	(1,003)							(1,003)
Balance (in shares) at Dec. 31, 2018		256,000,000	1,000,000	256,000,000	300,000
Balance at Dec. 31, 2018	(599)			$ 3	$ 0	(1)	3,536	(4,137)
Increase (Decrease) in Stockholders' Equity
Share-based compensation (in shares)				(1,000,000)
Share-based compensation	9					0	9
Net loss	(943)							(943)
Balance (in shares) at Dec. 31, 2019		256,000,000	1,000,000	255,000,000	300,000
Balance at Dec. 31, 2019	$ (1,533)			$ 3	$ 0	$ (1)	$ 3,545	$ (5,080)

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CONSOLIDATED STATEMENTS OF INCOME - USD ($) shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Operating revenues
Financial derivatives	$ (81)	$ 84
Total operating revenues	820	1,324
Operating expenses
Oil and natural gas purchases	0	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	0	(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)	0
Loss before income taxes	(943)	(1,003)
Income tax expense	0	0
Net loss	$ (943)	$ (1,003)
Basic and diluted net income (loss) per common share
Net loss (in dollars per share)	$ (3.77)	$ (4.05)
Basic and diluted weighted average common shares outstanding (in shares)	250	248
Oil
Operating revenues
Operating revenues	$ 790	$ 1,045
Natural gas
Operating revenues
Operating revenues	49	75
NGLs
Operating revenues
Operating revenues	$ 62	$ 120

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Income Taxes - Effective Income Tax Rate Reconciliation (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Income Tax Disclosure [Abstract]
Income taxes at the statutory federal rate	$ 198	$ 211
Increase (decrease)
State income taxes, net of federal income tax effect	11	8
Change in valuation allowance	(207)	(213)
Capital loss expiration	0	(5)
Other	(2)	(1)
Total income tax expense	$ 0	$ 0

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Acquisitions and Divestitures - Acquisitions (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Other Acquisitions and Divestitures [Line Items]
Payments to acquire producing properties and undeveloped acreage	$ 21	$ 292
Eagle Ford | Oil and Gas Properties
Other Acquisitions and Divestitures [Line Items]
Payments to acquire producing properties and undeveloped acreage		246
Payments to acquire additional working interests		$ 31

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Fair Value Measurements - Carrying Amounts and Estimated Fair Values of Financial Instruments (Details) - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Debt Obligations [Abstract]
Liabilities subject to compromise, carrying value	$ 2,932	$ 0
Total debt	4,595	4,343
Liabilities subject to compromise, debt	2,780	0
Carrying Amount
Debt Obligations [Abstract]
Debtor-in-possession (DIP) credit facility, carrying value	148	0
Liabilities subject to compromise, carrying value	2,780	0
Current portion of long-term debt, carrying value	1,815	58
Long-term debt, carrying value	0	4,380
Derivative instruments	9	114
Fair Value
Debt Obligations [Abstract]
Debtor-in-possession (DIP) credit facility, fair value	148	0
Liabilities subject to compromise, fair value	53	0
Current portion of long-term debt, fair value	1,285	44
Long-term debt, fair value	0	2,532
Derivative instruments	9	114
Line of Credit | Reserve-Based Loan Facility, Due November 2021
Debt Obligations [Abstract]
Total debt	$ 315	$ 100

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Commitments and Contingencies - Other Commercial Commitments Narrative (Details) $ in Millions	Dec. 31, 2019 USD ($)
Commitments and Contingencies Disclosure [Abstract]
Other commercial commitments	$ 134
Other commercial commitments, 2020	44
Other commercial commitments, 2021	35
Other commercial commitments, 2022	27
Other commercial commitments, 2023	9
Other commercial commitments, Thereafter	$ 19

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Incentive Compensation / 401(k) Retirement Plan - Performance Share Units Narrative (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Recognition period of fair value as compensation cost	1 year
Performance Share Units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Awards outstanding (in shares)	1,478,100
Shares issuable upon conversion (in shares)	1
Performance period	4 years
Vesting period	3 years
Shares subject to certain settlement and transfer restrictions (in shares)	1,224,000
Grant date fair value of awards		$ 5	$ 12
Unrecognized compensation cost	$ 6
Recognition period of fair value as compensation cost	2 years

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Incentive Compensation / 401(k) Retirement Plan - 401(k) Retirement Plan Narrative (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Retirement Benefits [Abstract]
Maximum matching contributions as a percentage of eligible compensation	6.00%
Non-elective employer contributions as a percentage of eligible compensation	5.00%
Matching and non-elective employer contributions by employer	$ 5	$ 6

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Basis of Presentation and Significant Accounting Policies, Voluntary Reorganization under Chapter 11 Cases

12 Months Ended

Dec. 31, 2019

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Basis of Presentation and Significant Accounting Policies, Voluntary Reorganization under Chapter 11 Cases

Basis of Presentation and Significant Accounting Policies

Basis of Presentation and Consolidation

Our consolidated financial statements are prepared in accordance with United States generally accepted accounting principles (“U.S. GAAP”) and include the accounts of all consolidated subsidiaries after the elimination of all significant intercompany accounts and transactions. 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. The consolidated financial statements included herein have been prepared as if we were a going concern and in accordance with Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) Topic No. 852, Reorganizations. For a further discussion of our Chapter 11 filing, see Note 1A.

We consolidate entities when we have the ability to control the operating and financial decisions of the entity or when we have a significant interest in the entity that gives us the ability to direct the activities that are significant to that entity. The determination of our ability to control, direct or exert significant influence over an entity involves the use of judgment.

We are engaged in the exploration for and the acquisition, development, and production of oil, natural gas and NGLs in the United States. Our oil and natural gas properties are managed as a single operating segment rather than through discrete operating segments or business units. We track basic operational data by area and allocate capital resources on a project-by-project basis across our entire asset base without regard to individual areas.  We assess financial performance as a single enterprise and not on a geographical area basis.

New Accounting Pronouncements Issued But Not Yet Adopted

Income Taxes. In December 2019, the FASB issued ASU No. 2019-12, Income Taxes (Topic 740): Simplifying the Accounting for Income Taxes, which is intended to simplify various aspects related to accounting for income taxes by eliminating certain exceptions within ASC 740, Income Taxes, and clarifying certain aspects of the current guidance. This standard is effective beginning for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2020, with early adoption permitted. The Company is in the process of assessing the impact the adoption of this guidance may have on our consolidated financial statements.

Significant Accounting Policies

Use of Estimates

The preparation of our financial statements requires the use of estimates and assumptions that affect the amounts we report as assets, liabilities, revenues and expenses and our disclosures in these financial statements. Actual results can, and often do, differ from those estimates.

Revenue Recognition

Our revenues are generated primarily through the physical sale of oil, natural gas and NGLs to third party customers at spot or market prices under both short and long-term contracts. We recognize revenue upon satisfaction of our contractual performance obligation requiring us to deliver oil, natural gas and NGLs to a delivery point. Our performance obligation is satisfied upon transfer of control of the commodity to the customer. Transfer of control varies depending on the product and delivery method, but typically occurs when delivery and passage of title and risk of loss have occurred at a pipeline or gathering line delivery point interconnect when delivered via pipeline or at the wellhead or tank battery to purchasers who transport the oil via truck. Realized prices for each barrel of oil, MMcf of natural gas or MMBtu of NGLs are based upon index prices (WTI, LLS, Henry Hub and Mt. Belvieu) or refiners' posted prices at various delivery points across our producing basins. Realized transaction prices received (not considering the effects of hedges) are generally less than the stated index price as a result of contractual deductions, differentials from the index to the delivery point, adjustments for time, and/or discounts for quality or grade.

Revenue is recorded net of any royalty interests or other profit interests in the produced product. Revenues related to products delivered, but not yet billed, are estimated each month. These estimates are based on contract data, commodity prices and preliminary throughput and allocation measurements. When actual sales volumes exceed our entitled share of sales volumes, an overproduced imbalance occurs. To the extent the overproduced imbalance exceeds our share of the remaining estimated proved natural gas reserves for a given property, we record a liability. 

Costs associated with the transportation and delivery of production between the wellhead and its intended sale location are generally included in transportation costs.  We also purchase and sell oil and natural gas on a monthly basis to manage our overall oil and natural gas production and sales. These transactions are undertaken to optimize prices we receive for our oil and natural gas, to physically move oil and gas to its intended sales point, or to manage firm transportation agreements. Revenue related to these transactions are recorded in oil and natural gas sales in operating revenues and associated purchases reflected in oil and natural gas purchases in operating expenses in our consolidated income statements.

For the years ended December 31, 2019 and 2018, we had two and three customers, respectively, that individually accounted for 10 percent or more of our total revenues. The loss of any one customer would not have an adverse effect on our ability to sell our oil, natural gas and NGLs production.

While most of our physical production is priced off of market indices, we actively manage the volatility of market pricing through our risk management program whereby we enter into financial derivatives contracts. All of our derivatives are marked-to-market each period. The change in the fair value of our commodity-based derivatives, as well as any realized amounts, are reflected in operating revenues as financial derivative revenues (see Derivatives below and Note 6).

Cash and Cash Equivalents and Restricted Cash

We consider short-term investments with an original maturity of less than three months to be cash equivalents. As of December 31, 2019, we had $1 million in restricted cash. As of December 31, 2018, we had no restricted cash.

Allowance for Doubtful Accounts

We establish provisions for losses on accounts receivable and for natural gas imbalances with other parties if we determine that we will not collect all or part of the outstanding balance. We regularly review collectability and establish or adjust our allowance as necessary using the specific identification method.

Oil and Natural Gas Properties

We account for oil and natural gas properties in accordance with the successful efforts method of accounting for oil and natural gas exploration and development activities.

Under the successful efforts method, we capitalize (i) lease acquisition costs, all development costs and exploratory drilling costs until results are determined, (ii) certain internal costs directly identified with the acquisition, successful drilling of exploratory wells and development activities, and (iii) interest costs related to financing oil and natural gas projects actively being developed until the projects are evaluated or substantially complete and ready for their intended use if the projects were evaluated as successful. Non-drilling exploratory costs, including certain geological and geophysical costs such as seismic costs and delay rentals, are expensed as incurred.

We provide for depreciation, depletion, and amortization on the basis of common geological structure or stratigraphic conditions applied to total capitalized costs, plus future abandonment costs, net of salvage value, using the unit of production method.  Lease acquisition costs are amortized over total proved reserves, while other exploratory drilling and all developmental costs are amortized over total proved developed reserves.

We evaluate capitalized costs related to proved properties upon a triggering event to determine if impairment of such properties is necessary.  Our evaluation of recoverability is made on the basis of common geological structure or stratigraphic conditions and considers estimated future cash flows primarily from all proved developed (producing and non-producing) and proved undeveloped reserves in comparison to the carrying amount of the proved properties. Estimated future cash flows are determined based on estimates of future oil and gas production, estimated or published commodity prices as of the date of the estimate, adjusted for geographical location, contractual and quality price differentials, and estimates of future operating and development costs. If the carrying amount of a property exceeds these estimated undiscounted future cash flows, the carrying amount is reduced to its estimated fair value through a charge to income. Fair value is calculated by discounting the estimated future cash flows using a risk-adjusted discount rate. This 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. Leasehold acquisition costs associated with non-producing areas are also assessed for impairment based on our estimated drilling plans and anticipated capital expenditures related to potential lease expirations.

Property, Plant and Equipment (Other than Oil and Natural Gas Properties)

Our property, plant and equipment, other than our assets accounted for under the successful efforts method, are recorded at their original cost of construction or, upon acquisition, at the fair value of the assets acquired. We capitalize the major units of property replacements or improvements and expense minor items. We depreciate our non-oil and natural gas property, plant and equipment using the straight-line method over the useful lives of the assets which range from four to seven years. 

Accounting for Asset Retirement Obligations

We record a liability for legal obligations associated with the replacement, removal or retirement of our long-lived assets in the period the obligation is incurred and is estimable. Our asset retirement liabilities are initially recorded at their estimated fair value with a corresponding increase to property, plant and equipment. This increase in property, plant and equipment is then depreciated over the useful life of the asset to which that liability relates. An ongoing expense is recognized for changes in the value of the liability as a result of the passage of time, which we record as depreciation, depletion and amortization expense in our consolidated income statements.

Accounting for Long-Term Incentive Compensation

We measure the cost of long-term incentive compensation based on the fair value of the award on the day it is granted.  Awards issued under our incentive compensation programs are recognized as either equity awards or liability awards based on their characteristics.  Expense is recognized in our consolidated financial statements as general and administrative expense over the period of service required by the award. See Note 10 for further discussion of our long-term incentive compensation.

Environmental Costs, Legal and Other Contingencies

Environmental Costs. We record environmental liabilities at their undiscounted amounts on our consolidated balance sheet in other current and long-term liabilities when we assess that remediation efforts are probable and the costs can be reasonably estimated. Estimates of our environmental liabilities are based on current available facts, existing technology and presently enacted laws and regulations, taking into consideration the likely effects of other societal and economic factors, and include estimates of associated legal costs. These amounts also consider prior experience in remediating contaminated sites, other companies’ clean-up experience and data released by the Environmental Protection Agency (EPA) or other organizations. Our estimates are subject to revision in future periods based on actual costs or new circumstances. We capitalize costs that benefit future periods and expense costs that do not in general and administrative expense.

We evaluate any amounts paid directly or reimbursed by government sponsored programs and potential recoveries or reimbursements of remediation costs from third parties, including insurance coverage, separately from our liability. Recovery is evaluated based on the creditworthiness or solvency of the third party, among other factors. When recovery is assured, we record and report an asset separately from the associated liability on our consolidated balance sheet.

Legal and Other Contingencies.  We recognize liabilities for legal and other contingencies when we have an exposure that indicates it is both probable that a liability has been incurred and the amount of the loss can be reasonably estimated. Where the most likely outcome of a contingency can be reasonably estimated, we accrue a liability for that amount. Where the most likely outcome cannot be estimated, a range of potential losses is established and if no one amount in that range is more likely than any other to occur, the low end of the range is accrued.

Derivatives

We enter into derivative contracts on our oil and natural gas products primarily to stabilize cash flows and reduce the risk and financial impact of downward commodity price movements on commodity sales.  Derivative instruments are reflected on our consolidated balance sheet at their fair value as assets and liabilities. We classify our derivatives as either current or non-current based on their anticipated settlement date. We net derivative assets and liabilities with counterparties where we have a legal right of offset.

All of our derivatives are marked-to-market each period and changes in the fair value of our commodity based derivatives, as well as any realized amounts, are reflected as operating revenues. We classify cash flows related to derivative contracts based on the nature and purpose of the derivative. As the derivative cash flows are considered an integral part of our oil and natural gas operations, they are classified as cash flows from operating activities. In our consolidated balance sheet, receivables and payables resulting from the settlement of our derivative instruments are reported as trade receivables and payables. See Note 6 for a further discussion of our derivatives.

Income Taxes

We record current income taxes based on our estimates of current taxable income and provide for deferred income taxes to reflect estimated future income tax payments and receipts. Changes in tax laws are recorded in the period they are enacted. Deferred taxes represent the tax impacts of differences between the financial statement and tax bases of assets and liabilities and carryovers at each year end. We classify all deferred tax assets and liabilities, along with any related valuation allowance, as non-current on the consolidated balance sheet. We account for tax credits under the flow-through method, which reduces the provision for income taxes in the year the tax credits first become available.

The realization of our deferred tax assets depends on recognition of sufficient future taxable income during periods in which those temporary differences are deductible. We record a valuation allowance against deferred tax assets when, based on our estimates, it is more likely than not that a portion of those assets will not be realized in a future period. The estimates utilized in recognition of deferred tax assets are subject to revision, either up or down, in future periods based on new facts or circumstances. In evaluating our valuation allowances, we consider cumulative book losses, the reversal of existing temporary differences, the existence of taxable income in carryback years, tax planning strategies and future taxable income for each of our taxable jurisdictions, the latter two of which involve the exercise of significant judgment. Changes to our valuation allowances could materially impact our results of operations.

Voluntary Reorganization under 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 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 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 further amended from time to time, the “Plan”) and an updated Disclosure Statement for Fourth Amended Joint Chapter 11 Plan of Reorganization of EP Energy Corporation and its Affiliated Debtors (as further 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 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 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 (“LCs”) 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.

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 (the “Exit Credit Agreement”).

Ability to Continue as a Going Concern. The significant risks and uncertainties related to the Company’s liquidity and the 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. Further, completion of a plan of reorganization could materially change the amounts and classifications of assets and liabilities reported in the consolidated financial statements. The accompanying consolidated financial statements have (i) been prepared on a going concern basis, which contemplates the realization of assets and satisfaction of liabilities and other commitments in the normal course of business and (ii) do not include any adjustments to reflect the possible future effects of this uncertainty on the recoverability or classification of recorded asset amounts or the amounts or classifications of liabilities.

Reorganization Items, Net. 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 have been expensed as incurred as reorganization items in our consolidated statements of income. For the year ended December 31, 2019, reorganization items, net were $65 million and consisted of:

	Year ended   December 31,   2019
	(in millions)
Professional fees	$	44
Rejection of executory contracts approved by Bankruptcy Court	16
DIP Facility costs	5
Total reorganization items, net	$	65

Liabilities subject to compromise. Prepetition unsecured and under-secured obligations that may be impacted by the Chapter 11 Cases have been classified as liabilities subject to compromise on our consolidated balance sheet. These liabilities are reported at the amounts expected to be allowed as claims by the Bankruptcy Court, although they may be settled for less or adjusted depending on Bankruptcy Court actions, further developments with respect to disputed claims, determination of secured status of certain claims, the determination as to the value of any collateral securing claims, proof of claims or other events. Differences between estimated liabilities recorded and claims filed, or to be filed, will be evaluated and resolved in connection with the claims resolution process and adjusted as necessary, and such adjustments may be material.

Liabilities subject to compromise includes allowed claims, prepetition accounts payable and other amounts related to the rejection of executory contracts approved by the Bankruptcy Court. Additional amounts may be included in liabilities subject to compromise in future periods if additional executory contracts and certain unexpired leases are rejected prior to emerging from bankruptcy. Based on the nature of potential allowed claims, future adjustments to amounts recorded as liabilities subject to compromise may be material.

As of December 31, 2019, liabilities subject to compromise were $2,932 million and consisted of:

	Year ended   December 31,   2019
	(in millions)
Senior secured 1.5 lien notes	$	2,092
Senior unsecured notes	688
Prepetition accrued interest on senior secured 1.5 lien and unsecured notes	117
Allowed claims, prepetition accounts payable and other	35
Total liabilities subject to compromise	$	2,932

As a result of the commencement of the Chapter 11 cases, the principal balance on the 1.5 lien notes and senior unsecured notes of $2,092 million and $688 million, respectively, as of December 31, 2019, has been reclassified as liabilities subject to compromise. Additionally, any prepetition accrued interest on the senior secured 1.5 lien notes and senior unsecured notes was also reclassified from accrued liabilities to liabilities subject to compromise as of December 31, 2019 as no interest payments have been made since the commencement of the Chapter 11 Cases or will be made in the future on these notes. Contractual interest expense amounts were $235 million for the year ended December 31, 2019, which is in excess of $211 million included in interest expense on the consolidated statements of income as a result of discontinuing the accrual of interest subsequent to the Petition Date on the senior secured 1.5 lien notes and senior unsecured notes.

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CONSOLIDATED BALANCE SHEETS - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Current assets
Cash and cash equivalents	$ 32	$ 27
Restricted cash	1	0
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
Other property, plant and equipment		81
Total property, plant and equipment, at cost	7,461
Total property, plant and equipment, at cost		7,425
Less accumulated depreciation, depletion and amortization	4,026
Less accumulated depreciation, depletion and amortization		3,651
Total property, plant and equipment, net	3,435
Total property, plant and equipment, net		3,774
Other assets
Derivative instruments	0	13
Unamortized debt issue costs	2	8
Operating lease assets and other	19	1
Total other assets	21	22
Total assets	3,710	4,181
Current liabilities
Current portion of long-term debt	1,815	58
Debtor-in-possession financing	148	0
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	0	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	0
Commitments and contingencies (Note 9)
Stockholders’ equity
Preferred stock, $0.01 par value; 50 million shares authorized; no shares issued or outstanding	0	0
Treasury stock (at cost); one million and less than one million shares at December 31, 2019 and December 31, 2018	(1)	(1)
Additional paid-in capital	3,545	3,536
Accumulated deficit	(5,080)	(4,137)
Total stockholders’ equity	(1,533)	(599)
Total liabilities and equity	3,710	4,181
Class A Stock
Stockholders’ equity
Common stock	3	3
Class B Stock
Stockholders’ equity
Common stock	$ 0	$ 0

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Fair Value Measurements

12 Months Ended

Dec. 31, 2019

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Fair Value Measurements

Fair Value Measurements

We use various methods to determine the fair values of our financial instruments. The fair value of a financial instrument depends on a number of factors, including the availability of observable market data over the contractual term of the underlying instrument. We separate the fair value of our financial instruments into three levels (Levels 1, 2 and 3) based on our assessment of the availability of observable market data and the significance of non-observable data used to determine fair value. Each of the levels are described below:

• Level 1 instruments’ fair values are based on quoted prices in actively traded markets.

• Level 2 instruments’ fair values are based on pricing data representative of quoted prices for similar assets and liabilities in active markets (or identical assets and liabilities in less active markets).

• Level 3 instruments’ fair values are partially calculated using pricing data that is similar to Level 2 instruments, but also reflect adjustments for being in less liquid markets or having longer contractual terms.

The following table presents the carrying amounts and estimated fair values of our financial instruments:

	December 31, 2019				December 31, 2018
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	(in millions)
Debt obligations:
Debtor-in-possession credit facility(1)	$	148	$	148	$	—	$	—
Liabilities subject to compromise(2)	$	2,780	$	53	$	—	$	—
Current portion of long-term debt(1)	$	1,815	$	1,285	$	58	$	44
Long-term debt(1)	$	—	$	—	$	4,380	$	2,532
Derivative instruments	$	9	$	9	$	114	$	114

(1) Current portion of long-term debt includes $315 million of the RBL Facility and the principal balance of the 2024 1.25 Lien Notes and 7.750% Senior Secured Notes due 2026 reflected in current portion of long-term debt on our balance sheet as of December 31, 2019. For a further discussion on our Chapter 11 Cases, reclassification of debt and DIP Facility, see Notes 1A and 8.

(2) Amount includes the principal balance on the 1.5 lien notes and senior unsecured notes totaling approximately $2,780 million reclassified as liabilities subject to compromise as of December 31, 2019.

For the years ended December 31, 2019 and 2018, the carrying amount of cash and cash equivalents, accounts receivable and accounts payable represent fair value because of the short-term nature of these instruments.  Our debt obligations (see Note 8) have various terms, and we estimated the fair value of debt (representing a Level 2 fair value measurement) primarily based on quoted market prices for the same or similar issuances, considering our credit risk.

Oil, Natural Gas and NGLs Derivative Instruments.  We attempt to mitigate a portion of our commodity price risk and stabilize cash flows associated with forecasted sales of oil, natural gas and NGLs through the use of financial derivatives. As of December 31, 2019, we had derivatives contracts in the form of fixed price swaps and three-way collars on 14 MMBbls of oil. As of December 31, 2018, we had derivative contracts for 16 MMBbls of oil and 26 TBtu of natural gas. In addition to the contracts above, we have derivative contracts related to locational basis differences on our oil production. None of our derivative contracts are designated as accounting hedges.

As of December 31, 2019 and 2018, all derivative financial instruments were classified as Level 2. Our assessment of the level of an instrument can change over time based on the maturity or liquidity of the instrument, which can result in a change in the classification level of the financial instrument.

The following table presents the fair value associated with our derivative financial instruments as of December 31, 2019 and 2018.  All of our derivative instruments are subject to master netting arrangements which provide for the unconditional right of offset for all derivative assets and liabilities with a given counterparty in the event of default. We present assets and liabilities related to these instruments in our consolidated balance sheets as either current or non-current assets or liabilities based on their anticipated settlement date, net of the impact of master netting agreements.  On derivative contracts recorded as assets in the table below, we are exposed to the risk that our counterparties may not perform.

	Level 2
	Derivative Assets									Derivative Liabilities
	Gross Fair Value					Balance Sheet Location				Gross Fair Value					Balance Sheet Location
			Impact of Netting			Current		Non-current					Impact of Netting		Current		Non-current
			(in millions)										(in millions)
December 31, 2019
Derivative instruments	$	14	$	(5	)	$	9	$	—	$	(5	)	$	5	$	—	$	—
December 31, 2018
Derivative instruments	$	116	$	(2	)	$	101	$	13	$	(2	)	$	2	$	—	$	—

For the years ended December 31, 2019 and 2018, we recorded a derivative loss of $81 million and a derivative gain of $84 million, respectively. Derivative gains and losses on our oil, natural gas and NGLs financial derivative instruments are recorded in operating revenues in our consolidated income statements.

Credit Risk. We are subject to a risk of loss on our derivative instruments that could occur if our counterparties do not perform pursuant to the terms of their contractual obligations. We maintain credit policies with regard to our counterparties to minimize our overall credit risk. These policies require that we (i) evaluate potential counterparties’ financial condition to determine their credit worthiness; (ii) monitor our oil, natural gas and NGLs counterparties’ credit exposures; (iii) review significant counterparties' credit from physical and financial transactions on an ongoing basis; (iv) use contractual language that affords us netting or set-off opportunities to mitigate risk; and (v) when appropriate, require counterparties to post cash collateral, parent guarantees or letters of credit to minimize credit risk.  Our assets related to derivatives as of December 31, 2019 represent financial instruments from two counterparties, all of which are lenders associated with our RBL Facility with an “investment grade” (minimum Standard & Poor’s rating of BBB+ or better) credit rating. Subject to the terms of our RBL Facility, collateral or other securities are not exchanged in relation to derivatives activities with the parties in the RBL Facility.

Other Fair Value Considerations. During the years ended December 31, 2019 and 2018, we recorded non-cash impairment charges on our proved properties in NEU and on our proved and unproved properties in the Permian basin. The estimate of fair value of our proved oil and natural gas properties used to determine the impairment was estimated using a discounted cash flow model and other relevant financial and transactional market participant data. These estimates represented a Level 3 fair value measurement. Significant Level 3 inputs associated with the calculation of discounted cash flows used in the impairment analysis include management’s estimate of future crude oil and natural gas prices, production costs, development expenditures, anticipated production of proved reserves, appropriate risk-adjusted discount rates and other relevant data. See Notes 1 and 3 for a further discussion of our impairment charges.

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Incentive Compensation / 401(k) Retirement Plan

12 Months Ended

Dec. 31, 2019

Retirement Benefits [Abstract]

Incentive Compensation / Retirement 401(k) Plan

Incentive Compensation / 401(k) Retirement Plan

Overview. Under our current stock-based compensation plans (the EP Energy Corporation 2014 Omnibus Incentive Plan and 2017 EP Energy Corporation Employment Inducement Plan), we may issue to our employees and non-employee directors various forms of long-term incentive (“LTI”) compensation including stock options, stock appreciation rights, restricted stock, restricted stock units, performance shares/units, incentive awards, cash awards, and other stock-based awards. We are authorized to grant awards of up to 36,832,525 shares of our common stock for awards under these plans, with 10,579,000 shares remaining available for issuance as of December 31, 2019. 

In addition, in conjunction with the acquisition of certain of our subsidiaries by Apollo and other private equity investors in 2012 (the Acquisition), we issued Class B shares (formerly management incentive units intended to constitute profits interests) which become payable only on the achievement of certain predetermined performance measures as further described below.  No additional Class B shares are available for issuance.

We record stock-based compensation expense as general and administrative expense over the requisite service period. For the years ended December 31, 2019 and 2018, we recognized pre-tax compensation expense related to our LTI programs, net of the impact of forfeitures of approximately $9 million and $14 million, respectively, and recorded an associated income tax benefit of $2 million and $4 million for the years 2019 and 2018, respectively.

Restricted stock.  We grant shares of restricted common stock which carry voting and dividend rights and may not be sold or transferred until they are vested. The fair value of our restricted stock is determined on the date of grant and these shares generally vest in equal amounts over three years from the date of the grant. A summary of the changes in our non-vested restricted shares for the year ended December 31, 2019 is presented below:

	Number of Shares		Weighted Average Grant Date Fair Value per Share
Non-vested at December 31, 2018	7,060,334		$	2.69
Granted	103,000		$	0.70
Vested	(2,648,390	)	$	3.22
Forfeited	(1,000,409	)	$	2.45
Non-vested at December 31, 2019	3,514,535		$	2.30

The total unrecognized compensation cost related to these arrangements at December 31, 2019 was approximately $6 million, which is expected to be recognized over a weighted average period of approximately two years.

Performance Share Units. As of December 31, 2019, we had 1,478,100 of outstanding performance share units (PSUs). The PSUs represent a contractual right to receive one share of EP Energy’s common stock if certain conditions are met, and the number of PSUs actually earned, if any, will be based upon achievement of specified stock price goals over a four-year performance period (grant date thru October 2021). For accounting purposes, the PSUs are treated as an equity award and will vest over a weighted average period of three years with expense recognized on an accelerated basis over the life of the award. Of the 1,478,100 PSU’s outstanding at December 31, 2019, 1,224,000 shares will remain subject to certain settlement and transfer restrictions from November 2021 through October 2024 unless certain conditions are satisfied.

The grant date fair value of the 2018 and 2017 awards was approximately $5 million and $12 million, respectively, as determined by a Monte Carlo simulation, utilizing multiple input variables that determine the probability of satisfying the market condition stipulated in the award. Volatility was based on life-to-date volatility of EP Energy’s common stock, which has been publicly traded for an amount of time less than the contractual term of the award. We estimated the risk free rate based on zero coupon U.S. Treasury STRIPS (Separate Trading of Registered Interest and Principal of Securities) that have a term equal to the length of the period from the valuation date to the final vest date. The following table summarizes the significant assumptions used to calculate the grant date fair value of the PSUs:

	2018 Awards		2017 Awards
Expected Term in Years	4		6
Expected Volatility	89.62	%	100.03	%
Risk-Free Interest Rate	2.75	%	1.89	%

Total compensation cost related to our non-vested performance share units not yet recognized at December 31, 2019 was $6 million, which is expected to be recognized over a weighted average period of two years.

Key Employee Retention Program. On May 29, 2019, the Compensation Committee of the Board of Directors of the Company approved the implementation of a Key Employee Retention Program (a “KERP”) for all employees of the Company. KERP payments totaling approximately $21 million were made in July 2019 and were comprised of approximately $10 million in lieu of target bonus amounts for 2019 performance, which were already being accrued during the year, plus an incremental amount of approximately $11 million in lieu of long-term incentive compensation for 2019. KERP payments are subject to certain termination provisions through June 30, 2020 which would result in the repayment of the award in full.

As of December 31, 2019, our consolidated balance sheet reflects a deferred charge in the amount of approximately$10 million related to the KERP. For accounting purposes, deferred expense is being amortized over the 13-month term of the KERP agreement. During the year ended December 31, 2019, we recorded $10 million in expense related to the KERP.

Other. We have issued and/or granted, in prior periods, (i) Class B shares (including those issued to EPE Employee Holdings, II, LLC, a subsidiary), which payout only occurs on the achievement of certain predetermined performance measures (e.g., certain liquidity events in which our private equity investors receive a return of at least one times their invested capital plus a stated return), (ii) stock options at a strike price of $19.82 per share and (iii) total shareholder return (TSR) based performance units treated as liability awards. Due to both reductions in force affecting the holders of these awards and/or declines in stock price performance in recent years, these awards will not materially impact the company and as of December 31, 2019, we had (i) unrecognized compensation expense of $1 million related to Class B shares, which will only be recognized should the liquidity events described above occur and the right to such amounts become nonforfeitable and (ii) less than $1 million in unrecognized compensation cost for non-vested performance units, which is expected to be recognized over a weighted average period of less than one year.

401(k) Retirement Plan. We sponsor a tax-qualified defined contribution retirement plan for a broad-based group of employees.  We make matching contributions (dollar for dollar up to 6% of eligible compensation) and non-elective employer contributions (5% of eligible compensation) to the plan, and individual employees are also eligible to contribute to the defined contribution plan. During 2019 and 2018, we contributed $5 million and $6 million, respectively, of matching and non-elective employer contributions.

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Fair Value Measurements - Additional Information (Details) MMBTU in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2019 USD ($) Contract counterparty MMBbls	Dec. 31, 2018 USD ($) MMBTU MMBbls
Derivative [Line Items]
Gain on derivative instruments | $	$ (81)	$ 84
Number of counterparties | counterparty	2
Derivatives not designated as accounting hedges | Oil derivatives
Derivative [Line Items]
Volume notional amount (in MMBbls) | MMBbls	14	16
Derivatives not designated as accounting hedges | Natural gas derivatives
Derivative [Line Items]
Energy notional amount (in MMBtu) | MMBTU		26
Designated as accounting hedges
Derivative [Line Items]
Number of derivative contracts designated as accounting hedges | Contract	0

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Income Taxes - Additional Information (Details) - USD ($)	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Income Tax Disclosure [Abstract]
Effective tax rate	0.00%	0.00%
Unrecognized tax benefits	$ 46,000,000	$ 0
Interest and penalties related to unrecognized tax benefits	0	0
Accrued interest and penalties associated with income taxes	0	0
Federal net operating loss carryover subject to limitations	0
Alternative minimum tax credits	0
Valuation allowance on deferred tax assets	$ (1,064,000,000)	$ (857,000,000)

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Acquisitions and Divestitures - Divestitures (Details) $ in Millions	Dec. 31, 2018 USD ($)
Northeastern Utah | Held-for-Sale
Divestitures
Sale price of assets	$ 177

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Income Taxes (Tables)

12 Months Ended

Dec. 31, 2019

Income Tax Disclosure [Abstract]

Pretax loss and the components of income tax benefit

The tables below show the pretax loss and the components of income tax expense for the following periods:

	Year Ended December 31,
	2019			2018
	(in millions)
Pretax Loss	$	(943	)	$	(1,003	)
Components of Income Tax Expense
Current
Federal	$	—		$	—
State	—			—
	$	—		$	—
Deferred
Federal	$	—		$	—
State	—			—
Total income tax expense	$	—		$	—

Effective tax rate reconciliation

Our income taxes included in net income differ from the amount computed by applying the statutory federal income tax rate of 21% for the following reasons:

	Year Ended December 31,
	2019			2018
	(in millions)
Income taxes at the statutory federal rate	$	198		$	211
Increase (decrease)
State income taxes, net of federal income tax effect	11			8
Change in valuation allowance	(207		)	(213		)
Capital loss expiration	—			(5		)
Other	(2		)	(1		)
Income tax expense	$	—		$	—

Components of deferred tax assets and liabilities

The following are the components of net deferred tax assets and liabilities:

	December 31,   2019			December 31,   2018
	(in millions)
Deferred tax assets
Property, plant and equipment	$	238		$	157
Net operating loss carryovers	642			611
Employee benefits	1			2
Lease obligations	4			—
Legal and other reserves	17			9
Asset retirement obligations	10			9
Interest deduction limitation	125			76
Transaction costs	33			14
Total deferred tax assets	1,070			878
Valuation allowance	(1,064		)	(857		)
Net deferred tax assets	6			21
Deferred tax liabilities
Operating lease assets	4			—
Financial derivatives	2			21
Total deferred tax liabilities	6			21
Net deferred tax liabilities	$	—		$	—

Federal and state net operating loss and tax credit carryovers

The table below presents the details of our federal and state net operating loss carryover periods as of December 31, 2019 (in millions): 

	Expiration Period
	2031 - 2037		No expiration(1)		Total
U.S. federal net operating loss carryover(1)	$	2,524	$	429	$	2,953

	2026 - 2038
State net operating loss carryover	$	480

(1) U.S. federal net operating loss carryovers generated since 2018 do not expire but are limited to 80% of taxable income per year.

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Commitments and Contingencies (Tables)

12 Months Ended

Dec. 31, 2019

Commitments and Contingencies Disclosure [Abstract]

Supplemental Balance Sheet Information

Supplemental balance sheet information related to leases was as follows:

	December 31, 2019
	(in millions)
Operating lease assets(1)(4)	$	18
Finance lease assets(2)	10
Total lease assets	$	28
Operating leases(3)(4)
Current liability	$	9
Noncurrent liability	9
Total operating lease liability	$	18
Finance leases(3)
Current liability	$	2
Noncurrent liability	9
Total finance lease liability	$	11
Weighted average remaining lease term
Operating leases	3 years
Finance leases	4 years
Weighted average discount rate
Operating leases	9.06		%
Finance leases	26.53		%

(1) Operating lease assets are reflected in Operating lease assets and other in our consolidated balance sheet as of December 31, 2019.

(2) Finance lease assets are reflected in Other property, plant and equipment in our consolidated balance sheet as of December 31, 2019.

(3) Current and noncurrent operating and finance lease liabilities are reflected in Other current liabilities and Lease obligations and other, respectively, in our consolidated balance sheet as of December 31, 2019.

(4) Upon adoption of ASU 2016-02 effective January 1, 2019, we recognized operating leases of approximately $10 million. For the year ended December 31, 2019, we also recorded an additional $16 million of operating leases.

Schedule of Future Minimum Annual Rental Commitments for Non-Cancelable Future Operating Leases

Future minimum annual rental commitments under non-cancelable future operating and finance lease commitments at December 31, 2019, were as follows:

Year Ending December 31,	Operating Leases			Finance Leases
	(in millions)
2020	$	10		$	5
2021	3			5
2022	2			5
2023	2			2
Thereafter	4			—
Total	$	21		$	17
Less: imputed interest	(3		)	(6		)
Present value of operating and finance lease obligations	$	18		$	11

Schedule of Future Minimum Annual Rental Commitments for Finance Leases

Future minimum annual rental commitments under non-cancelable future operating and finance lease commitments at December 31, 2019, were as follows:

Year Ending December 31,	Operating Leases			Finance Leases
	(in millions)
2020	$	10		$	5
2021	3			5
2022	2			5
2023	2			2
Thereafter	4			—
Total	$	21		$	17
Less: imputed interest	(3		)	(6		)
Present value of operating and finance lease obligations	$	18		$	11

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Basis of Presentation and Significant Accounting Policies, Voluntary Reorganization under Chapter 11 Cases - Schedule of Reorganization Items (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Reorganizations [Abstract]
Professional fees	$ 44
Rejection of executory contracts approved by Bankruptcy Court	16
DIP Facility costs	5
Total reorganization items, net	$ 65	$ 0

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Commitments and Contingencies - Future Minimum Annual Rental Commitments Under Non-Cancelable Future Operating and Finance Lease Commitments (Details) $ in Millions	Dec. 31, 2019 USD ($)
Operating Leases
2020	$ 10
2021	3
2022	2
2023	2
Thereafter	4
Total	21
Less: imputed interest	(3)
Present value of operating lease obligations	18
Finance Leases
2020	5
2021	5
2022	5
2023	2
Thereafter	0
Total	17
Less: imputed interest	(6)
Present value of finance lease obligations	$ 11

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Debt - Additional Information (Details) - USD ($) $ in Millions		1 Months Ended	12 Months Ended
	Nov. 25, 2019	Jan. 31, 2018	Dec. 31, 2019	Dec. 31, 2018	Oct. 18, 2019	Sep. 03, 2019	Aug. 15, 2019
Debt Instrument [Line Items]
Gain (loss) on extinguishment of debt			$ 10	$ 73
Debtor-in possession financing, loans outstanding			148	0
Senior Secured Note due May 1, 2024
Debt Instrument [Line Items]
Principal amount issued		$ 1,100
Gain (loss) on extinguishment/modification of debt		(12)
Gain (loss) on extinguishment of debt		$ 53
Unsecured Debt
Debt Instrument [Line Items]
Gain (loss) on extinguishment of debt			10	32
Repayments of outstanding amount			40	49
Aggregate principal amount repurchased			50	84
Senior Secured Notes due February 15, 2025
Debt Instrument [Line Items]
Principal amount issued					$ 138
Cash interest payment due, not paid							$ 40
Senior Unsecured Notes due September 1, 2022
Debt Instrument [Line Items]
Cash interest payment due, not paid						$ 7
Debtor-In-Possession Senior Secured Superpriority Revolving Credit Facility
Debt Instrument [Line Items]
Principal amount issued	$ 629
Debtor-in-possession financing, amount arranged	315
Debtor-in possession financing, remaining borrowing capacity			150
Debtor-in possession financing, loans outstanding			148	$ 0
Letter of Credit
Debt Instrument [Line Items]
Debtor-in-possession financing, amount arranged	$ 50
Debtor-in-possession letter of credit outstanding			$ 17
LIBOR | Debtor-In-Possession Senior Secured Superpriority Revolving Credit Facility
Debt Instrument [Line Items]
Debtor-in possession financing, basis spread on variable rate	3.50%
Debt Instrument Variable Rate Alternate Base Rate | Debtor-In-Possession Senior Secured Superpriority Revolving Credit Facility
Debt Instrument [Line Items]
Debtor-in possession financing, basis spread on variable rate	2.50%
Debtor-in possession financing, unused capacity, commitment fee percentage	0.50%

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Property, Plant and Equipment - Additional Information (Details) $ in Millions	12 Months Ended
	Dec. 31, 2019 USD ($)	Dec. 31, 2018 USD ($)
Property, Plant and Equipment [Line Items]
Property, Plant, And Equipment And Finance Lease Right-Of-Use Asset, After Accumulated Depreciation And Amortization	$ 3,435
Property, plant and equipment, net of accumulated depreciation, depletion, and amortization		$ 3,774
Projected inflation rate	2.50%
Capitalized interest	$ 5	$ 5
Risk-Free Interest Rate | Minimum
Property, Plant and Equipment [Line Items]
Credit-adjusted risk-free rate	0.07
Risk-Free Interest Rate | Maximum
Property, Plant and Equipment [Line Items]
Credit-adjusted risk-free rate	0.09