UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q

(Mark One)

x QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES

EXCHANGE ACT OF 1934

For the quarterly period ended September 30, 2019

o TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES

EXCHANGE ACT OF 1934

For the transition period from to

Commission File Number 333-183815

EP Energy LLC

(Exact Name of Registrant as Specified in Its Charter)



Delaware		45-4871021
(State or Other Jurisdiction of Incorporation or Organization)		(I.R.S. Employer Identification No.)

1001 Louisiana Street Houston, Texas		77002
(Address of Principal Executive Offices)		(Zip Code)

Telephone Number: (713) 997-1000

Internet Website: www.epenergy.com

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes o No x

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) 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, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” a “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 Exchange Act).Yes o No x

Securities registered pursuant to Section 12(b) of the Act: None

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EP ENERGY LLC

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Caption		Page
	PART I — FINANCIAL INFORMATION

Item 1.	Financial Statements	3
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	20
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	34
Item 4.	Controls and Procedures	34

	PART II — OTHER INFORMATION

Item 1.	Legal Proceedings	35
Item 1A.	Risk Factors	35
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	38
Item 3.	Defaults Upon Senior Securities	38
Item 4.	Mine Safety Disclosures	38
Item 5.	Other Information	38
Item 6.	Exhibits	39
Signatures		41

Below is a list of terms that are common to our industry and used throughout this document:



/d	=	per day
Bbl	=	barrel
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
MMBbls	=	million barrels
MMcf	=	million cubic feet
MMGal	=	million gallons
Mt. Belvieu	=	Mont Belvieu natural gas liquids pricing index
NGLs	=	natural gas liquids
NYMEX	=	New York Mercantile Exchange
TBtu	=	trillion British thermal units
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. In calculating equivalents, we use a generally recognized standard in which one Bbl of oil and/or NGLs is equal to six Mcf of natural gas. Also, when we refer to cubic feet measurements, all measurements are at a pressure of 14.73 pounds per square inch.

When we refer to “us”, “we”, “our”, “ours”, “the Company” or “EP Energy”, we are describing EP Energy LLC and/or its subsidiaries.

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CAUTIONARY STATEMENTS FOR PURPOSES OF THE “SAFE HARBOR” PROVISIONS OF THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995

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 Quarterly Report on Form 10-Q, 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:

• 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, 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;

•

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 our Ch. 11 Plan from various stakeholders and confirm and consummate that plan in accordance with the terms of the plan support agreement and/or the backstop commitment agreement as described in Part I, Item 1, Financial Statements, Note 1A;

•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;

•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 forbearances thereunder;

•our ability to generate sufficient cash flow to meet our debt obligations and commitments;

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

•our ability to obtain necessary governmental approvals for proposed exploration and production projects and

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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,” of our 2018 Annual Report on Form 10-K, the

additional factors described under Item 1A, “Risk Factors”, of this Quarterly Report on Form 10-Q, 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 any forward-looking statements, whether as a result of new information, subsequent events, anticipated or unanticipated circumstances or otherwise.

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PART I — FINANCIAL INFORMATION

Item 1. Financial Statements

EP ENERGY LLC

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

(In millions)

(Unaudited)



	Quarter ended September 30,						Nine months ended September 30,
	2019			2018			2019			2018
Operating revenues
Oil	$	193		$	287		$	590		$	820
Natural gas	10			15			36			55
NGLs	12			36			45			92
Financial derivatives	32			(44		)	(34		)	(122		)
Total operating revenues	247			294			637			845

Operating expenses
Oil and natural gas purchases	—			3			—			3
Transportation costs	23			25			71			76
Lease operating expense	34			46			101			123
General and administrative	38			21			102			68
Depreciation, depletion and amortization	116			127			304			376
Gain on sale of assets	—			(1		)	—			(1		)
Impairment charges	458			—			458			—
Exploration and other expense	1			2			3			3
Taxes, other than income taxes	12			22			43			63
Total operating expenses	682			245			1,082			711

Operating (loss) income	(435		)	49			(445		)	134
Other income	4			2			4			2
Gain on extinguishment/modification of debt	—			—			10			48
Interest expense	(189		)	(95		)	(379		)	(268		)
Loss before income taxes	(620		)	(44		)	(810		)	(84		)
Income tax expense	—			—			—			—
Net loss	$	(620	)	$	(44	)	$	(810	)	$	(84	)

See accompanying notes.

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EP ENERGY LLC

CONDENSED CONSOLIDATED BALANCE SHEETS

(In millions)

(Unaudited)



	September 30, 2019		December 31, 2018
ASSETS
Current assets
Cash and cash equivalents	$	188	$	27
Restricted cash	1		—
Accounts receivable
Customer, net of allowance of less than $1 in 2019 and 2018	118		164
Other, net of allowance of $1 in 2019 and 2018	15		66
Materials and supplies	46		22
Derivative instruments	46		101
Other	38		5
Total current assets	452		385
Property, plant and equipment, at cost
Oil and natural gas properties	7,320		7,344
Other property, plant and equipment	71		81
	7,391		7,425
Less accumulated depreciation, depletion and amortization	3,915		3,651
Total property, plant and equipment, net	3,476		3,774
Other assets
Derivative instruments	12		13
Unamortized debt issue costs - revolving credit facility	—		8
Operating lease assets and other	22		1
	34		22
Total assets	$	3,962	$	4,181

See accompanying notes.

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EP ENERGY LLC

CONDENSED CONSOLIDATED BALANCE SHEETS

(In millions)

(Unaudited)



	September 30, 2019			December 31, 2018
LIABILITIES AND EQUITY
Current liabilities
Current portion of long-term debt	$	4,882		$	58
Owner and royalties payable	76			144
Accounts payable and accrued expenses	122			105
Accrued interest	161			70
Accrued legal and other reserves	37			47
Other current liabilities	23			16
Total current liabilities	5,301			440

Long-term debt, net of debt issue costs	—			4,285
Other long-term liabilities
Asset retirement obligations	41			39
Lease obligations and other	22			16
Total non-current liabilities	63			4,340

Commitments and contingencies (Note 7)
Member’s equity	(1,402		)	(599		)
Total liabilities and equity	$	3,962		$	4,181

See accompanying notes.

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EP ENERGY LLC

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(In millions)

(Unaudited)



	Nine months ended September 30,
	2019			2018
Cash flows from operating activities
Net loss	$	(810	)	$	(84	)
Adjustments to reconcile net loss to net cash provided by operating activities
Depreciation, depletion and amortization	304			376
Gain on sale of assets	—			(1		)
Impairment charges	458			—
Gain on extinguishment/modification of debt	(10		)	(48		)
Write-off of debt discount and deferred issue costs	90			—
Other non-cash income items	20			22
Asset and liability changes				1
Accounts receivable	96			(69		)
Owner and royalties payable	(68		)	35
Accounts payable and accrued expenses	(3		)	(18		)
Derivative instruments	56			87
Accrued interest	91			50
Other asset changes	(55		)	6
Other liability changes	(20		)	14
Net cash provided by operating activities	149			370

Cash flows from investing activities
Cash paid for capital expenditures	(422		)	(559		)
Proceeds from the sale of assets	—			175
Cash paid for acquisitions	(18		)	(275		)
Net cash used in investing activities	(440		)	(659		)

Cash flows from financing activities
Proceeds from issuance of long-term debt	923			1,805
Repayments and repurchases of long-term debt	(468		)	(1,431		)
Fees/costs on debt exchange	—			(62		)
Contributions from parent	—			9
Debt issue costs	—			(21		)
Other	(2		)	—
Net cash provided by financing activities	453			300

Change in cash, cash equivalents and restricted cash	162			11

Cash, cash equivalents and restricted cash - beginning of period	27			45
Cash, cash equivalents and restricted cash - end of period	$	189		$	56

See accompanying notes.

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EP ENERGY LLC

CONDENSED CONSOLIDATED STATEMENT OF CHANGES IN EQUITY

(In millions)

(Unaudited)



	Total Member’s Equity
Balance at December 31, 2017	$	383
Cash contributions from parent	4
Net income	18
Balance at March 31, 2018	$	405
Share-based compensation	3
Net loss	(58		)
Balance at June 30, 2018	$	350
Share-based compensation	2
Cash contributions from parent	9
Net loss	(44		)
Balance at September 30, 2018	$	317
Cash contributions from parent	(4		)
Share-based compensation	7
Net loss	(919		)
Balance at December 31, 2018	$	(599	)
Share-based compensation	3
Net loss	(140		)
Balance at March 31, 2019	$	(736	)
Share-based compensation	1
Net loss	(50		)
Balance at June 30, 2019	$	(785	)
Share-based compensation	3
Net loss	(620		)
Balance at September 30, 2019	(1,402		)

See accompanying notes.

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EP ENERGY LLC

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

1. Basis of Presentation and Significant Accounting Policies

Basis of Presentation

We prepared this Quarterly Report on Form 10-Q under the rules and regulations of the United States Securities and Exchange Commission (SEC) and in accordance with United States generally accepted accounting principles (U.S. GAAP) as it applies to interim financial statements. Because this is an interim period report presented using a condensed format, it does not include all of the disclosures required by U.S. GAAP and should be read along with our 2018 Annual Report on Form 10-K. The condensed consolidated financial statements as of September 30, 2019 and 2018 are unaudited. The consolidated balance sheet as of December 31, 2018 has been derived from the audited consolidated balance sheet included in our 2018 Annual Report on Form 10-K. In our opinion, all adjustments which are of a normal, recurring nature are reflected to fairly present these interim period results. Our financial statements for prior periods include reclassifications that were made to conform to the current year presentation, none of which impacted our reported net income, stockholder’s equity or cash flows from operating activities. The results for any interim period are not necessarily indicative of the expected results for the entire year.

Significant Accounting Policies

In the first quarter of 2019, we adopted Accounting Standards Update (ASU) No. 2016-02, Leases, which requires lessees to recognize lease assets and liabilities on the balance sheet and disclose key information about leasing arrangements. We adopted this standard 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. For a further discussion on leases, see Note 7.

1A. Voluntary Reorganization under Chapter 11 Proceedings

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 Proceedings. 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

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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 have 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 have 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, 2024 1.5 Lien Notes, 9.375% Senior Secured Notes due 2024, 9.375% Senior Notes due 2020, 7.750% Senior Unsecured 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.

Plan Support 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 (the “Plan”) with holders of approximately 52.0% of the 8.000% Senior Secured Notes due 2024 (the “2024 1.5 Lien Notes”) and approximately 79.3% of the 9.375% Senior Secured Notes due 2024 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 included affiliates of, or funds managed by, Elliott Management Corporation, Apollo (together with Elliott, the “Initial Supporting Noteholders”), Access, and Avenue Capital Group (collectively, with the Initial Supporting Noteholders and Access, the “Supporting Noteholders”). Pursuant to the PSA, the Plan will be implemented in accordance with the plan term sheet annexed to the PSA, which is premised on (i) an equity rights offering (the “Rights Offering”), $463 million of which is backstopped by the Supporting Noteholders under a backstop commitment agreement (the “BCA”), and (ii) an approximately $629 million exit facility for which, as of October 18, 2019, over 90% of the lenders under the RBL Facility have committed to provide support, and which the RBL Facility and proposed DIP Facility discussed below will convert into on the effective date of the Plan. Capitalized terms used in this section but not otherwise defined shall have the meanings ascribed to such terms in the PSA (noted as an exhibit to this filing) or as noted below in the Backstop Commitment Agreement or Debtor-in-Possession Agreement discussions.

The PSA contemplates a Plan which would provide for the following treatment:

Holders of RBL Claims will receive their Pro Rata share of the Exit Facility as a first lien, second-out term loan; provided that each holder of an Allowed RBL Claim that elects to participate in the Exit Facility by the Voting Deadline will receive its Pro Rata share (with the holders of Allowed DIP Claims) of first lien, first-out revolving loans and letter of credit participations under the Exit Credit Agreement.

Holders of 1.125L Notes Claims will be reinstated in the principal amount of $1 billion and Holders of 1.25L Notes Claims will be reinstated in the principal amount of $500 million, provided that the Debtors may, with the consent of the Initial Supporting Noteholders, deliver a notice of redemption with respect to, or otherwise voluntarily prepay (including by way of tender offer), a portion of these notes, or (ii) receive new notes on terms acceptable to the Initial Supporting Noteholders and the Company.


c)	Holders of 1.5L Notes Claims will receive, on account of the secured portion of such 1.5L Notes Claims, their pro rata share of (i) 99.0% of the New Common Shares, subject to dilution by the Rights Offering Shares, the Private Placement, the Commitment Premium, the Jeter and EIP Shares, and (ii) the right to participate in the Rights Offering.

Holders of Unsecured Claims will receive their pro rata share of 1.0% of the New Common Shares, subject to dilution by the Rights Offering Shares, the Commitment Premium, the Private Placement, the Jeter and EIP Shares (as defined below); provided, that a convenience class may be established under the Plan (with such Plan provisions being acceptable to the Initial Supporting Noteholders) to provide distributions up to an aggregate amount in Cash to be specified under the Plan.


e)	Holders of existing Class A common stock and restricted stock prior to reorganization will receive, on account of available assets of the Company, their pro rata share of $500,000 in cash.

The Plan will also provide for the following additional terms:

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a)	Apollo and Access may contribute their equity interests in Wolfcamp Drillco Operating L.P. to the reorganized debtors in exchange for New Common Shares (the “Jeter Shares”), subject to the agreement of the Company, Access, and the Initial Supporting Noteholders.


b)	The Company may consummate a private placement of New Common Shares, subject to dilution by the Jeter and EIP Shares, for an aggregate purchase price of up to $75 million, in cash.

Establishment of a post-emergence employee incentive plan (the “EIP”) on the effective date of the Plan. All awards issued under the EIP, including restricted stock units, options, New Common Shares, or other rights exercisable, exchangeable, or convertible into New Common Shares (“EIP shares”) will be dilutive of all other equity interests in the reorganized debtors in accordance with the Plan. Ten percent of the New Common Shares, on a fully diluted basis, shall be reserved for issuance in connection with the EIP.

The PSA contains certain covenants on the part of the Company and the Supporting Noteholders, including that the Supporting Noteholders vote in favor of the Plan and otherwise facilitate the restructuring transactions, subject to the terms of the PSA. The PSA also provides for termination by each party upon the occurrence of certain events, including without limitation the failure of the Company to achieve certain milestones and the termination of the BCA (discussed further below).

Backstop Commitment Agreement. On October 18, 2019 the Debtors entered into the BCA with the Commitment Parties pursuant to which they agreed to backstop $463 million of the Rights Offering. The BCA is subject to Bankruptcy Court approval. Capitalized terms used in this section but not otherwise defined herein shall have the meanings ascribed to such terms in the BCA noted as an exhibit to this filing.

The Commitment Parties have committed, in connection with the Rights Offering, to (i) exchange $138 million in principal amount of 2025 1.25 Lien Notes for New Common Shares at the Exchange Purchase Price (the "Exchange Transaction") and (ii) purchase additional New Common Shares at the Cash Purchase Price for cash consideration of up to $325 million (reduced dollar for dollar for cash proceeds received in the Rights Offering) (the "Cash Purchase Obligation"). The Special Committee approved entry into the PSA and BCA.

As consideration for their backstop commitment, the Commitment Parties shall be entitled to receive $26 million in the form of New Common Shares issued at the Cash Purchase Price (the “Commitment Premium”). Alternatively, if the BCA is terminated due to certain events specified therein, the Commitment Parties shall be entitled to receive a $26 million cash termination fee (the “Termination Fee”). The Commitment Premium and Termination Fee will be allocated among the Commitment Parties as provided in the BCA.

The Commitment Parties’ obligation to backstop the Rights Offering, and the other transactions contemplated by the BCA, are conditioned upon the satisfaction (or waiver) of all conditions to the effectiveness of the Plan, and other conditions precedent set forth in the BCA, including Bankruptcy Court approval of the BCA. The BCA may be terminated upon the occurrence of certain events, including termination of the PSA and material, uncured breaches by the parties under the BCA.

Debtor-in-Possession Agreement. In connection with the PSA and the Chapter 11 Cases, on October 18, 2019, the Debtors also received an underwritten commitment from certain of the lenders under the RBL Facility to provide (i) for an approximately $315 million Senior Secured Superpriority Debtor-in-Possession Facility (the “DIP Facility”), and (ii) support for an approximately $629 million Senior Secured Revolving Exit Facility (the “Exit Facility”), which will consist of a first-out revolving tranche provided by the lenders under the DIP Facility (whose remaining claims under the RBL Facility will automatically convert into such first-out revolving tranche upon effectiveness of the Exit Facility) and a second-out term loan tranche provided by the lenders under the RBL Facility which are not also lenders under the DIP Facility (whose claims under the RBL Facility will automatically convert into such second-out term loan tranche upon effectiveness of the Exit Facility) (if any). The Exit Facility is anticipated to be effective upon the Debtors’ emergence from the Chapter 11 Cases. The proceeds of the Exit Facility may be used to fund distributions under the Plan, for working capital and for other general corporate purposes, to issue letters of credit, for transaction fees and expenses and for fees related to the Debtors’ emergence from the Chapter 11 Cases. The DIP Facility and the Exit Facility are each subject to customary closing conditions and Bankruptcy Court approval.

Ability to Continue as a Going Concern. The significant risks and uncertainties related to the Company’s liquidity and Chapter 11 proceedings described above raise substantial doubt about the Company’s ability to continue as a going concern. For the duration of the Chapter 11 proceedings, 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 proceedings. The outcome of the Chapter 11 process is subject to a high degree of uncertainty and is dependent upon factors that are outside of the Company’s control, including actions of the Bankruptcy Court and the Company’s creditors. There can be no assurance that we will confirm and consummate the Plan under the PSA or complete another plan of reorganization with respect to the Chapter 11 proceedings. Further, the Plan under the PSA, or completion of another plan of reorganization, could materially change the amounts and

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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.

2. 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 and/or unproved properties in the future.

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 Northeastern Utah (NEU) proved properties were not in excess of the related carrying value of the asset. Accordingly, we have recorded a non-cash impairment charge for both the quarter and nine months ended September 30, 2019 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.

3. Income Taxes

Our taxable income or loss is included in our parent’s (EP Energy Corporation) U.S. federal and certain state returns. EP Energy Corporation pays all consolidated U.S. federal and state income tax directly to the appropriate taxing jurisdictions. We record income taxes on a separate return basis in our financial statements as if we had filed separate income tax returns under our existing structure. In certain states, we also file and pay directly to the state taxing authorities.

Effective Tax Rate. Interim period income taxes are computed by applying an anticipated annual effective tax rate to year-to-date income or loss, except for significant, unusual or infrequently occurring items, which income tax effects are recorded in the period in which they occur. Changes in tax laws or rates are recorded in the period they are enacted.

For both the quarters and nine months ended September 30, 2019 and 2018, our effective tax rates were 0%. Our effective tax rates in 2019 and 2018 differed from the statutory rate of 21% primarily as a result of our recognition of a full valuation allowance on our net deferred tax assets. In addition, we recorded adjustments to the valuation allowance on our net deferred tax assets, which offset deferred income tax benefits by $135 million and $10 million, for the quarters ended September 30, 2019 and 2018, respectively, and by $174 million and $18 million for the nine months ended September 30, 2019 and 2018, respectively.

We evaluate the realization of our deferred tax assets and record any associated valuation allowance after considering 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. Based upon the evaluation of the available evidence, we maintained a valuation allowance against our net deferred tax assets of $710 million as of September 30, 2019.

The Company's and certain subsidiaries' income tax years after 2014 remain open and subject to examination by both federal and state tax authorities, and in 2018 we were notified of an IRS examination of our parent's 2016 U.S. tax return.

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4. 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. As of September 30, 2019 and December 31, 2018, all of our 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.

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



	September 30, 2019				December 31, 2018
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	(in millions)
Current portion of long-term debt	$	4,882	$	1,684	$	58	$	44

Long-term debt (see Note 6)	$	—	$	—	$	4,380	$	2,532

Derivative instruments	$	58	$	58	$	114	$	114

As of September 30, 2019 and December 31, 2018, the carrying amount of cash and cash equivalents, accounts receivable, owner and royalties payable, and accounts payable represent fair value because of the short-term nature of these instruments. We hold debt obligations with various terms. 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 September 30, 2019, we had derivative contracts in the form of collars and three-way collars on 15 MMBbls of oil (3 MMBbls in 2019 and 12 MMBbls in 2020). In addition to our oil derivatives, we had derivative contracts in the form of fixed price swaps and collars on 6 TBtu of natural gas in 2019. 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 and natural gas production. None of our derivative contracts are designated as accounting hedges.

The following table presents the fair value associated with our derivative financial instruments as of September 30, 2019 and December 31, 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
	Gross Fair Value		Impact of Netting			Current		Non- current		Gross Fair Value			Impact of Netting		Current		Non- current
			(in millions)										(in millions)
September 30, 2019
Derivative instruments	$	60	$	(2	)	$	46	$	12	$	(2	)	$	2	$	—	$	—

December 31, 2018
Derivative instruments	$	116	$	(2	)	$	101	$	13	$	(2	)	$	2	$	—	$	—

For the quarters ended September 30, 2019 and 2018, we recorded derivative gains and losses of $32 million and $44 million, respectively. For the nine months ended September 30, 2019 and 2018, we recorded derivative losses of $34 million and $122 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.

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Other Fair Value Considerations. During the quarter and nine months ended September 30, 2019, we recorded a non-cash impairment charge on our proved properties in NEU. 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. 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 Note 2 for a further discussion of our impairment charge.

5. Property, Plant and Equipment

Oil and Natural Gas Properties. As of September 30, 2019 and December 31, 2018, we had approximately $3.5 billion and $3.8 billion, respectively, of total property, plant, and equipment, net of accumulated depreciation, depletion and amortization on our consolidated balance sheets, 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 were as follows:



	September 30, 2019			December 31, 2018
	(in millions)
Proved
Eagle Ford	$	4,250		$	3,898
Permian	1,791			1,787
Northeastern Utah	1,279			1,659
Total Proved	7,320			7,344
Less accumulated depletion	(3,880		)	(3,607		)
Net capitalized costs for oil and natural gas properties	$	3,440		$	3,737

Suspended well costs were not material as of September 30, 2019 or December 31, 2018.

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.

Changes in estimates 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 September 30, 2019 on our consolidated balance sheet in other current and non-current liabilities and the changes in the net liability from January 1 through September 30, 2019 were as follows:



	2019
	(in millions)
Net asset retirement liability at January 1	$	42
Liabilities settled	(1		)
Accretion expense	3
Net asset retirement liability at September 30	$	44

Capitalized Interest. Interest expense is reflected in our consolidated 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 quarters ended September 30, 2019 and 2018 was approximately $2 million, and for the nine months ended September 30, 2019 and 2018 were approximately $5 million and $4 million, respectively.

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6. Long-Term Debt

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



	Interest Rate	September 30, 2019			December 31, 2018
		(in millions)
RBL credit facility - due November 23, 2021⁽¹⁾	Variable	$	602		$	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	8.000%	500			500
1.5 Lien due February 15, 2025	8.000%	1,000			1,000
1.125 Lien due May 15, 2026	7.750%	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		4,882			4,343
Current portion of long-term debt⁽³⁾		(4,882		)	(58		)
Total long-term debt		$	—		$	4,285


(1)	Carries interest at a specified margin over LIBOR of 2.50% to 3.50%, based on borrowing utilization.


(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 (including those discussed in Note 1A), we reclassified our debt as current and wrote off approximately $90 million in unamortized debt discount and debt issue costs.

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 nine months ended September 30, 2019 and 2018, we recorded a net gain on extinguishment/modification of debt of $10 million and $7 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 the second quarter of 2018, we paid approximately $10 million in cash to repurchase a total of approximately $19 million in aggregate principal amount of our senior unsecured notes due 2022 and 2023.

Reserve-based Loan Facility. As of September 30, 2019, we had borrowed the remaining $268 million under our RBL Facility and had no capacity remaining with approximately $27 million of LCs issued and $602 million outstanding under the RBL Facility.

Guarantees. Our obligations under the RBL Facility, term loans, and unsecured notes are fully and unconditionally guaranteed, jointly and severally, by the Company’s present and future direct and indirect wholly owned material domestic subsidiaries. EP Energy LLC has no independent assets or operations. Any subsidiaries of EP Energy LLC, other than the subsidiary guarantors, are minor. The subsidiary guarantees are subject to certain automatic customary releases, including the sale or disposition of the capital stock or substantially all of the assets of a subsidiary guarantor, exercise of legal defeasance or covenant defeasance, or designation of a subsidiary guarantor as unrestricted in accordance with the applicable indenture. There are no significant restrictions on the ability of the Company or any guarantor to obtain funds from its subsidiaries by dividend or loan.

Covenant Violations, Forbearance, and Chapter 11 Proceedings. On August 15, 2019, we did not make the approximately $40 million cash interest payment due with respect to the 2025 1.5 Lien Senior Secured 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

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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.

7. Commitments and Contingencies

Chapter 11 Proceedings

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.

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 September 30, 2019, we had approximately $26 million accrued for all outstanding legal matters.

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’ (affiliates of Apollo, Riverstone Holdings LLC, Access and Korea National Oil Corporation, collectively, 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 September 30, 2019, we had accrued $21 million related to this matter.

Weyerhaeuser Company v. Pardee Minerals LLC, et al. On July 5, 2017, Weyerhaeuser filed suit against one of our subsidiaries, among other defendants, in the United States District Court for the Western District of Louisiana. Weyerhaeuser seeks to recoup the value of production after November 2006 (approximately $15.6 million) plus judicial interest (approximately $7.8 million at this time) from certain wells drilled by EP Energy between 2002 and 2013 on leases Weyerhaeuser claims were invalid. Weyerhaeuser alleges that lessees prior to EP Energy had not drilled wells in good faith to perpetuate the associated mineral servitude (rights conveyed to produce minerals), rendering EP Energy’s subsequent lease invalid. We settled this matter in July 2019 for $3 million.

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 81^st Judicial District

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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 on July 17, 2019 and intends to pursue fully its appeal. As of September 30, 2019, EP Energy's accrual of $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 (GHG) emissions. Numerous governmental agencies, such as the Environmental Protection Agency (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 the Risk Factors section of our 2018 Annual Report on Form 10-K.

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 September 30, 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

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 quarter ended September 30, 2019, interest and depreciation expense associated with our finance leases was approximately $1 million and less than $1 million, respectively, and related cash payments were approximately $1 million. For the nine months ended September 30, 2019, interest and depreciation expense associated with our finance leases were approximately $3 million and $2 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 quarter ended September 30, 2019, operating lease costs and related cash payments were approximately $3 million and $4 million, respectively, and $8 million and $7 million,

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respectively, for the nine months ended September 30, 2019. 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 quarter and nine months ended September 30, 2019, variable lease costs were approximately $1 million and $2 million, respectively.

Short-term lease costs for the quarter and nine months ended September 30, 2019 were approximately $3 million and $18 million, respectively, and were primarily capitalized as part of our oil and natural gas properties.

Supplemental balance sheet information related to leases was as follows:



	September 30, 2019
	(in millions)
Operating lease assets⁽¹⁾⁽⁴⁾	$	21
Finance lease assets⁽²⁾	10
Total lease assets	$	31

Operating leases⁽³⁾⁽⁴⁾
Current liability	$	11
Noncurrent liability	10
Total operating lease liability	$	21
Finance leases⁽³⁾
Current liability	$	2
Noncurrent liability	9
Total finance lease liability	$	11

Weighted average remaining lease term
Operating leases	4 years
Finance leases	4 years
Weighted average discount rate
Operating leases	9.24		%
Finance leases	26.52		%


(1)	Operating lease assets are reflected in Operating lease assets and other in our consolidated balance sheet as of September 30, 2019.


(2)	Finance lease assets are reflected in Other property, plant and equipment in our consolidated balance sheet as of September 30, 2019.

(3) Current and noncurrent operating and finance lease liabilities are reflected in Other accrued liabilities and Lease obligations and other, respectively, in our consolidated

balance sheet as of September 30, 2019.


(4)	Upon adoption of ASU 2016-02 effective January 1, 2019, we recognized operating leases of approximately $10 million. For the nine months ended September 30, 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 September 30, 2019, were as follows:



	Operating Leases			Finance Leases
	(in millions)
2019	$	3		$	1
2020	10			5
2021	3			5
2022	2			5
Thereafter	6			2
Total	$	24		$	18
Less: imputed interest	(3		)	(7		)
Present value of operating and finance lease obligations	$	21		$	11

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8. Incentive Compensation

Long-term Incentive Compensation

Our parent’s long-term incentive (LTI) programs consist of restricted stock, stock options, cash-based incentives and performance share units awards. Refer to our 2018 Annual Report on Form 10-K and on Form 10-K/A for further information regarding the terms and details of these awards. We record compensation expense on all of our parent’s LTI awards as general and administrative expense over the requisite service period. Pre-tax compensation expense related to all of our parent’s LTI awards (both equity and liability based), net of the impact of forfeitures, was approximately $2 million and $5 million for the quarters ended September 30, 2019 and 2018, respectively, and $7 million and $10 million for the nine months ended September 30, 2019 and 2018, respectively. As of September 30, 2019, we had unrecognized compensation expense of $13 million of which we will recognize $2 million during the remainder of 2019 and $11 million thereafter.

Restricted Stock. A summary of the changes in our parent’s non-vested restricted shares for the nine months ended September 30, 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	(1,114,001	)	$	4.95
Forfeited	(905,338	)	$	2.46
Non-vested at September 30, 2019	5,143,995		$	2.20

Performance Share Units. In 2018, we granted 618,720 performance share units (PSUs) to certain EP Energy employees. The grant date fair value of the 2018 awards was approximately $5 million as determined by a Monte Carlo simulation, utilizing an expected volatility of approximately 90% and a risk free rate of approximately 3%. As of September 30, 2019, we had a total of 1,480,260 PSUs outstanding. PSUs will vest over a weighted average period of three years and earned only upon the achievement of specified stock price goals. Our PSUs are treated as an equity award with the expense recognized on an accelerated basis over the life of the award.

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 September 30, 2019, our consolidated balance sheet reflects a deferred charge in the amount of approximately $15 million related to the KERP. For accounting purposes, deferred expense is being amortized over the 13 month term of the KERP agreement. During the quarter and nine months ended September 30, 2019, we recorded $5 million and $6 million, respectively, in expense related to the KERP.

9. Related Party Transactions

Chapter 11 Proceedings. As of September 30, 2019, affiliates of Apollo 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 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 September 30, 2019, affiliates of Access held approximately $48 million of our 1.5 Lien Notes. In connection with the Chapter 11 Cases, 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. For a discussion of the Chapter 11 Cases as well as the PSA, BCA and other agreements, refer to Note 1A.

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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). At September 30, 2019 and December 31, 2018, we had accounts receivable of $1 million and $47 million, respectively, and payables to our owner of $6 million and $20 million, respectively, associated with our Investor reflected in our consolidated balance sheets. Refer to our 2018 Annual Report on Form 10-K and on Form 10-K/A for further information on the joint venture agreement.

Taxes. We are party to a tax accrual policy with our parent whereby our parent files U.S. and certain state tax returns on our behalf. As of December 31, 2018, we had no state income tax payable due to our parent.

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Item 2. 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 1 of Part I of this Quarterly Report on Form 10-Q. This discussion contains forward-looking statements and involves numerous risks and uncertainties, including, but not limited to, those described in the “Risk Factors” section of this Quarterly Report on Form 10-Q and our 2018 Annual Report on Form 10-K. Actual results may differ materially from those contained in any forward-looking statements. Unless otherwise indicated or the context otherwise requires, references in this MD&A section to “we”, “our”, “us” and “the Company” refer to EP Energy LLC and each of its consolidated subsidiaries.

Our Business

Overview. We are an independent exploration and production company engaged in the acquisition and development of unconventional onshore oil and natural gas properties in the United States. We operate through a diverse base of producing assets through the development of our drilling inventory located in three areas: the Eagle Ford Shale in South Texas, Northeastern Utah (NEU) in the Uinta basin, and the Permian basin in West Texas.

Recent Developments - Chapter 11 Proceedings. On October 3, 2019, the Debtors filed the Chapter 11 Cases in the Bankruptcy Court seeking relief under the Bankruptcy Code. We expect to continue operations in the normal course during the pendency of the Chapter 11 Cases. To ensure ordinary course operations, the Debtors have 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 have received authority to use cash collateral of the lenders under the Reserve-Based Loan Facility (RBL Facility). For a further discussion of the Chapter 11 Cases and related matters, see Liquidity and Capital Resources and Part I, Item 1, Financial Statements, Notes 1A, 6 and 7.

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

We are party to a drilling joint venture agreement in the Eagle Ford with a total anticipated joint venture investment of $225 million. As of the second quarter 2019, we had drilled and completed all wells under the amended agreement. Additionally, subject to certain time limits, we will provide our joint venture partner the option to participate in additional wells in the development areas. For a further discussion on this joint venture, see Part I, Item 1, Financial Statements, Note 9. In NEU, we are also party to a drilling joint venture agreement under which our joint venture partner is participating in the development of 53 wells. As of September 30, 2019, we have drilled and completed 51 wells under the NEU joint venture agreement.

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 long-term profitability will 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


•	managing debt levels and related interest costs.

In addition to these factors, our future 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

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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. While prices have generally stabilized over recent years, 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 commodities 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 or 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 September 30, 2019.



	2019				2020
	Volumes⁽¹⁾	Average Price⁽¹⁾			Volumes⁽¹⁾	Average Price⁽¹⁾
Oil
Collars
Ceiling - WTI	368	$	69.78		—	$	—
Floors - WTI	368	$	57.50		—	$	—
Three Way Collars
Ceiling - WTI	3,036	$	66.01		11,712	$	65.11
Floors - WTI	3,036	$	55.76		11,712	$	55.90
Sub-Floor - WTI	3,036	$	45.00		11,712	$	45.00
Basis Swaps
Midland vs. Cushing⁽²⁾	368	$	(5.23	)	1,464	$	0.46
NYMEX Roll⁽³⁾	184	$	0.25		—	$	—
Natural Gas
Fixed Price Swaps	3	$	3.01		—	$	—
Collars
Ceiling	3	$	4.26		—	$	—
Floors	3	$	2.75		—	$	—


(1)	Volumes presented are MBbls for oil and TBtu for natural gas. Prices presented are per Bbl of oil and MMBtu of natural gas.


(2)	EP Energy receives Cushing plus the basis spread listed and pays Midland.

(3)

These positions hedge the timing risk associated with our physical sales. We generally sell oil for the delivery month at a sales price based on the average NYMEX WTI price during that month, plus an adjustment calculated as a spread between the weighted average prices of the delivery month, the next month and the following month during the period when the delivery month is prompt (the “trade month roll”).


(4)	EP Energy receives Henry Hub plus the basis spread listed and pays WAHA.

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 $10.76 in 2019 and $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 September 30, 2019, the average forward price of oil was $53.84 per barrel of oil for the remainder of 2019 and $51.46 per barrel of oil for 2020.

During the nine months ended September 30, 2019, we settled commodity index hedges on approximately 98% of our oil production, 74% of our total liquids production and 62% of our natural gas production at average floor prices of $55.93 per

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barrel of oil and $2.86 per MMBtu of natural gas, respectively. As of September 30, 2019, approximately 100% of our future crude oil contracts allow for upside participation (to a weighted average price of approximately $66.41 per barrel for 2019 and $65.11 per barrel for 2020) while containing certain 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.

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Liquidity and Capital Resources

Overview. As of September 30, 2019, our primary sources of liquidity are cash generated by our operations and borrowings under our RBL Facility which matures in 2021. Our primary uses of cash are capital expenditures, debt service, including interest, and working capital requirements. As of September 30, 2019, our available liquidity was $188 million.

Chapter 11 Proceedings. 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.

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 it 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 with the Noteholders and 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 in respect of the failure to make the $40 million cash interest payment. The forbearance period was subsequently extended until October 3, 2019, at which time the Debtors filed the Chapter 11 Cases in the Bankruptcy Court seeking relief under 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 the Plan premised on (i) the equity rights offering of up to $475 million (the “Rights Offering”), $463 million of which is backstopped by the Commitment Parties, and (ii) an approximately $629 million exit facility for which, as of October 18, 2019, over 90% of the lenders under the RBL Facility have committed to provide support, and which the RBL Facility and proposed DIP Facility (as defined below) will convert into on the effective date of the Plan.

As part of the restructuring, the Company may also consummate a private placement of New Common Shares, subject to dilution by the Jeter Shares and EIP Shares, for an aggregate purchase price of up to $75 million, in cash, on terms acceptable to the Company and Initial Supporting Noteholders. In addition, Apollo and Access may contribute their equity interests in Wolfcamp Drillco Operating L.P. to the Reorganized Debtors in exchange for the Jeter Shares, subject to the agreement of the Company, Access, and the Initial Supporting Noteholders.

As more fully disclosed in Part I, Item 1, Financial Statements, Note 1A, the PSA contemplates a Plan which would provide for the treatment of holders of certain claims and existing equity interests. The Plan will also provide for the establishment of a post-emergence employee incentive plan on the effective date of the Plan.

In connection with the PSA and the Chapter 11 Cases, the Debtors have received an underwritten commitment from certain of the lenders under the RBL Facility to provide (i) for the for an approximately $315 million Senior Secured Superpriority Debtor-in-Possession Facility, and (ii) support for the $629 million Senior Secured Revolving Exit Facility, arranged by J.P. Morgan Chase Bank, N.A. The DIP Facility is intended to be utilized prior to the Debtors’ emergence from the Chapter 11 Cases. The Exit Facility is anticipated to be effective upon the Debtors’ emergence from the Chapter 11 Cases. The proceeds of the Exit Facility may be used to fund distributions under the Plan, for working capital and for other general corporate purposes, to issue letters of credit, for transaction fees and expenses and for fees related to the Debtors’ emergence from the Chapter 11 Cases. The DIP Facility and the Exit Facility are each subject to customary closing conditions, and Bankruptcy Court approval.

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We expect to continue operations in the normal course during the pendency of the Chapter 11 Cases. To ensure ordinary course operations, the Debtors have 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 have received authority to use cash collateral of the lenders under the RBL Facility.

However, for the duration of the Chapter 11 proceedings, our operations and our ability to develop and execute our business plan are subject to a high degree of risk and uncertainty associated with the Chapter 11 proceedings. The outcome of the Chapter 11 is dependent upon factors that are outside of the Company’s control, including actions of the Bankruptcy Court and the Company’s creditors. The significant risks and uncertainties related to the Company’s liquidity and Chapter 11 proceedings described above raise substantial doubt about the Company’s ability to continue as a going concern. There can be no assurance that we will confirm and consummate the Plan under the PSA or complete another plan of reorganization with respect to the Chapter 11 proceedings.

For a further discussion of all Chapter 11 related matters, including, but not limited to the PSA, BCA, DIP Facility, and Exit Facility, see Part I, Item 1, Financial Statements, Note 1A.

Capital Expenditures. Our capital expenditures and average drilling rigs by area for the nine months ended September 30, 2019 were:



	Capital Expenditures⁽¹⁾ (in millions)		Average Drilling Rigs
Eagle Ford Shale	$	348	2.3
Northeastern Utah	92		1.6
Permian	4		—
Total	$	444	3.9
Acquisition capital	$	18
Total Capital Expenditures	$	462


(1)	Represents accrual-based capital expenditures.

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Overview of Cash Flow Activities. Our cash flows are summarized as follows (in millions):



	Nine months ended September 30,
	2019			2018
Cash Inflows
Operating activities
Net loss	$	(810	)	$	(84	)
Gain on sale of assets	—			(1		)
Gain on extinguishment/modification of debt	(10		)	(48		)
Write-off of debt discount and deferred issue costs	90			—
Other income adjustments	782			398
Changes in assets and liabilities	97			105
Total cash flow from operations	149			370


Investing activities
Proceeds from the sale of assets	—			175
Cash inflows from investing activities	—			175

Financing activities
Proceeds from issuance of long-term debt	923			1,805
Contributions from parent	—			9
Cash inflows from financing activities	923			1,814

Total cash inflows	$	1,072		$	2,359

Cash Outflows
Investing activities
Capital expenditures	$	422		$	559
Cash paid for acquisitions	18			275
Cash outflows from investing activities	440			834

Financing activities
Repayments and repurchases of long-term debt	468			1,431
Fees/costs on debt exchange	—			62
Debt issue costs	—			21
Other	2			—
Cash outflows from financing activities	470			1,514

Total cash outflows	$	910		$	2,348

Net change in cash, cash equivalents and restricted cash	$	162		$	11

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Production Volumes and Drilling Summary

Production Volumes. Below is an analysis of our production volumes for the nine months ended September 30:



	2019	2018
Equivalent Volumes (MBoe/d)
Eagle Ford	32.9	37.0
Northeastern Utah	15.5	17.2
Permian	21.6	26.8
Total	70.0	81.0

Oil (MBbls/d)
Eagle Ford	21.8	25.2
Northeastern Utah	10.1	11.8
Permian	6.4	9.4
Total	38.3	46.4

Natural Gas (MMcf/d)
Eagle Ford⁽¹⁾	33	35
Northeastern Utah	32	32
Permian	48	56
Total	113	123

NGLs (MBbls/d)
Eagle Ford	5.6	6.0
Northeastern Utah	—	—
Permian	7.2	8.1
Total	12.8	14.1


(1)	Production volume excludes 22 MMcf/d of reinjected gas volumes used in operations during the nine months ended September 30, 2019.

Production Summary. For the nine months ended September 30, 2019 compared to the same period in 2018, (i) Eagle Ford equivalent volumes decreased 4.1 MBoe/d or (approximately 11%) due to fewer wells placed on production in the second half of 2018 through 2019, (ii) NEU equivalent volumes decreased 1.7 MBoe/d or (approximately 10%) due to reduced drilling activity in 2019, and (iii) Permian equivalent volumes decreased 5.2 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 the nine months ended September 30, 2019, we (i) frac’d (wells fracture stimulated) 54 gross wells in the Eagle Ford, all of which came online for a total of 847 net operated wells, and (ii) frac’d 11 gross wells in NEU, 10 of which came online for a total of 345 net operated wells. We did not frac any wells in the Permian during the nine months ended September 30, 2019, and currently operate 353 net wells in the area. As of September 30, 2019, we also had a total of 39 gross wells in progress, of which 37 were drilled, but not completed across our programs.

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Results of Operations

The information in the table below provides a summary of our financial results.



	Quarter ended September 30,						Nine months ended September 30,
	2019			2018			2019			2018
	(in millions)
Operating revenues
Oil	$	193		$	287		$	590		$	820
Natural gas	10			15			36			55
NGLs	12			36			45			92
Total physical sales	215			338			671			967
Financial derivatives	32			(44		)	(34		)	(122		)
Total operating revenues	247			294			637			845

Operating expenses
Oil and natural gas purchases	—			3			—			3
Transportation costs	23			25			71			76
Lease operating expense	34			46			101			123
General and administrative	38			21			102			68
Depreciation, depletion and amortization	116			127			304			376
Gain on sale of assets	—			(1		)	—			(1		)
Impairment charges	458			—			458			—
Exploration and other expense	1			2			3			3
Taxes, other than income taxes	12			22			43			63
Total operating expenses	682			245			1,082			711

Operating (loss) income	(435		)	49			(445		)	134
Other income	4			2			4			2
Gain on extinguishment/modification of debt	—			—			10			48
Interest expense	(189		)	(95		)	(379		)	(268		)
Loss before income taxes	(620		)	(44		)	(810		)	(84		)
Income tax expense	—			—			—			—
Net loss	$	(620	)	$	(44	)	$	(810	)	$	(84	)

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Operating Revenues

The table below provides our operating revenues, volumes and prices per unit for the quarters and nine months ended September 30, 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.



	Quarter ended September 30,					Nine months ended September 30,
	2019		2018			2019			2018
	(in millions)
Operating revenues:
Oil	$	193	$	287		$	590		$	820
Natural gas	10		15			36			55
NGLs	12		36			45			92
Total physical sales	215		338			671			967
Financial derivatives	32		(44		)	(34		)	(122		)
Total operating revenues	$	247	$	294		$	637		$	845

Volumes:
Oil (MBbls)	3,487		4,262			10,457			12,648
Natural gas (MMcf)	9,654		11,121			30,931			33,730
NGLs (MBbls)	1,090		1,285			3,518			3,851
Equivalent volumes (MBoe)	6,186		7,401			19,130			22,121
Total MBoe/d	67.2		80.4			70.0			81.0

Prices per unit⁽¹⁾:
Oil
Average realized price on physical sales ($/Bbl)⁽²⁾	$	55.25	$	66.61		$	56.40		$	64.61
Average realized price, including financial derivatives ($/Bbl)⁽²⁾⁽³⁾	$	55.50	$	63.37		$	57.10		$	61.55
Natural gas
Average realized price on physical sales ($/Mcf)⁽²⁾	$	1.04	$	1.34		$	1.16		$	1.62
Average realized price, including financial derivatives ($/Mcf)⁽²⁾⁽³⁾	$	1.74	$	1.69		$	1.62		$	1.89
NGLs
Average realized price on physical sales ($/Bbl)	$	10.98	$	27.74		$	12.93		$	23.80
Average realized price, including financial derivatives ($/Bbl)⁽³⁾	$	10.98	$	24.79		$	12.93		$	22.60

(1)

For the quarter and nine months ended September 30, 2019, there were no oil purchases associated with managing our physical oil sales. For both the quarter and nine months ended September 30, 2018, oil prices reflect operating revenues for oil reduced by $3 million for oil purchases associated with managing our physical oil sales. Natural gas prices for both the quarters and nine months ended September 30, 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 quarters ended September 30, 2019 and 2018, include cash received of approximately $1 million and cash paid of approximately $14 million, respectively, for the settlement of crude oil derivative contracts and approximately $7 million and $4 million of cash received, respectively, for the settlement of natural gas financial derivatives. The nine months ended September 30, 2019 and 2018, include cash received of approximately $7 million and cash paid of approximately $39 million, respectively, for the settlement of crude oil derivative contracts and approximately $14 million and $9 million of cash received, respectively, for the settlement of natural gas financial derivatives. The quarter and nine months ended September 30, 2018 also include $4 million and $5 million, respectively, of cash paid for the settlement of NGLs derivative contracts.

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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 quarter and nine months ended September 30, 2019 and 2018.



	Quarter ended
	Oil			Natural gas			NGLs			Total
	(in millions)
September 30, 2018 sales	$	287		$	15		$	36		$	338
Change due to prices	(42		)	(3		)	(18		)	(63		)
Change due to volumes	(52		)	(2		)	(6		)	(60		)
September 30, 2019 sales	$	193		$	10		$	12		$	215



	Nine months ended
	Oil			Natural gas			NGLs			Total
	(in millions)
September 30, 2018 sales	$	820		$	55		$	92		$	967
Change due to prices	(88		)	(14		)	(39		)	(141		)
Change due to volumes	(142		)	(5		)	(8		)	(155		)
September 30, 2019 sales	$	590		$	36		$	45		$	671

Oil sales for the quarter and nine months ended September 30, 2019, compared to the same periods in 2018, decreased by $94 million (33%) and $230 million (28)%, respectively, due primarily to lower oil prices and production in all areas reflecting lower capital spending in 2019.

Natural gas sales decreased by $5 million (33%) and $19 million (35)%, respectively, for the quarter and nine months ended September 30, 2019 compared to the same periods in 2018 primarily due to lower natural gas prices and lower production primarily 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 regional basis differentials, 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.



	Quarter ended September 30,
	2019						2018
	Oil (Bbl)			Natural gas (MMBtu)			Oil (Bbl)			Natural gas (MMBtu)
Differentials and deducts	$	(0.82	)	$	(1.21	)	$	(2.67	)	$	(1.39	)
NYMEX	$	56.45		$	2.23		$	69.50		$	2.91
Net back realization %	98.5		%	45.7		%	96.2		%	52.2		%



	Nine months ended September 30,
	2019						2018
	Oil (Bbl)			Natural gas (MMBtu)			Oil (Bbl)			Natural gas (MMBtu)
Differentials and deducts	$	(0.73	)	$	(1.48	)	$	(1.99	)	$	(1.17	)
NYMEX	$	57.06		$	2.67		$	66.75		$	2.90
Net back realization %	98.7		%	44.6		%	97.0		%	59.7		%

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The oil realization percentages for the quarter and nine months ended September 30, 2019 were higher as compared to the same periods in 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 for the quarter and nine months ended September 30, 2019 were primarily a result of weaker Permian basin natural gas pricing.

NGLs sales decreased by $24 million (67%) and $47 million (51)%, respectively, for the quarter and nine months ended September 30, 2019 compared with the same periods in 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 prices, our level of hedging, our capital expenditures, our ability to maintain or grow oil volumes and by the location of our production and the nature of our sales contracts. See Our Business and Liquidity and Capital Resources for further information on our derivative instruments.

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 quarters ended September 30, 2019 and 2018, we recorded $32 million and $44 million of derivative gains and losses, respectively. For the nine months ended September 30, 2019 and 2018, we recorded $34 million and $122 million of derivative losses, respectively.

Operating Expenses

The table below provides our operating expenses, volumes and operating expenses per unit for each of the periods presented:



	Quarter ended September 30,
	2019				2018
	Total		Per Unit⁽¹⁾		Total			Per Unit⁽¹⁾
	(in millions, except per unit costs)
Operating expenses
Oil and natural gas purchases	$	—	$	—	$	3		$	0.36
Transportation costs	23		3.69		25			3.41
Lease operating expense	34		5.54		46			6.16
General and administrative⁽²⁾	38		6.09		21			2.91
Depreciation, depletion and amortization	116		18.62		127			17.11
Gain on sale of assets	—		—		(1		)	(0.13		)
Impairment charges	458		74.10		—			—
Exploration and other expense	1		0.12		2			0.29
Taxes, other than income taxes	12		1.98		22			3.02
Total operating expenses	$	682	$	110.14	$	245		$	33.13

Total equivalent volumes (MBoe)	6,186				7,401

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	Nine months ended September 30,
	2019				2018
	Total		Per Unit⁽¹⁾		Total			Per Unit⁽¹⁾
	(in millions, except per unit costs)
Operating expenses
Oil and natural gas purchases	$	—	$	—	$	3		$	0.13
Transportation costs	71		3.70		76			3.44
Lease operating expense	101		5.30		123			5.53
General and administrative⁽²⁾	102		5.31		68			3.09
Depreciation, depletion and amortization	304		15.89		376			17.00
Gain on sale of assets	—		—		(1		)	(0.07		)
Impairment charges	458		23.96		—			—
Exploration and other expense	3		0.10		3			0.14
Taxes, other than income taxes	43		2.25		63			2.86
Total operating expenses	$	1,082	$	56.51	$	711		$	32.12

Total equivalent volumes (MBoe)	19,130				22,121


(1)	Per unit costs are based on actual amounts rather than the rounded totals presented.

(2)

For the quarter and nine months ended September 30, 2019, amount includes approximately $6 million or $1.02 per Boe and $13 million or $0.68 per Boe, respectively, of incentive compensation expense, and $15 million or $2.53 per Boe and $19 million or $1.00 per Boe, respectively, of transition, severance and other costs. For the nine months ended September 30, 2019, amount also includes approximately $1 million or $0.02 per Boe of fees paid to Sponsors and $24 million or $1.25 per Boe of legacy litigation accruals and settlements. For the quarter and nine months ended September 30, 2018, amount includes approximately $5 million or $0.70 per Boe and $9 million or $0.44 per Boe, respectively, of incentive compensation expense and approximately $1 million or $0.16 per Boe and $7 million or $0.32 per Boe, respectively, of transition, severance and other costs.

Transportation costs. Transportation costs for the quarter and nine months ended September 30, 2019 decreased by $2 million, and $5 million, respectively, compared to the same periods in 2018 as a result of (i) lower fees associated with revised transportation agreements in the Permian in 2019, and (ii) an increase in wells drilled with our drilling joint venture partner in the Eagle Ford in 2019 (see Part I, Item 1, Financial Statements, Note 9).

Lease operating expense. Lease operating expense decreased by $12 million and $22 million for the quarter and nine months ended September 30, 2019, respectively, compared to the same periods in 2018. The decrease for the quarter ended September 30, 2019 compared to 2018 is due primarily to lower disposal and chemical costs in the Eagle Ford and Permian and lower maintenance costs in the Eagle Ford. The decrease for the year ended September 30, 2019 compared to 2018 is due primarily to lower disposal and maintenance costs in the Eagle Ford and Permian and lower chemical costs in the Permian.

General and administrative expenses. General and administrative expenses for the quarter and nine months ended September 30, 2019 increased by $17 million and $34 million, respectively, compared to the same periods in 2018. Higher costs during the quarter and nine months ended September 30, 2019 compared to the same periods in 2018 were primarily due to higher professional and legal fees of $15 million and $18 million, respectively, related to legal and financial advisory fees associated with bankruptcy related matters prior to our Chapter 11 filing. Also impacting the nine months ended September 30, 2019 was an accrual of $21 million related to legacy legal matters (see Part 1, Item 1, Financial Statements, Note 7) offset by $6 million in lower severance costs.

Depreciation, depletion and amortization expense. Depreciation, depletion and amortization expense decreased for the quarter and nine months ended September 30, 2019 primarily due to a non-cash impairment charge recorded in the fourth quarter of 2018 on our proved properties in the Permian, decreased capital spending and lower production volumes when compared to the same periods in 2018. 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 quarter and nine months ended September 30 were:

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	Quarter ended September 30,				Nine months ended September 30,
	2019		2018		2019		2018
Depreciation, depletion and amortization ($/Boe)	$	18.62	$	17.11	$	15.89	$	17.00

Impairment charges. For both the quarter and nine months ended September 30, 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 I, Item 1, Financial Statements, Note 1A) and the uncertainties surrounding the availability of financing needed to develop our proved undeveloped reserves. See Part I, Item 1, Financial Statements, Note 2, for more information on impairment.

Taxes, other than income taxes. Taxes, other than income taxes, for the quarter and nine months ended September 30, 2019, decreased by $10 million and $20 million, respectively, compared to the same periods in 2018, 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 on extinguishment/modification of debt. During the nine months ended September 30, 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.

During the nine months ended September 30, 2018, we recorded a total gain on extinguishment of debt of $48 million primarily as a result of exchanging certain senior unsecured notes for approximately $1.1 billion in new 1.5 Lien Notes due 2024. See Part 1, Item 1, Financial Statements, Note 6 for more information on our long-term debt.

Interest expense. Interest expense for the quarter and year ended September 30, 2019 increased by $94 million and $111 million, respectively, compared to the same periods in 2018 due to reclassifying our debt as current and writing off approximately $90 million in unamortized debt discount and debt issue costs as a result of uncertainties regarding default, event of default and cross-default provisions under our indentures and RBL Facility (including those discussed in Part 1, Item 1, Financial Statements, Note 1A). Also impacting interest expense for the nine months ended September 30, 2019 was the issuance of our senior secured notes due 2026 in May 2018, partially offset by lower average borrowings under our RBL Facility and the repurchases of a portion of our senior unsecured notes due 2020, 2022 and 2023.

Income taxes. For both the quarters and nine months ended September 30, 2019 and 2018, our effective tax rates were 0%. Our effective tax rates in 2019 and 2018 differed from the statutory rate of 21% primarily as a result of our recognition of a full valuation allowance on our net deferred tax assets. In addition, we recorded adjustments to the valuation allowance on our net deferred tax assets, which offset deferred income tax benefits by $135 million and $10 million, for the quarters ended September 30, 2019 and 2018, respectively, and by $174 million and $18 million for the nine months ended September 30, 2019 and 2018, respectively.

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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 long-term incentive programs), transition, severance and other costs that affect comparability, management and other fees paid to 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 (loss) income to EBITDAX and Adjusted EBITDAX:



	Quarter ended September 30,						Nine months ended September 30,
	2019			2018			2019			2018
	(in millions)
Net loss	$	(620	)	$	(44	)	$	(810	)	$	(84	)
Income tax expense	—			—			—			—
Interest expense, net of capitalized interest⁽¹⁾	189			95			379			268
Depreciation, depletion and amortization	116			127			304			376
Exploration expense	1			1			3			3
EBITDAX	(314		)	179			(124		)	563
Mark-to-market on financial derivatives⁽²⁾	(32		)	44			34			122
Cash settlements and cash premiums on financial derivatives⁽³⁾	8			(14		)	22			(34		)
Incentive compensation expense⁽⁴⁾	6			5			13			9
Transition, severance and other costs	15			1			19			7
Fees paid to Sponsors	—			—			1			—
Legacy litigation settlements⁽⁵⁾	—			—			24			—
Gain on sale of assets	—			(1		)	—			(1		)
Gain on extinguishment/modification of debt	—			—			(10		)	(48		)
Impairment charges	458			—			458			—
Adjusted EBITDAX	$	141		$	214		$	437		$	618


(1)	Includes approximately $90 million at September 30, 2019 related to the write-off of unamortized debt discount and debt issue costs 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 (including those discussed in Part 1, Item 1, Financial Statements, Note 1A).


(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 quarters and nine months ended September 30, 2019 and 2018.


(4)	For the quarter and nine months ended September 30, 2019, incentive compensation expense includes $5 million and $6 million, respectively, in amounts under the Key Employee Retention Program, "KERP", in lieu of long-term incentive compensation. For additional details on the KERP, see Part I, Item 1, Financial Statements, Note 8.


(5)	Reflects amounts accrued related to Fairfield and Weyerhaeuser legal cases. For additional details on our legacy legal matters, see Part I, Item 1, Financial Statements, Note 7.

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Commitments and Contingencies

For a further discussion of our commitments and contingencies, see Part I, Item 1, Financial Statements, Note 7.

Item 3. Qualitative, Quantitative and Disclosures About Market Risk

This information updates, and should be read in conjunction with the information disclosed in our 2018 Annual Report on Form 10-K, in addition to the information presented in Items 1 and 2 of Part I of this Quarterly Report on Form 10-Q. There have been no material changes in our quantitative and qualitative disclosures about market risks from those reported in our 2018 Annual Report on Form 10-K, except as presented below:

Commodity Price Risk

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 September 30, 2019:



			Oil, Natural Gas and NGLs Derivatives
			10 Percent Increase					10 Percent Decrease
	Fair Value		Fair Value		Change			Fair Value		Change
					(in millions)
Price impact⁽¹⁾	$	58	$	16	$	(42	)	$	99	$	41



			Oil, Natural Gas and NGLs Derivatives
			1 Percent Increase					1 Percent Decrease
	Fair Value		Fair Value		Change			Fair Value		Change
					(in millions)
Discount rate⁽²⁾	$	58	$	58	$	—		$	58	$	—
Credit rate⁽³⁾	$	58	$	57	$	(1	)	$	58	$	—


(1)	Presents the hypothetical sensitivity of our commodity-based derivatives to changes in fair values arising from changes in oil, natural gas and NGLs 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.

Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

As of September 30, 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 Securities Exchange Act of 1934, as amended (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 September 30, 2019.

Changes in Internal Control over Financial Reporting

There were no changes in EP Energy LLC’s internal control over financial reporting during the three months ended September 30, 2019 that materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

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PART II — OTHER INFORMATION

Item 1. Legal Proceedings

The information contained in Note 7 of the notes to the condensed consolidated financial statements under the headings “Chapter 11 Cases” and “Legal Matters” are incorporated herein by reference.

Item 1A. Risk Factors

You should carefully consider the risks described in Part I, Item 1A of our 2018 Annual Report on Form 10-K, as well as the other information discussed herein, including the risk factors below. Our business, financial condition and results of operations could be adversely affected by any of the risks and uncertainties described. There have been no material changes from the risk factors disclosed in Part I, Item 1A, in our 2018 Annual Report on Form 10-K other than as disclosed below.

We are subject to risks and uncertainties associated with the Chapter 11 Cases filed with the Bankruptcy Court on October 3, 2019.

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 execute, confirm and consummate the Plan or another plan of reorganization with respect to the Chapter 11 proceedings; 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 proceedings to Chapter 7 proceedings; and the actions and decisions of our creditors and other third parties who have interests in our Chapter 11 proceedings that may be inconsistent with our operational and strategic plans.

Delays in our Chapter 11 proceedings 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 proceedings could adversely affect our relationships with our lenders, counterparties, employees and other third parties, which in turn could adversely affect our operations and financial condition. Also, we need the prior approval of the Bankruptcy Court for transactions outside the ordinary course of business, which may limit our ability to respond timely to certain events or take advantage of certain opportunities. Because of the risks and uncertainties associated with our Chapter 11 proceedings, we cannot accurately predict or quantify the ultimate impact of events that occur during our Chapter 11 proceedings that may be inconsistent with our plans.

Even if the restructuring transactions are 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 that the proposed financial restructuring will achieve our stated goals nor can we give any assurance of our ability to continue as a going concern.

We are also evaluating the impact of becoming a privately held company after emergence from the Chapter 11 Cases, which would result in less disclosure about us and may negatively affect our ability to raise additional funds, the ability of our stockholders to sell our securities, and the liquidity and trading prices of our preferred stock, common stock and warrants.

The PSA is subject to significant conditions and milestones that may be beyond our control and may be difficult for us to satisfy. If the PSA is terminated, our ability to confirm and consummate the Plan, and our ability to consummate any restructuring of our debt, could be materially and adversely affected.

The PSA sets forth certain conditions and milestones we must satisfy, including the timely satisfaction of conditions and milestones to consummate a Chapter 11 plan. Our ability to timely satisfy such conditions and milestones is subject to risks and uncertainties that, in certain instances, are beyond our control. The PSA gives the Supporting Noteholders the ability to terminate the PSA under certain circumstances, including the failure of certain conditions or milestones being satisfied. Should the PSA be terminated, all obligations of the parties to the PSA will terminate (except as expressly provided in the PSA). A termination of the PSA may result in the loss of support for the Plan, which could adversely affect our ability to confirm and consummate the Plan and our ability to emerge from Chapter 11. If the Plan is not consummated, there can be no assurance that any new plan would be as favorable to holders of claims or interests as the Plan, and our Chapter 11 proceedings could become protracted, which could significantly and detrimentally impact our relationships with regulators, government agencies, vendors, suppliers, employees and major customers.

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There can be no assurance that the solicited classes of claims will vote to accept the Plan.

There can be no assurance that the Plan will receive the necessary level of support to be implemented or will be approved by the Bankruptcy Court. The success of the restructuring transactions will depend on the willingness of certain existing creditors to agree to the exchange or modification of their claims and approval by the Bankruptcy Court, and there can be no guarantee of success with respect to those matters. Holders of RBL Claims, 1.5L Notes Claims, Unsecured Claims, and Existing Equity Interests (each as defined in the PSA) are impaired under the Plan and entitled to vote to accept or reject the Plan. Although certain Supporting Noteholders are bound to vote for the Plan pursuant to the PSA, if the PSA is terminated they will not be so bound and any vote or consent given by such Supporting Noteholders prior to such termination may, upon written notice, be revoked, null and void ab initio.

We may receive objections to the terms of the transactions contemplated by the PSA, including official objections to confirmation of the Plan from the various stakeholders in the Chapter 11 Cases. We cannot predict the impact that any objection or third party motion may have on the Bankruptcy Court’s decision to confirm the Plan or our ability to complete an in-court restructuring as contemplated by the PSA or otherwise. Any objection may cause us to devote significant resources in response which could materially and adversely affect our business, financial condition and results of operations.

If we do not receive sufficient support for the Plan, or if the Plan is not confirmed by the Bankruptcy Court, it is unclear what, if any, distributions holders of claims against us would ultimately receive with respect to their claims and interests. There can be no assurance as to whether or when we will emerge from Chapter 11. If no plan of reorganization can be confirmed, or if the Bankruptcy Court otherwise finds that it would be in the best interest of holders of claims and interests, the Chapter 11 Cases may be converted to a case under Chapter 7 of the Bankruptcy Code, pursuant to which a trustee would be appointed or elected to liquidate our assets for distribution in accordance with the priorities established by the Bankruptcy Code.

The pursuit of the restructuring transactions under the PSA will consume a substantial portion of the time and attention of our management, which may have an adverse effect on our business and results of operations, and we may face increased levels of employee attrition.

Although the PSA and transactions contemplated therein are designed to minimize the length of our Chapter 11 proceedings, it is impossible to predict with certainty the amount of time and resources necessary to successfully implement the restructuring transactions. Compliance with the terms of the PSA and Backstop Agreement will involve additional expense and our management will be required to spend a significant amount of time and effort focusing on the proposed transactions. This diversion of attention may materially adversely affect the conduct of our business, and, as a result, our financial condition and results of operations, particularly if the Chapter 11 proceedings are protracted.

Furthermore, during the pendency of the Chapter 11 proceedings, our employees will face considerable distraction and uncertainty and we may experience increased levels of employee attrition. A loss of key personnel or material erosion of employee morale has negatively impacted and could have a material adverse effect on our ability to effectively, efficiently and safely conduct our business, and could impair our ability to execute our strategy and implement operational initiatives, thereby having a material adverse effect on our business and on our financial condition and results of operations.

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.

The inability to effectuate the restructuring transactions could have a material adverse effect on the Company.

If a plan of reorganization is not confirmed and we are unable to effectuate the restructuring transactions as contemplated by the PSA, the adverse pressures we have recently experienced are expected to continue and potentially intensify, and could have a material adverse effect on our business, prospects, results of operations, liquidity and financial condition including with respect to our:


•	relationships with counterparties and key stakeholders who are critical to our business;


•	ability to access the capital markets;


•	ability to execute on our operational and strategic goals;


•	ability to recruit and/or retain key personnel; and


•	business, prospects, results of operations and liquidity generally.

Upon our emergence from bankruptcy, the composition of our Board may change significantly.

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Under the Plan, the composition of our Board may change significantly. Any new directors are likely to have different backgrounds, experiences and perspectives from those individuals who previously served on the Board and, thus, may have different views on the issues that will determine our future. As a result, our future strategy and plans may differ materially from those of the past.

In certain instances, a Chapter 11 case may be converted to a case under Chapter 7 of the Bankruptcy Code.

Upon a showing of cause, the Bankruptcy Court may convert our Chapter 11 Cases to a case under Chapter 7 of the Bankruptcy Code. In such event, a Chapter 7 trustee would be appointed or elected to liquidate our assets for distribution in accordance with the priorities established by the Bankruptcy Code. Liquidation under Chapter 7 would result in significantly smaller distributions being made to our creditors than those provided for in the Plan because of (i) the likelihood that the assets would have to be sold or otherwise disposed of in a distressed fashion over a short period of time rather than in a controlled manner and as a going concern, (ii) additional administrative expenses involved in the appointment of a Chapter 7 trustee, and (iii) additional expenses and claims, some of which would be entitled to priority, that would be generated during the liquidation and from the rejection of leases and other executory contracts in connection with a cessation of operations.

We may be subject to claims that will not be discharged in the Chapter 11 proceedings, which could have a material adverse effect on our financial condition and results of operations.

The Bankruptcy Code provides that the confirmation of a plan of reorganization discharges a debtor from substantially all debts arising prior to confirmation. With certain exceptions, all claims that arose prior to confirmation of the plan of reorganization (i) would be subject to compromise and/or treatment under the plan of reorganization and/or (ii) would be discharged in accordance with the Bankruptcy Code and the terms of the plan of reorganization. Any claims not ultimately discharged through a plan of reorganization could be asserted against the reorganized entities and may have an adverse effect on our financial condition and results of operations on a post-reorganization basis.

The Plan and any other plan of reorganization that we may implement will be based in large part upon assumptions, projections and analyses developed by us. If these assumptions, projections and analyses prove to be incorrect in any material respect, the Plan may not be successfully implemented.

The Plan or any other plan of reorganization that we may implement will have been based in important part on assumptions and analyses based on our experience and perception of historical trends, current conditions and expected future developments, as well as other factors that we have considered appropriate under the circumstances. Whether actual future results and developments will be consistent with our expectations and assumptions depends on a number of factors, including but not limited to (i) our ability to change substantially our capital structure; (ii) our ability to maintain customers’ confidence in our viability as a continuing entity and to attract and retain sufficient business from them; (iii) our ability to retain key employees; and (iv) the overall strength and stability of general economic conditions of the oil and natural gas industry. The failure of any of these factors could materially adversely affect the successful reorganization of our businesses.

Transfers of our equity, or issuances of equity in connection with our Chapter 11 proceedings, may impair our ability to utilize our federal income tax net operating loss carryforwards and other tax attributes during the current year and in future years.

Under federal income tax law, a corporation is generally permitted to offset 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. If we experienced an “ownership change” or if we do experience an “ownership change” during or in connection with the restructuring process, as defined in section 382 of the Internal Revenue Code, then our ability to use our net operating loss carryforwards and other tax attributes may be substantially limited, which could have a negative impact on our financial position and results of operations. In addition, the Internal Revenue Service recently proposed regulations that, depending on the rules ultimately adopted, could further substantially limit our ability to utilize our tax attributes. Generally, there is an “ownership change” 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 would impair our ability to utilize our net operating loss carryforwards and other tax attributes. 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 the Plan.

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Whether or not the net operating loss carryforwards and other tax attributes are subject to limitation under section 382, our net operating losses and possibly other tax attributes are expected to be reduced by the amount of discharge of indebtedness arising in our Chapter 11 Cases under section 108 of the Internal Revenue Code. In addition, if implementation of the Plan results in an “ownership change” (as currently expected), our ability to utilize our net operating loss carryforwards and other tax attributes could be severely restricted, the magnitude of which depends on, among other things, the application of special tax law rules under section 382(l)(6) and (if applicable) section 382(l)(5) for an “ownership change” that occurs as part of a chapter 11 plan and any change in the applicable limitation rules as referenced above. With respect to the application of section 382(l)(5), the Plan contemplated under the PSA is not premised on qualification for or utilization of section 382(l)(5).

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. If the Plan contemplated thereto is confirmed by the Bankruptcy Court, the equity ownership of the Company would change significantly.

Additionally, the Sponsors and other legacy investors 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’ and other investors’ interests in other portfolio companies could impact our ability to pursue acquisition opportunities. 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 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 expect decreases in analyst coverage, market making activity and information available concerning trading prices and volume, and possibly fewer broker-dealers willing to execute trades with respect to our common stock.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds

None.

Item 3. Defaults Upon Senior Securities

None.

Item 4. Mine Safety Disclosures

Not applicable.

Item 5. Other Information

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None.

Item 6. Exhibits

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 agreement 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.

Each exhibit identified below is filed as part of this Report. Exhibits filed with this Report are designated by “*”. Exhibits designated with a “+” constitute a management contract or compensatory plan or arrangement. All exhibits not so designated are incorporated herein by reference to a prior filing as indicated.

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Exhibit Number		Description

10.1		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).

10.2		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).

10.3		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).

10.4		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).

*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.

*101.INS		XBRL Instance Document.

*101.SCH		XBRL Schema Document.

*101.CAL		XBRL Calculation Linkbase Document.

*101.DEF		XBRL Definition Linkbase Document.

*101.LAB		XBRL Labels Linkbase Document.

*101.PRE		XBRL Presentation Linkbase Document.

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.



	EP ENERGY LLC


Date: November 12, 2019	/s/ Kyle A. McCuen
	Kyle A. McCuen
	Senior Vice President, Chief Financial Officer and Treasurer
	(Principal Financial and Accounting Officer)

EP Energy LLC 10-Q