Quarterly Report (10-q)

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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 June 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 001-36253

EP Energy Corporation

(Exact Name of Registrant as Specified in Its Charter)



Delaware		46-3472728
(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

Securities registered pursuant to Section 12(b) of the Act*:



Title of each class	Trading Symbol(s)	Name of each exchange on which registered
Class A Common Stock, par value $0.01 per share	EPEG	N/A

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

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

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§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	Non-accelerated filer o	Emerging Growth Company o
Accelerated filer x	Smaller reporting company x

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

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

Class A Common Stock, par value $0.01 per share. Shares outstanding as of July 31, 2019 : 255,185,316

Class B Common Stock, par value $0.01 per share. Shares outstanding as of July 31, 2019 : 237,256

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EP ENERGY CORPORATION

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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	18
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	31
Item 4.	Controls and Procedures	31

PART II — OTHER INFORMATION

Item 1.	Legal Proceedings	32
Item 1A.	Risk Factors	32
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	34
Item 3.	Defaults Upon Senior Securities	34
Item 4.	Mine Safety Disclosures	34
Item 5.	Other Information	34
Item 6.	Exhibits	34
Signatures		36

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 Corporation and/or its subsidiaries.

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

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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:

• 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, including making principal and

interest payments or to obtain any necessary consents, waivers or forbearances thereunder;

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

• the possibility that we may not be able to continue as a going concern if we are not successful in obtaining

the necessary additional liquidity, refinancing any of our indebtedness on commercially reasonable terms or

at all, executing on our strategic alternatives and/or if there is not a sustained, significant increase in

commodity prices;

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

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

to successfully construct and operate such projects;

• actions by credit rating agencies, including potential downgrades;

• credit and performance risks of our lenders, trading counterparties, customers, vendors, suppliers and third

party operators;

• general economic and weather conditions in geographic regions or markets we serve, or where operations are

located, including the risk of a global recession and negative impact on demand for oil and/or natural gas;

• the uncertainties associated with governmental regulation, including any potential changes in federal and

state tax laws and regulations;

• competition; and

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• 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 CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

(In millions, except per common share amounts)

(Unaudited)



	Quarter ended June 30,						Six months ended June 30,
	2019			2018			2019			2018
Operating revenues
Oil	$	204		$	281		$	397		$	533
Natural gas	8			18			26			40
NGLs	15			30			33			56
Financial derivatives	29			(64		)	(66		)	(78		)
Total operating revenues	256			265			390			551

Operating expenses
Transportation costs	23			26			48			51
Lease operating expense	30			38			67			77
General and administrative	43			28			64			47
Depreciation, depletion and amortization	94			129			188			249
Exploration and other expense	1			—			2			1
Taxes, other than income taxes	20			21			31			41
Total operating expenses	211			242			400			466

Operating income (loss)	45			23			(10		)	85
Gain on extinguishment/modification of debt	—			7			10			48
Interest expense	(95		)	(88		)	(190		)	(173		)
Loss before income taxes	(50		)	(58		)	(190		)	(40		)
Income tax expense	—			—			—			—
Net loss	$	(50	)	$	(58	)	$	(190	)	$	(40	)

Basic and diluted net income (loss) per common share
Net loss	$	(0.20	)	$	(0.23	)	$	(0.76	)	$	(0.16	)
Basic and diluted weighted average common shares outstanding	250			248			249			247

See accompanying notes.

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EP ENERGY CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS

(In millions)

(Unaudited)



	June 30, 2019		December 31, 2018
ASSETS
Current assets
Cash and cash equivalents	$	52	$	27
Accounts receivable
Customer, net of allowance of less than $1 in 2019 and 2018	115		164
Other, net of allowance of $1 in 2019 and 2018	11		66
Materials and supplies	28		22
Derivative instruments	24		101
Other	31		5
Total current assets	261		385
Property, plant and equipment, at cost
Oil and natural gas properties	7,625		7,344
Other property, plant and equipment	76		81
	7,701		7,425
Less accumulated depreciation, depletion and amortization	3,813		3,651
Total property, plant and equipment, net	3,888		3,774
Other assets
Derivative instruments	10		13
Unamortized debt issue costs - revolving credit facility	6		8
Operating lease assets and other	25		1
	41		22
Total assets	$	4,190	$	4,181

See accompanying notes.

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EP ENERGY CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS

(In millions)

(Unaudited)



	June 30, 2019			December 31, 2018
LIABILITIES AND EQUITY
Current liabilities
Current maturities of long-term debt, net of debt issue costs	$	182		$	58
Owner and royalties payable	75			144
Accounts payable and accrued expenses	154			105
Accrued interest	69			70
Accrued legal and other reserves	44			47
Other accrued liabilities	21			16
Total current liabilities	545			440

Long-term debt, net of debt issue costs	4,365			4,285
Other long-term liabilities
Asset retirement obligations	41			39
Lease obligations and other	24			16
Total non-current liabilities	4,430			4,340

Commitments and contingencies (Note 7)

Stockholders’ equity
Class A shares, $0.01 par value; 550 million shares authorized; 256 million shares issued and 255 million outstanding at June 30, 2019; 256 million shares issued and outstanding at December 31, 2018	3			3
Class B shares, $0.01 par value; less than one million shares authorized, issued and outstanding at June 30, 2019 and December 31, 2018	—			—
Preferred stock, $0.01 par value; 50 million shares authorized; no shares issued or outstanding	—			—
Treasury stock (at cost), one million and less than one million shares at June 30, 2019 and December 31, 2018, respectively	(1		)	(1		)
Additional paid-in capital	3,540			3,536
Accumulated deficit	(4,327		)	(4,137		)
Total stockholders’ equity	(785		)	(599		)
Total liabilities and equity	$	4,190		$	4,181

See accompanying notes.

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EP ENERGY CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(In millions)

(Unaudited)



	Six months ended June 30,
	2019			2018
Cash flows from operating activities
Net loss	$	(190	)	$	(40	)
Adjustments to reconcile net loss to net cash provided by operating activities
Depreciation, depletion and amortization	188			249
Gain on extinguishment/modification of debt	(10		)	(48		)
Other non-cash income items	14			13
Asset and liability changes
Accounts receivable	103			(28		)
Owner and royalties payable	(68		)	5
Accounts payable and accrued expenses	12			(22		)
Derivative instruments	80			57
Accrued interest	(1		)	7
Other asset changes	(32		)	11
Other liability changes	(12		)	13
Net cash provided by operating activities	84			217

Cash flows from investing activities
Cash paid for capital expenditures	(249		)	(384		)
Proceeds from the sale of assets	—			169
Cash paid for acquisitions	(15		)	(239		)
Net cash used in investing activities	(264		)	(454		)

Cash flows from financing activities
Proceeds from issuance of long-term debt	615			1,665
Repayments and repurchases of long-term debt	(408		)	(1,291		)
Fees/costs on debt exchange	—			(62		)
Debt issue costs	—			(20		)
Other	(2		)	(1		)
Net cash provided by financing activities	205			291

Change in cash, cash equivalents and restricted cash	25			54

Cash, cash equivalents and restricted cash - beginning of period	27			45
Cash, cash equivalents and restricted cash - end of period	$	52		$	99

See accompanying notes.

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EP ENERGY CORPORATION

CONDENSED CONSOLIDATED STATEMENT OF CHANGES IN EQUITY

(In millions)

(Unaudited)



	Class A Stock				Class B Stock			Treasury Stock			Additional Paid-in Capital			Retained Earnings (Accumulated Deficit)
	Shares		Amount		Shares	Amount		Treasury Stock			Additional Paid-in Capital			Retained Earnings (Accumulated Deficit)			Total

Balance at December 31, 2017	252		$	3	0.3	$	—	$	(3	)	$	3,526		$	(3,134	)	$	392
Share-based compensation	(1	)	—		—	—		(1		)	1			—			—
Net income	—		—		—	—		—			—			18			18
Balance at March 31, 2018	251		$	3	0.3	$	—	$	(4	)	$	3,527		$	(3,116	)	$	410
Share-based compensation	6		—		—	—		4			(1		)	—			3
Net loss	—		—		—	—		—			—			(58		)	(58		)
Balance at June 30, 2018	257		$	3	0.3	$	—	$	—		$	3,526		$	(3,174	)	$	355
Share-based compensation	—		—		—	—		—			6			—			6
Net loss	—		—		—	—		—			—			(44		)	(44		)
Balance at September 30, 2018	257		$	3	0.3	$	—	$	—		$	3,532		$	(3,218	)	$	317
Share-based compensation	(1	)	—		—	—		(1		)	4			—			3
Net loss	—		—		—	—					—			(919		)	(919		)
Balance at December 31, 2018	256		$	3	0.3	$	—	$	(1	)	$	3,536		$	(4,137	)	$	(599	)
Share-based compensation	—		—		—	—		—			3			—			3
Net loss	—		—		—	—		—			—			(140		)	(140		)
Balance at March 31, 2019	256		$	3	0.3	$	—	$	(1	)	$	3,539		$	(4,277	)	$	(736	)
Share-based compensation	(1	)	—		—	—		—			1			—			1
Net loss	—		—		—	—		—			—			(50		)	(50		)
Balance at June 30, 2019	255		$	3	0.3	$	—	$	(1	)	$	3,540		$	(4,327	)	$	(785	)

See accompanying notes.

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EP ENERGY CORPORATION

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 June 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.

Liquidity and Ability to Continue as a Going Concern

The accompanying interim consolidated financial statements have been prepared assuming the Company will continue as a going concern. The interim consolidated financial statements do not include any adjustments that might result from the outcome of a going concern uncertainty.

As previously disclosed, in May 2020, $182 million of our senior unsecured notes will mature. Based on our forecasted EBITDAX and cash on hand, we anticipate that we will not have sufficient liquidity to repay these notes, meet our working capital needs and/or fund our planned capital expenditures as of one year from the filing date of these financial statements without obtaining additional liquidity through other sources. On August 1, 2019, we borrowed $268 million under our Reserve-Based Loan Facility (RBL Facility). Following this drawdown, we have no borrowing capacity remaining under the RBL Facility.

In addition, in the next six months, we have the following near-term interest payments due on our indebtedness: (i) an approximately $40 million interest payment due under the indenture governing our 8.000% 1.5 Lien Notes due 2025 (the “2025 1.5 Lien Notes”) on August 15, 2019; (ii) an approximately $7 million interest payment due under the indenture governing our 7.750% Senior Unsecured Notes due 2022 on September 1, 2019; (iii) an approximately $9 million interest payment due under the indenture governing our 9.375% Senior Unsecured Notes due 2020 on November 1, 2019; (iv) an approximately $51 million interest payment under the indenture governing our 9.375% 1.5 Lien Notes due 2024 on November 1, 2019; (v) an approximately $39 million interest payment due under the indenture governing our 7.750% 1.125 Lien Notes due 2026 on November 15, 2019; (vi) an approximately $20 million interest payment due under the indenture governing our 8.000% 1.25 Lien Notes due 2024 on December 2, 2019; and (vii) an approximately $10 million interest payment due under the indenture governing our 6.375% Senior Unsecured Notes due 2023 on December 15, 2019. While no decision has been made at this time, we may determine not to pay the interest due on our 2025 1.5 Lien Notes on the August 15, 2019 interest payment due date, and we may decide to utilize the 30-day grace period under the indenture governing the 2025 1.5 Lien Notes, or may not make this interest payment or future interest payments at all. Any failure to make payments of interest and principal on our outstanding indebtedness on a timely basis, including with respect to the 2025 1.5 Lien Notes, would likely result in a default under that indebtedness and likely cause cross-defaults and/or cross-acceleration under our other indebtedness, which in the event of available capacity, could limit our ability to borrow under the RBL Facility.

As a result of these issues, there is substantial doubt about the Company’s ability to continue as a going concern. In order to address these issues, our Board of Directors (the “Board”) has appointed a special committee (the “Special Committee”) of the Board consisting of independent members of the Board who are not affiliated with our Sponsors (affiliates of Apollo Global Management LLC, Riverstone Holdings LLC, Access Industries and Korea National Oil Corporation, collectively, the “Sponsors”), and we have engaged financial and legal advisors to consider a number of potential actions we may take in order to address our liquidity and balance sheet issues. We are evaluating certain 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 United States Bankruptcy Code, Title 11 (the

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“Bankruptcy Code”)) and/or similar transactions involving the Company, none of which have been implemented at this time. The Special Committee is authorized to, among other things, consider, evaluate and approve such strategic alternatives.

However, there is no assurance that our actions will be successful in alleviating these concerns. Should we not be able to execute on one of or a combination of these strategic alternatives, we would be unable to continue as a going concern. In addition, in the absence of any suitable relief through the actions mentioned above, should we be required to include a going concern qualification in our year-end audit report and audited financial statements for 2019, the disclosure would be considered a default under the RBL Facility, and potentially an event of default if not waived within 30 days after receiving notice of the default from the administrative agent under the RBL Facility. An event of default under the RBL Facility could trigger cross-defaults and/or cross acceleration under our other debt agreements, including our senior secured and unsecured notes, which could also result in the acceleration of those obligations by the lenders thereunder.

Furthermore, failure to comply with not only the covenants associated with the indebtedness noted above, but also those under each of our debt agreements would likely result in a default under the indebtedness and likely cause cross-defaults and/or cross-acceleration under our other indebtedness. Any cross-defaults and cross-accelerations of our indebtedness could have a material adverse effect on our business, financial condition, liquidity and results of operations and could require that we take other actions to protect our business, including seeking forbearance agreements from our lenders and investors and/or filing for protection under the Bankruptcy Code.

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.

2. Income Taxes

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 six months ended June 30, 2019 and 2018 , our effective tax rates were approximately 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 $9 million and $13 million , for the quarters ended June 30, 2019 and 2018 , respectively, and by $39 million and $8 million for the six months ended June 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 $896 million as of June 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 2016 U.S. tax return.

3. Earnings Per Share

We exclude potentially dilutive securities from the determination of diluted earnings per share (as well as their related income statement impacts) when their impact on net income per common share is antidilutive. Potentially dilutive securities consist of our stock options, restricted stock and performance share unit awards. For both the quarters and six months ended

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June 30, 2019 and 2018 , we incurred net losses and accordingly excluded all potentially dilutive securities from the determination of diluted earnings per share as their impact on loss per common share was antidilutive.

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 June 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:



	June 30, 2019				December 31, 2018
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	(in millions)
Current maturities of long-term debt	$	182	$	7	$	58	$	44

Long-term debt (see Note 6)	$	4,453	$	2,051	$	4,380	$	2,532

Derivative instruments	$	34	$	34	$	114	$	114

As of June 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 long-term 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 June 30, 2019 , we had derivative contracts in the form of collars and three-way collars on 19 MMBbls of oil ( 7 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 13 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 June 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)
June 30, 2019
Derivative instruments	$	38	$	(4	)	$	24	$	10	$	(4	)	$	4	$	—	$	—

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

For the quarters ended June 30, 2019 and 2018 , we recorded derivative gains and losses of $29 million and $64 million , respectively. For the six months ended June 30, 2019 and 2018 , we recorded derivative losses of $66 million and $78

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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.

5. Property, Plant and Equipment

Oil and Natural Gas Properties . As of June 30, 2019 and December 31, 2018 , we had approximately $3.9 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:



	June 30, 2019			December 31, 2018
	(in millions)
Proved
Eagle Ford	$	4,132		$	3,898
Permian	1,789			1,787
Northeastern Utah	1,704			1,659
Total Proved	7,625			7,344
Less accumulated depletion	(3,772		)	(3,607		)
Net capitalized costs for oil and natural gas properties	$	3,853		$	3,737

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

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

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 June 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 June 30, 2019 were as follows:



	2019
	(in millions)
Net asset retirement liability at January 1	$	42
Accretion expense	2
Net asset retirement liability at June 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 and six months ended June 30, 2019 and 2018 were approximately $2 million and $3 million , respectively.

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6. Long-Term Debt

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



	Interest Rate	June 30, 2019			December 31, 2018
		(in millions)
RBL credit facility - due November 23, 2021 ⁽¹⁾	Variable	$	355		$	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
Total debt		4,635			4,438
Current maturities of long-term debt, net of debt issue costs of less than $1 million		(182		)	(58		)
Total long-term debt		4,453			4,380
Less debt discount and non-current portion of unamortized debt issue costs ⁽³⁾		(88		)	(95		)
Total long-term debt, net		$	4,365		$	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 April 30, 2019 and December 31, 2018 , the effective interest rates for the term loan were 6.08% and 6.21% . In April 2019, we retired the note in full.


(3)	Includes debt discount of $39 million and $42 million as of June 30, 2019 and December 31, 2018 , respectively, associated with our 1.5 Lien Notes maturing in 2024 and unamortized debt issue costs of $49 million and $53 million as of June 30, 2019 and December 31, 2018 , respectively.

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, in 2019 and 2018, we also recorded gains and losses on extinguishment/modification of debt primarily related to repurchased debt as follows:



	Quarter ended June 30,			Six months ended June 30,
	2019	2018		2019	2018
	(in millions)
Debt repurchased- face value ⁽¹⁾	—	19		50	19
Cash paid	—	10		40	10
Gain on extinguishment of debt	—	9		10	9
Other losses on extinguishment of debt ⁽²⁾	—	(2	)	—	(2	)

(1) In 2019 and 2018, repurchases were associated with our 2020 senior unsecured notes and 2022 and 2023 senior unsecured notes, respectively.

(2) Reflects the elimination of associated unamortized debt issue costs related to the reduction of our RBL Facility commitments in 2018.

Reserve-based Loan Facility. We have a RBL Facility which allows us to borrow funds or issue letters of credit (LCs) up to $629 million . The RBL Facility matures in November 2021. As of June 30, 2019 , we had $247 million of capacity

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remaining with approximately $27 million of LCs issued and $355 million outstanding under the RBL Facility. On August 1, 2019, we borrowed $268 million under our RBL Facility. Following this drawdown, we have no borrowing capacity remaining under the RBL Facility.

The RBL Facility is collateralized by certain of our oil and natural gas properties and has a borrowing base subject to semi-annual redetermination. In April 2019, our RBL borrowing base was reaffirmed at $1.36 billion and total commitments remained at $629 million . Our next redetermination date is in November 2019. Downward revisions of our oil and natural gas reserves volume and value due to declines in commodity prices, the impact of lower estimated capital spending in response to lower prices, performance revisions, or sales of assets or the incurrence of certain types of additional debt, among other items, could cause a reduction of our borrowing base in the future, and these reductions could be significant.

Restrictive Provisions/Covenants. The availability of borrowings under our RBL Facility and our ability to incur additional indebtedness is subject to various financial and non-financial covenants and restrictions, including first lien debt to EBITDAX and current ratio financial covenants. First lien debt for purposes of the covenant only includes amounts borrowed under our RBL Facility. Our current financial covenants require us to maintain a ratio of first lien debt to EBITDAX not exceeding 2.25 to 1.00 and a current ratio (as defined in the RBL Facility) of not less than 1.00 to 1.00. As of June 30, 2019 , we were in compliance with our debt covenants.

Under our various debt agreements, we are limited in our ability to repurchase certain tranches of non-RBL Facility debt. Certain other covenants and restrictions, among other things, also limit or place certain conditions on our ability to incur or guarantee additional indebtedness, make restricted payments, pay dividends on equity interests, redeem, repurchase or retire equity interests or subordinated indebtedness, sell assets, make investments, create certain liens, prepay debt obligations, engage in certain transactions with affiliates, and enter into certain hedging agreements. We are also subject to cross-defaults and/or cross-acceleration under our debt agreements which are further described in Note 1.

7. Commitments and Contingencies

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 June 30, 2019 , we had approximately $29 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 Global Management LLC, Riverstone Holdings LLC, Access Industries 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 June 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. As of June 30, 2019 , we had accrued $3 million related to this matter, which was subsequently settled in July 2019.

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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 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 June 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 June 30, 2019 , we had approximately $15 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 June 30, 2019 , both interest and depreciation expense associated with our finance leases was approximately $1 million and related cash payments were approximately $2 million . For the six months ended June 30, 2019 , both interest and depreciation expense associated with our finance leases were approximately $2 million 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

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over the lease term depending on the nature of the payment. For the quarter ended June 30, 2019 , operating lease costs and related cash payments were approximately $3 million and $2 million , respectively, and $5 million and $3 million , respectively, for the six months ended June 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 both the quarter and six months ended June 30, 2019 , variable lease costs were approximately $1 million .

Short-term lease costs for the quarter and six months ended June 30, 2019 were approximately $7 million and $16 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:



	June 30, 2019
	(in millions)
Operating lease assets ⁽¹⁾⁽⁴⁾	$	23
Finance lease assets ⁽²⁾	11
Total lease assets	$	34

Operating leases ⁽³⁾⁽⁴⁾
Current liability	$	10
Noncurrent liability	13
Total operating lease liability	$	23
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	9.37		%
Finance leases	26.52		%


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


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


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

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	Operating Leases			Finance Leases
	(in millions)
2019	$	6		$	2
2020	10			5
2021	3			5
2022	2			5
Thereafter	6			2
Total	$	27		$	19
Less: imputed interest	(4		)	(8		)
Present value of operating and finance lease obligations	$	23		$	11

8. Incentive Compensation

Long-term Incentive Compensation

Our 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 LTI awards as general and administrative expense over the requisite service period. Pre-tax compensation expense related to all of our LTI awards (both equity and liability based), net of the impact of forfeitures, was approximately $3 million for both of the quarters ended June 30, 2019 and 2018 , and $7 million and $4 million for the six months ended June 30, 2019 and 2018 , respectively. As of June 30, 2019 , we had unrecognized compensation expense of $18 million of which we will recognize $7 million during the remainder of 2019 and $11 million thereafter.

Restricted Stock. A summary of the changes in our non-vested restricted shares for the six months ended June 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	(1,112,910	)	$	4.93
Forfeited	(754,623	)	$	2.60
Non-vested at June 30, 2019	5,295,801		$	2.24

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 June 30, 2019 , we had a total of 1,487,280 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 June 30, 2019, our consolidated balance sheet reflects a liability and deferred charge in the amount of approximately $21 million and $20 million respectively, related to the KERP. For accounting purposes, deferred expense is being amortized over the 13 month term of the KERP agreement. During both the quarter and six months ended June 30, 2019 , we recorded less than $1 million in expense related to the KERP.

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9. Related Party Transactions

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 Global Management LLC) and indirectly through Access Industries (through an indirect minority ownership interest in the Investor). At June 30, 2019 and December 31, 2018 , we had accounts receivable of $3 million and $47 million , respectively, and payables to our owner of $9 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.

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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 Corporation and each of its consolidated subsidiaries.

Our Business

Overview . We are an independent exploration and production company engaged in the acquisition and development of unconventional onshore oil and natural gas properties in the United States. We operate through a diverse base of producing

assets and are focused on providing returns to our shareholders 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.

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 June 30, 2019 , we have 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 Information", 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 June 30, 2019 , we have drilled and completed 47 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 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.

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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 June 30, 2019 .



	2019				2020
	Volumes ⁽¹⁾	Average Price ⁽¹⁾			Volumes ⁽¹⁾	Average Price ⁽¹⁾
Oil
Collars
Ceiling - WTI	736	$	69.78		—	$	—
Floors - WTI	736	$	57.50		—	$	—
Three Way Collars
Ceiling - WTI	6,072	$	66.01		11,712	$	65.11
Floors - WTI	6,072	$	55.76		11,712	$	55.90
Sub-Floor - WTI	6,072	$	45.00		11,712	$	45.00
Basis Swaps
Midland vs. Cushing ⁽²⁾	736	$	(5.23	)	1,464	$	0.46
NYMEX Roll ⁽³⁾	244	$	0.25		—	$	—
Natural Gas
Fixed Price Swaps	6	$	3.01		—	$	—
Collars
Ceiling	7	$	4.26		—	$	—
Floors	7	$	2.75		—	$	—
Basis Swaps
WAHA vs. Henry Hub ⁽⁴⁾	4	$	(0.39	)	—	$	—


(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 June 30, 2019 , the average forward price of oil was $58.16 per barrel of oil for the remainder of 2019 and $55.91 per barrel of oil for 2020.

During the six months ended June 30, 2019 , we settled commodity index hedges on approximately 99% of our oil production, 73% of our total NGLs production and 60% of our natural gas production at average floor prices of $55.92 per barrel of oil and $2.86 per MMBtu of natural gas, respectively. As of June 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

Our primary sources of liquidity are cash generated by our operations and borrowings under our Reserve-Based Loan Facility (RBL Facility) which matures in 2021 and our primary uses of cash are capital expenditures, debt service, including interest, and working capital requirements. Our available liquidity was $299 million as of June 30, 2019 .

In April 2019, our RBL borrowing base was reaffirmed at $1.36 billion and total commitments remained at $629 million. However, downward revisions of our oil and natural gas reserves volume and value due to declines in commodity prices, the impact of lower estimated capital spending in response to lower prices, performance revisions, sales of assets, or the incurrence of certain types of additional debt, among other items, could cause a reduction of our borrowing base in the future, and these reductions could be significant. Conversely, future acquisitions, reserve additions and higher prices may have the effect of increasing our borrowing base.

Debt Maturities and Covenants. As of June 30, 2019 , our total debt was approximately $4.6 billion, comprised of $182 million in senior unsecured notes due in 2020, $355 million outstanding under the RBL Facility which matures in 2021, $506 million in senior unsecured notes due in 2022 and 2023, and $3.6 billion in 1.5 Lien Notes due in 2024 and 2025, 1.25 Lien Notes due in 2024 and 1.125 Lien Notes due in 2026. Our most restrictive financial debt covenants (which were modified and/or extended in 2018) include a requirement to maintain a first lien debt to EBITDAX ratio of 2.25 to 1.00 and a current ratio (as defined in the RBL Facility) of not less than 1.00 to 1.00. As of June 30, 2019 , we were in compliance with our debt covenants. For additional details on our long-term debt, see Part I, Item 1, Financial Statements, Note 6.

As previously disclosed, in May 2020, $182 million of our senior unsecured notes will mature. Based on our forecasted EBITDAX and cash on hand, we anticipate that we will not have sufficient liquidity to repay these notes, meet our working capital needs and/or fund our planned capital expenditures as of May 2020 when these notes are due. On August 1, 2019, we borrowed $268 million under our RBL Facility. Following this drawdown, we have no borrowing capacity remaining under the RBL Facility.

In addition, in the next six months we have the following near-term interest payments due on our indebtedness: (i) an approximately $40 million interest payment due under the indenture governing our 8.000% 1.5 Lien Notes due 2025 (the “2025 1.5 Lien Notes”) on August 15, 2019; (ii) an approximately $7 million interest payment due under the indenture governing our 7.750% Senior Unsecured Notes due 2022 on September 1, 2019; (iii) an approximately $9 million interest payment due under the indenture governing our 9.375% Senior Unsecured Notes due 2020 on November 1, 2019; (iv) an approximately $51 million interest payment under the indenture governing our 9.375% 1.5 Lien Notes due 2024 on November 1, 2019; (v) an approximately $39 million interest payment due under the indenture governing our 7.750% 1.125 Lien Notes due 2026 on November 15, 2019; (vi) an approximately $20 million interest payment due under the indenture governing our 8.000% 1.25 Lien Notes due 2024 on December 2, 2019; and (vii) an approximately $10 million interest payment due under the indenture governing our 6.375% Senior Unsecured Notes due 2023 on December 15, 2019. While no decision has been made at this time, we may determine not to pay the interest due on our 2025 1.5 Lien Notes on the August 15, 2019 interest payment due date, and we may decide to utilize the 30-day grace period under the indenture governing the 2025 1.5 Lien Notes, or may not make this payment or future interest payments at all. Any failure to make payments of interest and principal on our outstanding indebtedness on a timely basis, including with respect to the 2025 1.5 Lien Notes, would likely result in a default under that indebtedness and likely cause cross-defaults and/or cross-acceleration under our other indebtedness, which in the event of available capacity, could limit our ability to borrow under the RBL Facility.

However, there can be no assurance that this review will be successful, and an in-court restructuring pursuant to which we may seek relief under the Bankruptcy Code may be unavoidable. Any transaction or action we determine to pursue, including seeking in-court protection under the Bankruptcy Code, could require our senior management to spend a significant

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amount of time and effort dealing with such transaction or action instead of focusing exclusively on our business operations and make it more difficult to attract, retain or replace management and other key personnel necessary to the success and growth of our business; cause the loss of confidence in us by our customers; and have a material adverse effect on our business, financial condition, liquidity and results of operations.

Even if we are able to implement such strategic alternatives, they may be insufficient to meet our debt and other obligations over the longer term. Furthermore, such strategic alternatives may not yield additional value for stockholders, and may adversely affect our creditors or our existing stockholders, potentially resulting in a reduction in the value of their investment or the loss of all or substantially all of their investment in us. In addition, we may incur substantial expenses associated with identifying and evaluating potential strategic alternatives, and the process of exploring strategic alternatives may be time consuming and disruptive to our business operations.

Should we not be able to execute on one of or a combination of these strategic alternatives, we would be unable to continue as a going concern. In addition, in the absence of any suitable relief through the actions mentioned above, should we be required to include a going concern qualification in our year-end audit report and audited financial statements for 2019 the disclosure would also be considered a default under the Company's RBL Facility, and potentially an event of default if not waived within 30 days after receiving notice of the default from the administrative agent under the RBL Facility. An event of default under the RBL Facility could trigger cross-defaults and/or cross acceleration under our other debt agreements, including our senior secured term loan and our senior secured and unsecured notes, which could also result in the acceleration of those obligations by the lenders thereunder.

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



	Capital Expenditures ⁽¹⁾ (in millions)		Average Drilling Rigs
Eagle Ford Shale	$	226	2.8
Northeastern Utah	60		1.3
Permian	2		—
Total	$	288	4.1
Acquisition capital	$	15
Total Capital Expenditures	$	303


(1)	Represents accrual-based capital expenditures.

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



	Six months ended June 30,
	2019			2018
Cash Inflows
Operating activities
Net loss	$	(190	)	$	(40	)
Gain on extinguishment/modification of debt	(10		)	(48		)
Other income adjustments	202			262
Changes in assets and liabilities	82			43
Total cash flow from operations	84			217

Investing activities
Proceeds from the sale of assets	—			169
Cash inflows from investing activities	—			169

Financing activities
Proceeds from issuance of long-term debt	615			1,665
Cash inflows from financing activities	615			1,665

Total cash inflows	$	699		$	2,051

Cash Outflows
Investing activities
Capital expenditures	$	249		$	384
Cash paid for acquisitions	15			239
Cash outflows from investing activities	264			623

Financing activities
Repayments and repurchases of long-term debt	408			1,291
Fees/costs on debt exchange	—			62
Debt issue costs	—			20
Other	2			1
Cash outflows from financing activities	410			1,374

Total cash outflows	$	674		$	1,997

Net change in cash, cash equivalents and restricted cash	$	25		$	54

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Production Volumes and Drilling Summary

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



	2019	2018
Equivalent Volumes (MBoe/d)
Eagle Ford	32.8	37.6
Northeastern Utah	15.6	17.0
Permian	23.2	26.7
Total	71.6	81.3

Oil (MBbls/d)
Eagle Ford	21.6	24.9
Northeastern Utah	10.1	11.7
Permian	6.8	9.7
Total	38.5	46.3

Natural Gas (MMcf/d)
Eagle Ford ⁽¹⁾	33	38
Northeastern Utah	33	32
Permian	52	55
Total	118	125

NGLs (MBbls/d)
Eagle Ford	5.7	6.4
Northeastern Utah	—	—
Permian	7.7	7.8
Total	13.4	14.2


(1)	Production volume excludes 7 MMcf/d of reinjected gas volumes used in operations during the six months ended June 30, 2019 .

Production Summary. For the six months ended June 30, 2019 compared to the same period in 2018, (i) Eagle Ford equivalent volumes decreased 4.8 MBoe/d or (approximately 13% ) due to fewer wells placed on production in the second half of 2018 and first half of 2019, (ii) NEU equivalent volumes decreased 1.4 MBoe/d or (approximately 8% ) due to reduced drilling activity in 2019, and (iii) Permian equivalent volumes decreased 3.5 MBoe/d or (approximately 13% ) reflecting the slower pace of development due to a significant reduction in capital allocated to the Permian. I n Eagle Ford and Permian, our 2019 production volumes were also negatively impacted by downstream third-party operational issues and constraints.

Drilling Summary. During the six months ended June 30, 2019 , we (i) frac’d (wells fracture stimulated) 26 gross wells in the Eagle Ford, 24 of which came online for a total of 811 net operated wells, and (ii) frac’d 7 gross wells in NEU, all of which came online for a total of 292 net operated wells. We did not frac any wells in the Permian during the six months ended June 30, 2019 , and currently operate 350 net wells in the area. As of June 30, 2019 , we also had a total of 62 gross wells in progress, of which all 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 June 30,						Six months ended June 30,
	2019			2018			2019			2018
	(in millions)
Operating revenues
Oil	$	204		$	281		$	397		$	533
Natural gas	8			18			26			40
NGLs	15			30			33			56
Total physical sales	227			329			456			629
Financial derivatives	29			(64		)	(66		)	(78		)
Total operating revenues	256			265			390			551

Operating expenses
Transportation costs	23			26			48			51
Lease operating expense	30			38			67			77
General and administrative	43			28			64			47
Depreciation, depletion and amortization	94			129			188			249
Exploration and other expense	1			—			2			1
Taxes, other than income taxes	20			21			31			41
Total operating expenses	211			242			400			466

Operating income (loss)	45			23			(10		)	85
Gain on extinguishment/modification of debt	—			7			10			48
Interest expense	(95		)	(88		)	(190		)	(173		)
Loss before income taxes	(50		)	(58		)	(190		)	(40		)
Income tax expense	—			—			—			—
Net loss	$	(50	)	$	(58	)	$	(190	)	$	(40	)

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Operating Revenues

The table below provides our operating revenues, volumes and prices per unit for the quarters and six months ended June 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 June 30,					Six months ended June 30,
	2019		2018			2019			2018
	(in millions)
Operating revenues:
Oil	$	204	$	281		$	397		$	533
Natural gas	8		18			26			40
NGLs	15		30			33			56
Total physical sales	227		329			456			629
Financial derivatives	29		(64		)	(66		)	(78		)
Total operating revenues	$	256	$	265		$	390		$	551

Volumes:
Oil (MBbls)	3,424		4,299			6,970			8,386
Natural gas (MMcf)	10,121		11,274			21,277			22,609
NGLs (MBbls)	1,245		1,334			2,428			2,566
Equivalent volumes (MBoe)	6,356		7,512			12,944			14,720
Total MBoe/d	69.8		82.5			71.6			81.3

Prices per unit ⁽¹⁾ :
Oil
Average realized price on physical sales ($/Bbl) ⁽²⁾	$	59.72	$	65.53		$	56.97		$	63.60
Average realized price, including financial derivatives ($/Bbl) ⁽²⁾⁽³⁾	$	59.84	$	62.30		$	57.89		$	60.62
Natural gas
Average realized price on physical sales ($/Mcf) ⁽²⁾	$	0.80	$	1.58		$	1.21		$	1.76
Average realized price, including financial derivatives ($/Mcf) ⁽²⁾⁽³⁾	$	1.36	$	1.96		$	1.57		$	2.00
NGLs
Average realized price on physical sales ($/Bbl)	$	12.06	$	22.65		$	13.81		$	21.82
Average realized price, including financial derivatives ($/Bbl) ⁽³⁾	$	12.06	$	22.07		$	13.81		$	21.51


(1)	For both of the quarters and six months ended June 30, 2019 and 2018 , there were no oil purchases associated with managing our physical oil sales. Natural gas prices for both of the quarters and six months ended June 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 June 30, 2019 and 2018 , include cash received of less than $1 million and cash paid of approximately $14 million, respectively, for the settlement of crude oil derivative contracts and approximately $6 million and $4 million of cash received, respectively, for the settlement of natural gas financial derivatives. The six months ended June 30, 2019 and 2018 , include cash received of approximately $6 million and cash paid of approximately $25 million, respectively, for the settlement of crude oil derivative contracts and approximately $8 million and $5 million of cash received, respectively, for the settlement of natural gas financial derivatives. Both the quarter and six months ended June 30, 2018 also include $1 million 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 six months ended June 30, 2019 and 2018 .



	Quarter ended
	Oil			Natural gas			NGLs			Total
	(in millions)
June 30, 2018 sales	$	281		$	18		$	30		$	329
Change due to prices	(20		)	(8		)	(13		)	(41		)
Change due to volumes	(57		)	(2		)	(2		)	(61		)
June 30, 2019 sales	$	204		$	8		$	15		$	227



	Six months ended
	Oil			Natural gas			NGLs			Total
	(in millions)
June 30, 2018 sales	$	533		$	40		$	56		$	629
Change due to prices	(46		)	(12		)	(20		)	(78		)
Change due to volumes	(90		)	(2		)	(3		)	(95		)
June 30, 2019 sales	$	397		$	26		$	33		$	456

Oil sales for the quarter and six months ended June 30, 2019 , compared to the same periods in 2018 , decreased by $77 million ( 27% ) and $136 million (26)% , respectively, due primarily to lower oil prices and production in all areas reflecting lower capital spending from the first half of 2018 through the first half of 2019.

Natural gas sales decreased by $10 million ( 56% ) and $14 million (35)% , respectively, for the quarter and six months ended June 30, 2019 compared to the same periods in 2018 primarily due to lower natural gas prices and production in the Eagle Ford and Permian.

Our oil, natural gas and NGLs are sold at index prices (WTI, Brent, LLS, Henry Hub and Mt. Belvieu) or refiners’ posted prices at various delivery points across our producing basins. Realized prices received (not considering the effects of hedges) are generally less than the stated index price as a result of fixed or variable contractual deductions, differentials from the index to the delivery point, adjustments for time, and/or discounts for quality or grade.

In the Eagle Ford, our oil is sold at prices tied primarily to benchmark Magellan East Houston crude oil. In NEU, market pricing of our oil is based upon NYMEX-based agreements, which reflect a locational difference at the wellhead. In the Permian, physical barrels are generally sold at the WTI Midland Index, which trades at a spread to WTI Cushing. Across all regions, natural gas realized pricing is influenced by factors such as 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 June 30,
	2019						2018
	Oil (Bbl)			Natural gas (MMBtu)			Oil (Bbl)			Natural gas (MMBtu)
Differentials and deducts	$	(0.15	)	$	(1.77	)	$	(2.27	)	$	(1.10	)
NYMEX	$	59.82		$	2.64		$	67.88		$	2.80
Net back realization %	99.7		%	33.0		%	96.7		%	60.7		%

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	Six months ended June 30,
	2019						2018
	Oil (Bbl)			Natural gas (MMBtu)			Oil (Bbl)			Natural gas (MMBtu)
Differentials and deducts	$	(0.67	)	$	(1.63	)	$	(1.67	)	$	(1.07	)
NYMEX	$	57.36		$	2.89		$	65.37		$	2.90
Net back realization %	98.8		%	43.6		%	97.4		%	63.1		%

The oil realization percentages for the quarter and six months ended June 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 six months ended June 30, 2019 were primarily a result of weaker Permian basin natural gas pricing.

NGLs sales decreased by $15 million ( 50% ) and $23 million (41)% , respectively, for the quarter and six months ended June 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 June 30, 2019 and 2018 , we recorded $29 million and $ 64 million of derivative gains and losses, respectively. For the six months ended June 30, 2019 and 2018 , we recorded $66 million and $78 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 June 30,
	2019				2018
	Total		Per Unit ⁽¹⁾		Total		Per Unit ⁽¹⁾
	(in millions, except per unit costs)
Operating expenses
Transportation costs	$	23	$	3.67	$	26	$	3.49
Lease operating expense	30		4.84		38		4.95
General and administrative ⁽²⁾	43		6.77		28		3.74
Depreciation, depletion and amortization	94		14.83		129		17.20
Exploration and other expense	1		0.10		—		—
Taxes, other than income taxes	20		3.04		21		2.82
Total operating expenses	$	211	$	33.25	$	242	$	32.20

Total equivalent volumes (MBoe)	6,356				7,512

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	Six months ended June 30,
	2019				2018
	Total		Per Unit ⁽¹⁾		Total		Per Unit ⁽¹⁾
	(in millions, except per unit costs)
Operating expenses
Transportation costs	$	48	$	3.70	$	51	$	3.46
Lease operating expense	67		5.20		77		5.21
General and administrative ⁽²⁾	64		4.93		47		3.17
Depreciation, depletion and amortization	188		14.58		249		16.95
Exploration and other expense	2		0.10		1		0.09
Taxes, other than income taxes	31		2.38		41		2.78
Total operating expenses	$	400	$	30.89	$	466	$	31.66

Total equivalent volumes (MBoe)	12,944				14,720


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

(2)

For the quarter and six months ended June 30, 2019 , amount includes approximately $3 million or $0.45 per Boe and $7 million or $0.51 per Boe, respectively, of non-cash compensation expense, $3 million or $0.46 per Boe and $4 million or $0.27 per Boe, respectively, of transition, severance and other costs, $1 million or $0.06 per Boe and $1 million or $0.05 per Boe, respectively, of fees paid to Sponsors, and $24 million or $3.78 per Boe and $24 million or $1.85 per Boe, respectively, of legacy litigation accruals and settlements. For the quarter and six months ended June 30, 2018 , amount includes approximately $2 million or $0.38 per Boe and $4 million or $0.30 per Boe, respectively, of non-cash compensation expense and approximately $6 million or $0.77 per Boe and $6 million or $0.40 per Boe, respectively, of transition, severance and other costs.

Transportation costs. Transportation costs for both the quarter and six months ended June 30, 2019 decreased by $3 million compared to the same periods in 2018 as a result of expiring transportation agreements in the Eagle Ford and lower fees associated with revised transportation agreements in the Permian in 2019.

Lease operating expense. Lease operating expense decreased by $8 million and $10 million for the quarter and six months ended June 30, 2019 , respectively, compared to the same periods in 2018 . The decrease for the quarter and six months ended June 30, 2019 compared to 2018 is due primarily to lower disposal costs in the Eagle Ford and Permian and lower chemical costs in the Permian. Also impacting the six months ended June 30, 2019 were lower maintenance costs in 2019 in the Eagle Ford and Permian.

General and administrative expenses. General and administrative expenses for the quarter and six months ended June 30, 2019 increased by $15 million and $17 million , respectively, compared to the same periods in 2018 . Higher costs during the quarter and six months ended June 30, 2019 compared to the same periods in 2018 were primarily due to accruals of $21 million related to legacy legal matters (see Part 1, Item 1, Financial Statements, Note 6) in 2019. Also impacting the quarter and six months ended June 30, 2019 were $3 million and $4 million, respectively, of higher professional and legal fees primarily related to legal and financial advisory fees incurred associated with the evaluation of strategic alternatives.

Higher overall general and administrative costs during both the quarter and six months ended June 30, 2019 were partially offset by lower payroll, bonus and benefits of $5 million and lower severance expense of $5 million for both periods. The decrease in bonus and benefits for both periods is primarily due to the reversal of previous amounts accrued associated with the 2019 annual bonus in conjunction with the implementation of the Key Employee Retention Program (“KERP”), which granted payments to KERP participants in lieu of any bonuses or long-term incentive awards, if any, that would otherwise be due or payable to the KERP participants for 2019 performance. For further discussion of the KERP, see Part I, Item, I, Financial Statements, Note 8.

Depreciation, depletion and amortization expense. Depreciation, depletion and amortization expense decreased for the quarter and six months ended June 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 six months ended June 30 were:

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	Quarter ended June 30,				Six months ended June 30,
	2019		2018		2019		2018
Depreciation, depletion and amortization ($/Boe)	$	14.83	$	17.20	$	14.58	$	16.95

Taxes, other than income taxes. Taxes, other than income taxes, for the quarter and six months ended June 30, 2019 , decreased by $1 million and $10 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 six months ended June 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.

For the quarter ended June 30, 2018 , we recorded a total gain on extinguishment of debt of $7 million primarily as a result of our repurchase of approximately $19 million in aggregate principal amount of our senior unsecured notes. During the six months ended June 30, 2018 , we also 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 six months ended June 30, 2019 increased by $7 million and $17 million , respectively, compared to the same periods in 2018 due primarily to the issuance of our senior secured notes due 2026 in May 2018, partially offset by lower average borrowings under our RBL Facility during both the quarter and six months ended June 30, 2019 .

Income taxes. For both the quarters and six months ended June 30, 2019 and 2018 , our effective tax rates were approximately 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 $9 million and $13 million , for the quarters ended June 30, 2019 and 2018 , respectively, and by $39 million and $8 million for the six months ended June 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), the non-cash portion of compensation expense (which represents non-cash compensation expense under our long-term incentive programs), transition, severance and other costs that affect comparability, management and other fees paid to Sponsors, legacy litigation settlements and gains and losses on extinguishment/modification of debt.

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 June 30,						Six months ended June 30,
	2019			2018			2019			2018
	(in millions)
Net loss	$	(50	)	$	(58	)	$	(190	)	$	(40	)
Income tax expense	—			—			—			—
Interest expense, net of capitalized interest	95			88			190			173
Depreciation, depletion and amortization	94			129			188			249
Exploration expense	1			1			2			2
EBITDAX	140			160			190			384
Mark-to-market on financial derivatives ⁽¹⁾	(29		)	64			66			78
Cash settlements and cash premiums on financial derivatives ⁽²⁾	6			(10		)	14			(20		)
Non-cash portion of compensation expense ⁽³⁾	3			2			7			4
Transition, severance and other costs	3			6			4			6
Fees paid to Sponsors	1			—			1			—
Legacy litigation settlements ⁽ ⁴⁾	24			—			24			—
Gain on extinguishment/modification of debt	—			(7		)	(10		)	(48		)
Adjusted EBITDAX	$	148		$	215		$	296		$	404


(1)	Represents the income statement impact of financial derivatives.


(2)	Represents actual cash settlements related to financial derivatives. No cash premiums were received or paid for the quarters and six months ended June 30, 2019 and 2018.


(3)	For the quarter and six months ended June 30, 2019 , non-cash compensation expense includes less than $1 million in amounts under the Key Employee Retention Program, "KERP", in lieu of long-term incentive compensation. For additional details on the KERP, see Part I, Item 1, Financial Statements, Note 8.


(4)	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 and Quantitative 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 June 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⁾	$	34	$	(26	)	$	(60	)	$	88	$	54



			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⁾	$	34	$	34	$	—	$	34	$	—
Credit rate ⁽³⁾	$	34	$	34	$	—	$	34	$	—


(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 June 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 June 30, 2019 .

Changes in Internal Control over Financial Reporting

There were no changes in EP Energy Corporation’s internal control over financial reporting during the three months ended June 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 heading “Legal Matters” is 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.

Any determination by us not to make an interest payment under any of our debt instruments could have a material adverse effect on our business, financial condition, liquidity and results of operations.

In the next six months, we have the following near-term interest payments due on our indebtedness: (i) an approximately $40 million interest payment due under the indenture governing our 2025 1.5 Lien Notes on August 15, 2019; (ii) an approximately $7 million interest payment due under the indenture governing our 7.750% Senior Unsecured Notes due 2022 on September 1, 2019; (iii) an approximately $9 million interest payment due under the indenture governing our 9.375% Senior Unsecured Notes due 2020 on November 1, 2019; (iv) an approximately $51 million interest payment under the indenture governing our 9.375% 1.5 Lien Notes due 2024 on November 1, 2019; (v) an approximately $39 million interest payment due under the indenture governing our 7.750% 1.125 Lien Notes due 2026 on November 15, 2019; (vi) an approximately $20 million interest payment due under the indenture governing our 8.000% 1.25 Lien Notes due 2024 on December 2, 2019; and (vii) an approximately $10 million interest payment due under the indenture governing our 6.375% Senior Unsecured Notes due 2023 on December 15, 2019. While no decision has been made at this time, we may determine not to pay the interest due on our 2025 1.5 Lien Notes on the August 15, 2019 interest payment due date, and we may decide to utilize the 30-day grace period under the indenture governing the 2025 1.5 Lien Notes or may not make the interest payment at all.

Any failure to make payments of interest and principal on our outstanding indebtedness on a timely basis, including with respect to the 2025 1.5 Lien Notes, would likely result in a default under that indebtedness, which would likely cause cross-defaults and/or cross-acceleration under our other indebtedness, after the expiration of the applicable grace period, which could have a material adverse effect on our business, financial condition, liquidity and results of operations, or could force us into and could require that we take other actions to protect our business, including seeking forbearance agreements from our lenders and investors and/or filing for protection under the Bankruptcy Code.

We may be unable to successfully identify or effectuate any or all of the strategic alternatives that we must implement in order to service our substantial indebtedness.

As discussed herein, in the next six months, we have near-term interest payments due on our indebtedness. We may not have sufficient liquidity available to make these interest payments, meet our working capital needs, fund our planned capital expenditures or meet other near-term maturities. We may determine not to make certain payments and/or use available grace periods before making certain payments. We have engaged legal and financial advisors and our Board has appointed a Special Committee of the Board consisting of independent members of the Board who are not affiliated with our Sponsors to consider a number of potential actions we may take in order to address our liquidity and balance sheet issues. We are evaluating certain 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, none of which have been implemented at this time. The Special Committee is authorized to, among other things, consider, evaluate and approve such strategic alternatives.

However, there can be no assurance as to when or whether we will determine to implement any action as a result of this review, whether the implementation of one or more of such actions will be successful, or the effects the failure to take action may have on our business, our ability to achieve our operational and strategic goals or our ability to finance our business or refinance our indebtedness. In addition, we may fail to identify or effectuate any such strategic alternatives on commercially reasonable terms or at all. The failure to develop and implement steps to address our level of corporate leverage may have a material adverse effect on our business, prospects, results of operations, liquidity and financial condition, and our ability to refinance our corporate level indebtedness as it becomes due in future years.

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If we fail to obtain the necessary additional liquidity, there may be substantial doubt that we would be able to continue as a going concern. Even if we are able to implement such strategic alternatives, they may be insufficient to meet our debt and other obligations. Furthermore, such strategic alternatives may not yield additional value for stockholders, and may adversely affect our creditors or our stockholders, potentially resulting in the loss of all or substantially all of their investment in us. In addition, we may incur substantial expenses associated with identifying and evaluating potential strategic alternatives, and the process of exploring strategic alternatives may be time consuming and disruptive to our business operations.

Under the RBL Facility, we are required to deliver audited consolidated financial statements without a going concern or like qualification or explanation. The inclusion of a going concern explanation in our audited financial statements would result in an event of default under the RBL Facility, after which the lenders thereunder could, in the absence of a waiver, forbearance or other suitable relief, accelerate the outstanding indebtedness. In addition, an event of default under our RBL Facility could trigger cross-defaults and/or cross-acceleration under our other debt agreements, including our senior secured and unsecured notes, which could also result in the acceleration of those obligations by the lenders thereunder.

Our ability to issue additional debt and/or refinance our debt depends on numerous factors, such as our financial condition and the terms of our existing debt agreements, which include restrictions on our ability to, among other things, incur additional debt and prepay, redeem or repurchase certain debt. Our ability to issue additional debt and/or refinance our debt is also subject to many factors that are beyond our control, such as commodity prices, interest rates, and the condition of the capital markets in general. Even if we are able to issue additional debt and/or refinance our debt, we could, as a result, become subject to higher interest rates and/or more onerous debt covenants, which could further restrict our ability to operate our business. To the extent that we seek to sell assets in order to meet our debt and other obligations, we may fail to effectuate any such dispositions for fair market value, in a timely manner or at all. Furthermore, the proceeds that we realize from any such dispositions may be inadequate to meet our debt and other obligations.

Our potential for restructuring transactions may impact our business, financial condition and operations.

Our Board has appointed a Special Committee which is authorized to, among other things, consider, evaluate and approve strategic alternatives to address our liquidity and capital structure, and we have engaged financial and legal advisors. However, there can be no assurance that this review will be successful, and an in-court restructuring (pursuant to which we may seek relief under the Bankruptcy Code) may be unavoidable. Seeking in-court protection could require our senior management to spend a significant amount of time and effort dealing with the reorganization instead of focusing exclusively on our business operations and make it more difficult to attract, retain or replace management and other key personnel necessary to the success and growth of our business; cause the loss of confidence in us by our customers; and have a material adverse effect on our business, financial condition, liquidity and results of operations.

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. As a result, the Sponsors and such other investors have the ability to prevent any transaction that would require the approval of stockholders and, generally, have had significant influence over our decisions to enter into certain corporate transactions.

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, none of which have been implemented at this time. One or more of our Sponsors may have certain conflicts of interest with our public stockholders and may have significant influence over certain strategic alternatives, including restructuring transactions, particularly to the extent any such Sponsor also holds our notes in addition to their equity interests in us. As of June 30, 2019 , affiliates of Apollo Global Management held approximately $675 million of the aggregate outstanding principal amount of approximately $2,092 million of our 9.375% 1.5 Lien Notes due 2024 and 8.000% 1.5 Lien Notes due 2025 and approximately $21 million of the outstanding principal amount of $500 million of our 8.000% 1.25 Lien Notes due 2024. As of June 30, 2019, affiliates of Access Industries held approximately $48 million of our 1.5 Lien Notes.

The indentures governing the notes and the credit agreements governing the RBL Facility and our senior secured term loan permit us, under certain circumstances, to pay advisory and other fees, pay dividends and make other restricted payments

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to the Sponsors and other investors, and the Sponsors and such other investors or their respective affiliates may have an interest in our doing so.

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.

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

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.

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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.



Exhibit Number		Description

*10.1+		Form of Key Employee Retention Plan for officers

*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 CORPORATION


Date: August 9, 2019	/s/ Kyle A. McCuen
	Kyle A. McCuen
	Senior Vice President, Chief Financial Officer and Treasurer
	(Principal Financial and Accounting Officer)

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