UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q

(Mark One)

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

EXCHANGE ACT OF 1934

For the quarterly period ended September 30, 2017

OR

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

EXCHANGE ACT OF 1934

                    For the transition period from             to            

Commission File Number 001-36253

EP Energy Corporation

(Exact Name of Registrant as Specified in Its Charter)

Delaware	46-3472728
(State or Other Jurisdiction of Incorporation or Organization)	(I.R.S. Employer Identification No.)
1001 Louisiana Street Houston, Texas	77002
(Address of Principal Executive Offices)	(Zip Code)

Telephone Number: (713) 997-1000

 Internet Website: www.epenergy.com

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

 Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).  Yes x  No o

 Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer”, “accelerated filer”, “smaller reporting company” and "emerging growth company" in Rule 12b-2 of the Exchange Act.:

Large accelerated filer o	Accelerated filer x
Non-accelerated filer o	Smaller reporting company o
(Do not check if a smaller reporting company)
Emerging Growth Company o

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No x

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

 Class A Common Stock, par value $0.01 per share. Shares outstanding as of October 19, 2017: 254,923,001

Class B Common Stock, par value $0.01 per share. Shares outstanding as of October 19, 2017: 702,754

EP ENERGY CORPORATION

TABLE OF CONTENTS

Caption		Page
PART I — FINANCIAL INFORMATION
Item 1.	Financial Statements	2
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	16
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	32
Item 4.	Controls and Procedures	32
PART II — OTHER INFORMATION
Item 1.	Legal Proceedings	33
Item 1A.	Risk Factors	33
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	33
Item 3.	Defaults Upon Senior Securities	33
Item 4.	Mine Safety Disclosures	33
Item 5.	Other Information	33
Item 6.	Exhibits	33
Signatures		35

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
Gal	=	gallons
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.

i

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

We have made statements in this document that constitute forward-looking statements, as that term is defined in the Private Securities Litigation Reform Act of 1995. Forward-looking statements include information concerning possible or assumed future results of operations. The words “believe”, “expect”, “estimate”, “anticipate” and similar expressions will generally identify forward-looking statements. These statements may relate to information or assumptions about:

• capital and other expenditures;

• financing plans;

• capital structure;

• liquidity and cash flow;

• pending legal proceedings, claims and governmental proceedings, including environmental matters;

• future economic and operating performance;

• operating income;

• management’s plans; and

• goals and objectives for future operations.

Forward-looking statements are subject to risks and uncertainties. While we believe the assumptions or bases underlying the forward-looking statements are reasonable and are made in good faith, we caution that assumed facts or bases almost always vary from actual results, and these differences can be material, depending upon the circumstances. We cannot assure you that the statements of expectation or belief contained in our forward-looking statements will result or be achieved or accomplished. Important factors that could cause actual results to differ materially from estimates or projections contained in our forward-looking statements are described in our 2016 Annual Report on Form 10-K. There have been no material changes to the risk factors described in the Form 10-K.

1

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   September 30,						Nine months ended    September 30,
	2017			2016			2017			2016
Operating revenues
Oil	$	189		$	169		$	595		$	463
Natural gas	27			27			84			94
NGLs	26			16			71			42
Financial derivatives	(23		)	43			92			(20		)
Total operating revenues	219			255			842			579
Operating expenses
Oil and natural gas purchases	—			2			2			9
Transportation costs	29			27			86			81
Lease operating expense	42			37			121			117
General and administrative	25			31			71			101
Depreciation, depletion and amortization	118			132			368			342
Loss (gain) on sale of assets	—			4			—			(78		)
Impairment charges	1			—			2			—
Exploration and other expense	6			1			10			3
Taxes, other than income taxes	16			15			50			43
Total operating expenses	237			249			710			618
Operating (loss) income	(18		)	6			132			(39		)
Gain (loss) on extinguishment of debt	24			26			(16		)	384
Interest expense	(80		)	(74		)	(245		)	(231		)
(Loss) income before income taxes	(74		)	(42		)	(129		)	114
Income tax benefit (expense)	2			(1		)	7			(1		)
Net (loss) income	$	(72	)	$	(43	)	$	(122	)	$	113
Basic net (loss) income per common share
Net (loss) income	$	(0.29	)	$	(0.18	)	$	(0.50	)	$	0.46
Basic weighted average common shares outstanding	246			245			246			245
Diluted net (loss) income per common share
Net (loss) income	$	(0.29	)	$	(0.18	)	$	(0.50	)	$	0.46
Diluted weighted average common shares outstanding	246			245			246			246

See accompanying notes.

2

EP ENERGY CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS

(In millions)

(Unaudited)

	September 30, 2017		December 31, 2016
ASSETS
Current assets
Cash and cash equivalents	$	21	$	20
Accounts receivable
Customer, net of allowance of less than $1 in 2017 and 2016	141		133
Other, net of allowance of $1 in 2017 and 2016	36		16
Income tax receivable	7		—
Materials and supplies	16		16
Derivative instruments	53		58
Prepaid assets	8		5
Total current assets	282		248
Property, plant and equipment, at cost
Oil and natural gas properties	7,616		7,194
Other property, plant and equipment	87		85
	7,703		7,279
Less accumulated depreciation, depletion and amortization	3,135		2,781
Total property, plant and equipment, net	4,568		4,498
Other assets
Derivative instruments	13		4
Unamortized debt issue costs - revolving credit facility	8		10
Other	1		1
	22		15
Total assets	$	4,872	$	4,761

See accompanying notes.

3

EP ENERGY CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS

(In millions)

(Unaudited)

	September 30, 2017			December 31, 2016
LIABILITIES AND EQUITY
Current liabilities
Accounts payable
Trade	$	74		$	63
Other	138			113
Derivative instruments	2			4
Accrued interest	83			43
Short-term debt, net of debt issue costs	21			—
Other accrued liabilities	93			98
Total current liabilities	411			321
Long-term debt, net of debt issue costs	3,933			3,789
Other long-term liabilities
Derivative instruments	—			1
Asset retirement obligations	36			40
Other	1			4
Total non-current liabilities	3,970			3,834
Commitments and contingencies (Note 8)
Stockholders’ equity
Class A shares, $0.01 par value; 550 million shares authorized; 255 million shares issued and outstanding at September 30, 2017; 251 million shares issued and outstanding at December 31, 2016	3			2
Class B shares, $0.01 par value; 0.7 million and 0.8 million shares authorized, issued and outstanding at September 30, 2017 and December 31, 2016	—			—
Preferred stock, $0.01 par value; 50 million shares authorized; no shares issued or outstanding	—			—
Treasury stock (at cost), 0.7 million shares at September 30, 2017 and 0.5 million shares at December 31, 2016	(3		)	(3		)
Additional paid-in capital	3,553			3,546
Accumulated deficit	(3,062		)	(2,939		)
Total stockholders’ equity	491			606
Total liabilities and equity	$	4,872		$	4,761

See accompanying notes.

4

EP ENERGY CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(In millions)

(Unaudited)

	Nine months ended    September 30,
	2017			2016
Cash flows from operating activities
Net (loss) income	$	(122	)	$	113
Adjustments to reconcile net (loss) income to net cash provided by operating activities
Depreciation, depletion and amortization	368			342
Gain on sale of assets	—			(78		)
Impairment charges	2			—
Loss (gain) on extinguishment of debt	16			(384		)
Other non-cash income items	24			27
Asset and liability changes
Accounts receivable	(25		)	84
Accounts payable	26			(36		)
Derivative instruments	(7		)	535
Accrued interest	40			34
Other asset changes	(12		)	4
Other liability changes	(12		)	17
Net cash provided by operating activities	298			658
Cash flows from investing activities
Cash paid for capital expenditures	(405		)	(398		)
Proceeds from the sale of assets	—			389
Cash paid for acquisitions	(29		)	—
Net cash used in investing activities	(434		)	(9		)
Cash flows from financing activities
Proceeds from issuance of long-term debt	1,645			630
Repayments and repurchases of long-term debt	(1,484		)	(1,239		)
Debt issue costs	(21		)	(24		)
Other	(3		)	(2		)
Net cash provided by (used in) financing activities	137			(635		)
Change in cash and cash equivalents	1			14
Cash and cash equivalents
Beginning of period	20			26
End of period	$	21		$	40

See accompanying notes.

5

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		Accumulated Deficit
	Shares	Amount		Shares		Amount										Total
Balance at December 31, 2016	251	$	2	0.8		$	—	$	(3	)	$	3,546	$	(2,939	)	$	606
Cumulative effect of accounting change	—	—		—		—		—			1		(1		)	—
Balance at January 1, 2017	251	$	2	0.8		$	—	$	(3	)	$	3,547	$	(2,940	)	$	606
Share-based compensation	4	1		(0.1	)	—		—			6		—			7
Net loss	—	—		—		—		—			—		(122		)	(122		)
Balance at September 30, 2017	255	$	3	0.7		$	—	$	(3	)	$	3,553	$	(3,062	)	$	491

See accompanying notes.

6

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 2016 Annual Report on

Form 10-K. The condensed consolidated financial statements as of September 30, 2017 and 2016 are unaudited. The consolidated balance sheet as of December 31, 2016 has been derived from the audited consolidated balance sheet included in our 2016 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. The results for any interim period are not necessarily indicative of the expected results for the entire year.

Significant Accounting Policies

There were no changes in significant accounting policies as described in the 2016 Annual Report on Form 10-K other than in Accounting for Long-Term Incentive Compensation. In the first quarter of 2017, we adopted Accounting Standards Update (ASU) No. 2016-09, Improvements to Employee Share-Based Payment Accounting which simplifies several aspects of the accounting for share-based payment awards to employees including accounting for income taxes, forfeitures, statutory tax withholding requirements and classification in the statement of cash flows. As permitted under ASU 2016-09, we elected to account for forfeitures in compensation cost when they occur. Upon adoption of the ASU, we recorded a cumulative adjustment of approximately $1 million to the opening balance of retained earnings as of January 1, 2017.

New Accounting Pronouncements Issued But Not Yet Adopted

The following accounting standards have been issued but not yet adopted as of September 30, 2017.

Statement of Cash Flows. In August 2016, the Financial Accounting Standards Board (FASB) issued ASU No. 2016-15, Statement of Cash Flows - Classification of Certain Cash Receipts and Cash Payments, which addresses eight specific cash flow issues with the objective of reducing the existing diversity in practice in how certain cash receipts and cash payments are presented and classified in the statement of cash flows. In November 2016, the FASB issued ASU No. 2016-18, Statement of Cash Flows - Restricted Cash, which requires restricted cash and restricted cash equivalents to be included with cash and cash equivalents when reconciling the beginning of period and end of period total amounts shown on the statement of cash flows. Retrospective application of these standards is required for fiscal years beginning after December 15, 2017, including interim periods within those fiscal years, and early adoption is allowed. We do not anticipate that the adoption of this standard will have a material impact on our consolidated statement of cash flows.

Leases.  In February 2016, the FASB issued ASU No. 2016-02, Leases, which requires lessees to recognize lease assets and lease liabilities on the balance sheet and disclose key information about leasing arrangements.  Adoption of this standard is required beginning in the first quarter of 2019 and early adoption is allowed.  We continue to evaluate our contracts and other agreements to assess the impact this update will have on our financial statements.

Revenue Recognition.  In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers, which clarifies the principles for recognizing revenue and develops a common revenue standard for U.S. GAAP and International Financial Reporting Standards. Adoption of this standard is required beginning in the first quarter of 2018. Modified or full retrospective application of this standard is required upon adoption. We do not currently anticipate our adoption of this standard in 2018, utilizing the modified retrospective approach, will have a material impact on our financial statements. We continue to evaluate disclosure requirements and assess any potential changes to our accounting policies, business processes and/or controls as a result of the provisions of this standard. 

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2. Acquisitions and Divestitures

Acquisitions. In 2017, we acquired proved and unproved properties for approximately $29 million located in the Wolfcamp area.

Divestitures. In May 2016, we completed the sale of our assets located in the Haynesville and Bossier shales for approximately $420 million (net cash proceeds of $388 million after customary adjustments). We recorded a gain on the sale of approximately $79 million, with the buyer also assuming a transportation commitment totaling $106 million.

Summarized operating results of our assets sold were as follows (in millions):

	Quarter ended September 30, 2016			Nine months ended September 30, 2016
Operating revenues	$	—		$	26
Operating expenses
Transportation costs	—			7
Lease operating expense	—			1
Depreciation, depletion and amortization	—			16
Other expense	—			5
Total operating expenses	—			29
(Loss) gain on sale of assets	(4		)	79
(Loss) income before income taxes	$	(4	)	$	76

3. Income Taxes

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 the quarter and nine months ended September 30, 2017, our effective tax rates were approximately 4% and 6%, respectively. For both the quarter and nine months ended September 30, 2016, our effective tax rates were approximately 1%. Our effective tax rates in 2017 and 2016 differed from the statutory rate primarily as a result of our recognition of a full valuation allowance on our net deferred tax assets. For the quarters ended September 30, 2017 and 2016, we recorded adjustments to the valuation allowance on our net deferred tax assets which offset deferred income tax benefit of $24 million and $16 million, respectively, and offset deferred income tax benefit and deferred income tax expense of $36 million and $43 million for the nine months ended September 30, 2017 and 2016, respectively. Our effective tax rate for the quarter and nine months ended September 30, 2017 also reflects recording a current income tax benefit and related receivable for the recovery of previously paid alternative minimum taxes based on a change in our tax depreciation elections.

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 $1 billion as of September 30, 2017.

The Company's and certain subsidiaries' income tax years (2014-2016) remain open and subject to examination by both federal and state tax authorities. During the second quarter of 2017, we concluded an examination of our 2013 U.S. tax return.

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4. 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 employee stock options, restricted stock and performance unit awards. For the quarters ended September 30, 2017 and 2016 and for the nine months ended September 30, 2017, 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. For the nine months ended September 30, 2016, approximately one million shares are included in our calculation of diluted earnings per share related to our restricted stock awards and performance units (see Note 9).

5. Fair Value Measurements

We use various methods to determine the fair values of our financial instruments. The fair value of a financial instrument depends on a number of factors, including the availability of observable market data over the contractual term of the underlying instrument. We separate the fair value of our financial instruments into three levels (Levels 1, 2 and 3) based on our assessment of the availability of observable market data and the significance of non-observable data used to determine fair value.  As of September 30, 2017 and December 31, 2016, all of our derivative financial instruments were classified as Level 2. Our assessment of the level of an instrument can change over time based on the maturity or liquidity of the instrument.

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

	September 30, 2017				December 31, 2016
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	(in millions)
Short-term debt	$	21	$	19	$	—	$	—
Long-term debt (see Note 7)	$	3,982	$	3,265	$	3,856	$	3,637
Derivative instruments	$	64	$	64	$	57	$	57

As of September 30, 2017 and December 31, 2016, the carrying amount of cash and cash equivalents, accounts receivable and accounts payable represent fair value because of the short-term nature of these instruments. 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 September 30, 2017, we had derivative contracts in the form of fixed price swaps and three-way collars on 11 MMBbls of oil (2 MMBbls in 2017 and 9 MMBbls in 2018). In addition to our oil derivatives, we had derivative contracts in the form of fixed price swaps and options on 42 TBtu of natural gas (9 TBtu in 2017, 26 TBtu in 2018 and 7 TBtu in 2019) and 117 MMGal of ethane and propane fixed price swaps (25 MMGal in 2017 and 92 MMGal in 2018). As of December 31, 2016, we had fixed price derivative contracts for 16 MMBbls of oil, 36 TBtu on natural gas and 108 MMGal on ethane. In addition to the contracts above, we have derivative contracts related to locational basis differences on our oil and natural gas production. None of our derivative contracts are designated as accounting hedges.

The following table presents the fair value associated with our derivative financial instruments as of September 30, 2017 and December 31, 2016. 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.

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	Level 2
	Derivative Assets									Derivative Liabilities
	Gross Fair Value					Balance Sheet Location				Gross Fair Value					Balance Sheet Location
			Impact of Netting			Current		Non- current					Impact of Netting		Current			Non- current
	(in millions)									(in millions)
September 30, 2017
Derivative instruments	$	75	$	(9	)	$	53	$	13	$	(11	)	$	9	$	(2	)	$	—
December 31, 2016
Derivative instruments	$	79	$	(17	)	$	58	$	4	$	(22	)	$	17	$	(4	)	$	(1	)

     For the quarters ended September 30, 2017 and 2016, we recorded a derivative loss of $23 million and a derivative gain of $43 million, respectively. For the nine months ended September 30, 2017 and 2016, we recorded a derivative gain of $92 million and a derivative loss of $20 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. 

6.  Property, Plant and Equipment

Oil and Natural Gas Properties.  As of both September 30, 2017 and December 31, 2016, we had approximately $4.5 billion 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 and unproved oil and natural gas properties.

Our capitalized costs related to proved and unproved oil and natural gas properties by area were as follows:

	September 30, 2017		December 31, 2016
	(in millions)
Proved
Eagle Ford	$	3,127	$	3,001
Wolfcamp	2,678		2,415
Altamont	1,684		1,624
Total Proved	7,489		7,040
Unproved
Wolfcamp	66		94
Altamont	62		60
Total Unproved	128		154
Less accumulated depletion	3,077		2,731
Net capitalized costs for oil and natural gas properties	$	4,540	$	4,463

During the nine months ended September 30, 2017, we transferred approximately $51 million from unproved properties to proved properties. For the quarters ended September 30, 2017 and 2016, we recorded approximately $2 million and $1 million, respectively, of amortization of unproved leasehold costs in exploration expense in our consolidated income statements. For the nine months ended September 30, 2017 and 2016, we recorded approximately $4 million and $1 million, respectively, of amortization of unproved leasehold costs. Suspended well costs were not material as of September 30, 2017 or December 31, 2016. 

We evaluate capitalized costs related to proved properties upon a triggering event (such as a significant and sustained decline in forward commodity prices) to determine if an impairment of such properties has occurred. Capitalized costs associated with unproved properties (e.g. leasehold acquisition costs associated with non-producing areas) are also assessed upon a triggering event for impairment based on estimated drilling plans and capital expenditures which may also change based on forward commodity price changes and/or potential lease expirations. Commodity price declines may cause changes to our capital spending levels, production rates, levels of proved reserves and development plans, which may result in an impairment of the carrying value of our proved and/or unproved properties in the future.

10

Generally, economic recovery of unproved reserves in non-producing or unproved areas is not yet supported by actual production or conclusive formation tests, but may be confirmed by continuing exploration and development activities.  Our ability to retain our leases and thus recover our non-producing leasehold costs is dependent upon a number of factors including our levels of drilling activity, which may include drilling the acreage on our own behalf or jointly with partners, or our ability to modify or extend our leases. Should commodity prices not justify sufficient capital allocation to the continued development of properties where we have non-producing leasehold costs, we could incur impairment charges of our unproved property costs.

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

In estimating the liability associated with our asset retirement obligations, we utilize several assumptions, including a credit-adjusted risk-free rate between 7 percent and 9 percent on a significant portion of our obligations and a projected inflation rate of 2.5 percent. Changes in estimates represent changes to the expected amount and timing of payments to settle our asset retirement obligations. Typically, these changes primarily result from obtaining new information about the timing of our obligations to plug and abandon oil and natural gas wells and the costs to do so, or reassessing our assumptions in light of changing market conditions. The net asset retirement liability as of September 30, 2017 on our consolidated balance sheet in other current and non-current liabilities and the changes in the net liability from January 1 through September 30, 2017 were as follows:

	2017
	(in millions)
Net asset retirement liability at January 1	$	41
Liabilities settled	(1		)
Accretion expense	3
Changes in estimate	(5		)
Net asset retirement liability at September 30	$	38

Capitalized Interest.  Interest expense is reflected in our financial statements net of capitalized interest. We capitalize

interest primarily on the costs associated with drilling and completing wells until production begins. The interest rate used is

the weighted average interest rate of our outstanding borrowings. Capitalized interest for both of the quarters and nine months ended September 30, 2017 and 2016 were approximately $1 million and $3 million, respectively.

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7. Long-Term Debt

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

	Interest Rate	September 30, 2017			December 31, 2016
		(in millions)
RBL credit facility - due May 24, 2019(1)	Variable	$	505		$	370
Senior secured term loans:
Due May 24, 2018(2)	Variable	21			21
Due April 30, 2019(3)	Variable	8			8
Due June 30, 2021(4)	Variable	—			580
Senior secured notes:
Due November 29, 2024	8.00%	500			500
Due February 15, 2025	8.00%	1,000			—
Senior unsecured notes:
Due May 1, 2020	9.375%	1,200			1,576
Due September 1, 2022	7.75%	250			250
Due June 15, 2023	6.375%	519			551
Total debt		4,003			3,856
Less short-term debt, net of debt issue costs of less than $1 million		(21		)	—
Total long-term debt		3,982			3,856
Less non-current portion of unamortized debt issue costs		(49		)	(67		)
Total long-term debt, net		$	3,933		$	3,789

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

(2)Issued at 99% of par and carries interest at a specified margin over the LIBOR of 2.75%, with a minimum LIBOR floor of 0.75%. As of September 30, 2017 and December 31, 2016, the effective interest rate of the term loan was 4.07% and 3.50%, respectively.

(3)Carries interest at a specified margin over the LIBOR of 3.50%, with a minimum LIBOR floor of 1.00%. As of September 30, 2017 and December 31, 2016, the effective interest rate for the term loan was 4.82% and 4.50%, respectively.

(4) As of December 31, 2016, the effective interest rate for the term loan was 9.75%.

During the first quarter of 2017, we issued $1 billion of 8.00% senior secured notes which mature in 2025 and used the proceeds (less fees and expenses) to (i) repay in full our $580 million senior secured term loans due 2021, (ii) repurchase $250 million in aggregate principal amount of our 9.375% senior unsecured notes due 2020 and (iii) repay $111 million of the amounts outstanding under our Reserve-Based Loan facility (RBL Facility). As a result of the issuance, our RBL Facility borrowing base was also reduced from $1.5 billion to $1.44 billion. In conjunction with these transactions, we recorded a loss on extinguishment of debt of approximately $53 million (including $30 million in non-cash expense related to eliminating associated unamortized debt issue costs and debt discounts).

In 2017 and 2016, we also repurchased additional debt as follows:

	Quarter ended September 30,		Nine months ended September 30,
	2017	2016	2017	2016
	(in millions)
Debt repurchased - face value(1)	101	75	157	812
Cash paid	76	47	118	407
Gain on extinguishment of debt(2)(3)	24	26	37	393

(1) In 2017, repurchases were associated with 2020 and 2023 senior unsecured notes. In 2016, repurchases were associated with certain senior unsecured notes and term loans.

(2) Includes $1 million and $2 million, for the quarter and nine months ended September 30, 2017, respectively, and $1 million and $12 million for the quarter and nine months ended September 30, 2016, respectively, of non-cash expense related to eliminating associated unamortized debt issue costs.

(3) For the nine months ended September 30, 2016, we also recorded a loss on the extinguishment of debt of approximately $9 million primarily related to eliminating a portion of the unamortized debt issue costs due to the reduction of our RBL borrowing base in May 2016.

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Unamortized Debt Issue Costs. As of September 30, 2017 and December 31, 2016, we had total unamortized debt issue costs of $57 million and $77 million. Of these amounts, $8 million and $10 million, respectively, are associated with our RBL Facility and reflected as other assets, while $49 million and $67 million, respectively, are associated with our senior secured term loans and senior notes and reflected net in our debt balances.

Reserve-based Loan Facility. We have a RBL Facility in place which allows us to borrow funds or issue letters of credit. The facility matures in May 2019. As of September 30, 2017, we had $913 million of available capacity remaining with $19 million of letters of credit issued and $505 million outstanding under the 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 October 2017 our RBL borrowing base was affirmed at $1.4 billion. 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 credit agreements and our ability to incur additional indebtedness is subject to various financial and non-financial covenants and restrictions. In conjunction with the redetermination of our RBL Facility in April 2017, we extended our first lien debt to EBITDAX covenant through March 31, 2019 and the ratio was reduced to 3.0 to 1.0. In April 2019, this financial covenant will revert to a requirement that our total net debt to EBITDAX ratio not exceed 4.5 to 1.0. As of September 30, 2017, we were in compliance with our debt covenants, and our ratio of first lien debt to EBITDAX was 0.66x while our ratio of total net debt to EBITDAX was 5.21x.

Under our RBL Facility, we are also limited in non-RBL Facility debt repurchases to $350 million, subject to certain adjustments. As of September 30, 2017, the non-RBL Facility debt repurchases limit was approximately $885 million as a result of divestitures and financing transactions and will continue to be subject to future adjustments. Certain other covenants and restrictions, among other things, also limit or place certain conditions on our ability to incur or guarantee additional indebtedness; make any restricted payments or pay any dividends on equity interests or redeem, repurchase or retire equity interests or subordinated indebtedness; sell assets; make investments; create certain liens; prepay debt obligations; engage in transactions with affiliates; and enter into certain hedging agreements.

8. 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 September 30, 2017, we had approximately $7 million accrued for all outstanding legal matters. 

FairfieldNodal v. EP Energy E&P Company, L.P. In 2014, Fairfield filed suit against one of our subsidiaries in a Texas district court, claiming we were contractually obligated to pay a transfer fee of approximately $21 million for seismic licensing, triggered by a change in control with the Sponsors' acquisition of our predecessor entity in 2012. Prior to the change in control, we had unilaterally terminated the seismic licensing agreements, and we returned the applicable seismic data. Fairfield also claimed EP Energy did not properly maintain the confidentiality of the seismic data and interpretations made from it. In April 2015, the district court granted summary judgment to EP Energy, and Fairfield then appealed. On July 6, 2017, an intermediate court of appeals in Texas reversed the judgment related to the transfer fee and denied rehearing on October 5, 2017. We intend to appeal this court's ruling to the Texas Supreme Court. At this time, we are unable to estimate the amount or range of possible loss, if any, on this matter.

Indemnifications and Other Matters. We periodically enter into indemnification arrangements 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, environmental and other contingent matters. In addition, under various laws or regulations, we could be subject to the imposition of certain liabilities. For example, 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

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required to assume all, or a portion of the plugging or abandonment obligations on assets we no longer own or operate. As of September 30, 2017, we had approximately $5 million accrued related to these indemnifications and other matters.

Non-Income Tax Matters. We are under a number of examinations by taxing authorities related to non-income tax matters. As of September 30, 2017, we had approximately $41 million accrued (in other accrued liabilities in our consolidated balance sheet) in connection with ongoing examinations related to certain prior period non-income tax matters.

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 2016 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.

9. Long-Term Incentive Compensation

Our long-term incentive (LTI) programs consist of restricted stock, stock options and performance unit awards.

Restricted Stock. A summary of the changes in our non-vested restricted shares for the nine months ended September 30, 2017 is presented below:

	Number of Shares		Weighted Average Grant Date Fair Value per Share
Non-vested at December 31, 2016	6,326,788		$	7.69
Granted	5,142,527		$	4.28
Vested	(2,144,100	)	$	8.28
Forfeited	(715,502	)	$	7.10
Non-vested at September 30, 2017	8,609,713		$	5.56

Performance Unit Awards. A summary of the changes in our performance unit awards for the nine months ended September 30, 2017 is presented below:

	Number of Awards		Weighted Average Fair Value
Non-vested at December 31, 2016	78,900		$	97.77
Granted(1)	40,470		$	36.57
Vested	(22,302	)	$	159.92
Forfeited	(12,000	)	$	159.92
Non-vested at September 30, 2017	85,068		$	48.16

(1) Grant date fair value at March 16, 2017 is based on: (i) an expected term of 3 years, (ii) expected volatility of 96.71%, which is based upon the historical stock price volatility and (iii) a risk-free interest rate of 1.57%, based upon the yield on U.S. Treasury STRIPS over the expected term as of the grant date.

Our performance unit awards are treated as liability awards for accounting purposes with the expense recognized on an accelerated basis and fair value remeasured at each reporting period. During the nine months ended September 30, 2017, we paid approximately $4 million in connection with awards that vested and had accrued approximately $2 million related to

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unvested outstanding performance unit awards. Performance unit awards may be settled in either stock or cash at the election of the board of directors. Had all outstanding performance unit awards at September 30, 2017 vested and been settled in stock, approximately two million shares would have been issued. Refer to our 2016 Annual Report on Form 10-K for further description 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 $5 million for both of the quarters ended September 30, 2017 and 2016 and $10 million and $15 million for the nine months ended September 30, 2017 and 2016, respectively. Included in pre-tax compensation expense for the nine months ended September 30, 2017 was approximately $7 million of forfeitures recorded during the first quarter of 2017. As of September 30, 2017, we had unrecognized compensation expense of $51 million.  We will recognize an additional $6 million related to our outstanding awards during the remainder of 2017, $33 million over the remaining requisite service periods subsequent to 2017 and $12 million should a specified capital transaction occur and the right to such amounts become non-forfeitable.

10. Related Party Transactions

Affiliate Payments.  In connection with the release of members of the leadership team of a portfolio company of funds managed by Apollo affiliates to join the Company, the Company reimbursed that portfolio company approximately $4 million for money contributed to it by fund investors (other than Apollo).

Joint Venture. In January 2017, we entered into a drilling joint venture with Wolfcamp Drillco Operating L.P. (the

Investor), which is managed and controlled by an affiliate of Apollo Global Management LLC, to fund future oil and natural gas development in our Wolfcamp program. Subsequently, Access Industries acquired an indirect minority ownership interest in the Investor and therefore is also indirectly responsible for funding a portion of the Investor’s capital commitment. The Investor is anticipated to fund approximately $450 million over the entire program (150 wells in two separate 75 well tranches), or approximately 60 percent of the estimated drilling, completion and equipping costs of the wells, in exchange for a 50 percent working interest in the joint venture wells.  Once the Investor achieves a 12 percent internal rate of return on its invested capital in each tranche, its working interest reverts to 15 percent.  We are the operator of the joint venture assets and the transaction increases our well-level returns on the jointly developed wells.  The first wells under the joint venture began producing in January 2017, and for the nine months ended September 30, 2017, we recovered approximately $193 million related to the capital costs of the joint venture wells from the Investor and have drilled and completed 51 wells.

Affiliate Supply Agreement.  For the nine months ended September 30, 2017 and 2016, we recorded approximately $1 million and $6 million in capital expenditures for amounts expended under supply agreements entered into with an affiliate of Apollo Global Management, LLC to provide certain materials used in our Eagle Ford drilling operations.

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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 our 2016 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 development and acquisition 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 creating shareholder value through the development of our drilling inventory located in three core areas: the Wolfcamp Shale (Permian Basin in West Texas), the Eagle Ford Shale (South Texas), and the Altamont Field in the Uinta Basin (Northeastern Utah). 

We evaluate growth opportunities for our asset portfolio that are aligned with our core competencies and that are in areas that we believe can provide us a competitive advantage. Strategic acquisitions of leasehold acreage or acquisitions of producing assets can provide opportunities to achieve our long-term goals by leveraging existing expertise in our core areas, balancing our exposure to regions, basins and commodities, helping us to achieve risk-adjusted returns competitive with those available within our existing drilling programs and by increasing our reserves. We continuously evaluate our asset portfolio and will also sell oil and natural gas properties if they no longer meet our long-term goals. In 2017, we acquired proved and unproved properties for approximately $29 million located in the Wolfcamp area.

From time to time, we will also enter into joint ventures to enhance the development, hold acreage and/or improve near-term economics in our programs. In January and May 2017, we entered into drilling joint ventures in our Wolfcamp and Altamont programs. In Wolfcamp, our partner is participating in the development of up to 150 wells in two separate 75 well tranches primarily in Reagan and Crockett counties. Our joint venture investor is anticipated to fund approximately $450 million over the entire program, or approximately 60 percent of the estimated drilling, completion and equipping costs of the wells in exchange for a 50 percent working interest in the joint venture wells. The first wells under the joint venture began producing in January 2017 and as of September 30, 2017, we have drilled and completed 51 wells. In Altamont, our partner is participating in the development of 60 wells and will provide a capital carry in exchange for 50 percent working interest in the joint venture wells. The first wells under the joint venture began producing in July 2017 and as of September 30, 2017, we have drilled and completed 7 wells. We are the operator of the assets in both joint ventures.

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 costs; and

•managing commodity price risks on our oil and natural gas production. 

In addition to these factors, our future profitability and performance will be affected by volatility in the financial and commodity markets, changes in the cost of drilling and oilfield services, operating and capital costs, and our debt level and related interest costs. Future commodity price declines may cause changes to our future capital spending levels, production rates, levels of proved reserves and development plans, all of which impact performance. Additionally, we may be impacted by weather events, regulatory issues or other third party actions outside of our control.

Forward commodity prices play a significant role in determining the recoverability of proved or unproved property

costs on our balance sheet. Future price declines, along with changes to our future capital spending levels, production rates, levels of proved reserves and development plans may result in an impairment of the carrying value of our proved and/or unproved 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 the commodity and (ii) other contractual pricing adjustments contained in our underlying sales contracts.  In order to stabilize cash flows and protect the economic assumptions associated with our capital investment programs, we enter into financial derivative contracts to reduce the financial impact of downward commodity price movements and unfavorable movements in locational prices. Adjustments to our strategy and the decision to enter into new contracts or positions 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.

During the nine months ended September 30, 2017, we (i) settled commodity index hedges on approximately 65% of our oil production, 57% of our total liquids production and on 68% of our natural gas production at average floor prices of $61.00 per barrel of oil, $0.44 per gallon of NGLs and $3.27 per MMBtu of natural gas, respectively. To the extent our oil and natural gas production is unhedged, either from a commodity index or locational price perspective, our operating revenues will be impacted from period to period. The following table and discussion that follows reflects the contracted volumes and the prices we will receive under derivative contracts we held as of September 30, 2017.

	2017				2018				2019
	Volumes(1)	Average Price(1)			Volumes(1)	Average Price(1)			Volumes(1)	Average Price(1)
Oil
Fixed Price Swaps
WTI	276	$	58.05		—	$	—		—	$	—
Three Way Collars
Ceiling - WTI	2,226	$	70.37		8,859	$	68.15		—	$	—
Floors - WTI	2,226	$	60.62		8,859	$	60.00		—	$	—
Sub-Floor - WTI	2,226	$	46.24		8,859	$	50.00		—	$	—
Basis Swaps
LLS vs. Brent(2)	920	$	(3.14	)	—	$	—		—	$	—
Midland vs. Cushing(3)	920	$	(0.82	)	4,380	$	(1.02	)	—	$	—
LLS vs. WTI(4)	920	$	2.42		3,285	$	2.41		—	$	—
Natural Gas
Fixed Price Swaps	6	$	3.25		26	$	3.04		7	$	2.97
Ceiling	3	$	3.67		—	$	—		—	$	—
Floors	3	$	3.35		—	$	—		—	$	—
Basis Swaps
WAHA vs. Henry Hub(5)	4	$	(0.34	)	15	$	(0.46	)	7	$	(0.39	)
NGLs
Fixed Price Swaps - Ethane	15	$	0.27		61	$	0.30		—	$	—
Fixed Price Swaps - Propane	10	$	0.67		31	$	0.75		—	$	—

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

(2) EP Energy receives Brent plus the basis spread listed and pays LLS. These positions listed do not include offsetting LLS vs. Brent basis swaps on our 0.92 MMBbls LLS vs. Brent with an average of $(0.46) per barrel of oil.

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

(4) EP Energy receives WTI plus the basis spread listed and pays LLS.

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

For our three-way collar contracts in the table above, the sub-floor prices represent the price below which we receive WTI plus a weighted average spread of $14.38 in 2017 and WTI plus a weighted average spread of $10.00 in 2018 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 above, at which time we receive the fixed ceiling price. As of September 30, 2017, the average forward price of oil was $51.08 per barrel of oil for the remainder of 2017 and $51.85 per barrel of oil for 2018.

For the period from October 1, 2017 through November 1, 2017, we entered into derivative contracts on 0.7 MMBbls of 2018 LLS vs. WTI basis swaps with an average price of $3.04 per barrel of oil.

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Summary of Liquidity and Capital Resources.  As of September 30, 2017, we had available liquidity of approximately $934 million, reflecting $913 million of available liquidity on our Reserve-Based Loan facility (RBL Facility) borrowing base and $21 million of available cash. In 2017, we have taken steps to improve our liquidity and expand our financial flexibility by (i) issuing $1 billion of 8.00% senior secured notes which mature in 2025 and using the net proceeds to repay in full senior secured term loans due 2021, repurchase senior notes, and repay a portion of the amounts outstanding under our RBL Facility and (ii) repurchasing for cash a total of $157 million in aggregate principal amount of senior unsecured notes due 2020 and 2023 for approximately $118 million. In addition, in April 2017, we amended our credit agreement, extending the first lien debt to EBITDAX covenant through March 31, 2019, reducing it such that the ratio of first lien debt to EBITDAX may not exceed 3.0 to 1.0. In October 2017, we also affirmed the borrowing base of our RBL Facility at $1.4 billion. For a further discussion of our liquidity and capital resources, including factors that could impact our liquidity, see Liquidity and Capital Resources.

Outlook. For the full year 2017, we expect to spend approximately $550 million to $600 million in capital in our programs, with approximately $250 million to $300 million in the Wolfcamp Shale, approximately $200 million in the Eagle Ford Shale and approximately $100 million in Altamont. We anticipate 140 to 160 gross well completions, and our average daily production volumes for the year to be approximately 80 MBoe/d to 85 MBoe/d, including average daily oil production volumes of approximately 46 MBbls/d to 48 MBbls/d.

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Production Volumes and Drilling Summary

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

	2017	2016
Equivalent Volumes (MBoe/d)
Wolfcamp Shale	27.6	19.3
Eagle Ford Shale	37.4	45.5
Altamont	17.8	16.2
Other(1)	—	8.4
Total	82.8	89.4
Oil (MBbls/d)	47.0	46.9
Natural Gas (MMcf/d)(1)	126	169
NGLs (MBbls/d)	14.8	14.3

(1) For the nine months ended September 30, 2016, natural gas volumes included 50 MMcf/d from the Haynesville Shale.

• Wolfcamp Shale—Our Wolfcamp Shale equivalent volumes increased8.3 MBoe/d (approximately 43%) and oil production increased by 3.5 MBbls/d (approximately 45%) for the nine months ended September 30, 2017 compared to the same period in 2016. During the nine months ended September 30, 2017, we completed 64 additional operated wells, for a total of 328 net operated wells as of September 30, 2017.

• Eagle Ford Shale—Our Eagle Ford Shale equivalent volumes decreased8.1 MBoe/d (approximately 18%) and oil production decreased by 4.5 MBbls/d (approximately 16%) for the nine months ended September 30, 2017 compared to the same period in 2016. During the nine months ended September 30, 2017, we completed 39 additional operated wells in the Eagle Ford, for a total of 636 net operated wells as of September 30, 2017.

• Altamont—Our Altamont equivalent volumes increased1.6 MBoe/d (approximately 10%) and oil production increased by 1.1 MBbls/d (approximately 10%) for the nine months ended September 30, 2017 compared to the same period in 2016. During the nine months ended September 30, 2017, we completed 16 additional operated oil wells, for a total of 373 net operated wells as of September 30, 2017.

Our production declines in our Eagle Ford area reflect natural declines and the slowed pace of development in our drilling program due to reduced capital spending in 2016, while increases in Wolfcamp reflect incremental capital allocated to this program in 2016 and 2017. Future volumes across all our assets will be impacted by the level of natural declines, and the level and timing of capital spending in each respective asset. In the current commodity price environment, we may continue to have low spending levels which may result in lower produced volumes in the future.

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Results of Operations

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

	Quarter ended   September 30,						Nine months ended    September 30,
	2017			2016			2017			2016
	(in millions)
Operating revenues
Oil	$	189		$	169		$	595		$	463
Natural gas	27			27			84			94
NGLs	26			16			71			42
Total physical sales	242			212			750			599
Financial derivatives	(23		)	43			92			(20		)
Total operating revenues	219			255			842			579
Operating expenses
Oil and natural gas purchases	—			2			2			9
Transportation costs	29			27			86			81
Lease operating expense	42			37			121			117
General and administrative	25			31			71			101
Depreciation, depletion and amortization	118			132			368			342
Loss (gain) on sale of assets	—			4			—			(78		)
Impairment charges	1			—			2			—
Exploration and other expense	6			1			10			3
Taxes, other than income taxes	16			15			50			43
Total operating expenses	237			249			710			618
Operating (loss) income	(18		)	6			132			(39		)
Gain (loss) on extinguishment of debt	24			26			(16		)	384
Interest expense	(80		)	(74		)	(245		)	(231		)
(Loss) income before income taxes	(74		)	(42		)	(129		)	114
Income tax benefit (expense)	2			(1		)	7			(1		)
Net (loss) income	$	(72	)	$	(43	)	$	(122	)	$	113

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Operating Revenues

The table below provides our operating revenues, volumes and prices per unit for the quarters and nine months ended September 30, 2017 and 2016. We present (i) average realized prices based on physical sales of oil, natural gas and NGLs as well as (ii) average realized prices inclusive of the impacts of financial derivative settlements and premiums which reflect cash received or paid during the respective period.

	Quarter ended   September 30,					Nine months ended    September 30,
	2017			2016		2017		2016
	(in millions)
Operating revenues:
Oil	$	189		$	169	$	595	$	463
Natural gas	27			27		84		94
NGLs	26			16		71		42
Total physical sales	242			212		750		599
Financial derivatives	(23		)	43		92		(20		)
Total operating revenues	$	219		$	255	$	842	$	579
Volumes:
Oil (MBbls)	4,153			4,137		12,824		12,861
Natural gas (MMcf)(1)	11,563			11,177		34,381		46,281
NGLs (MBbls)	1,376			1,326		4,058		3,908
Equivalent volumes (MBoe)(1)	7,456			7,326		22,612		24,483
Total MBoe/d(1)	81.0			79.6		82.8		89.4
Prices per unit(2):
Oil
Average realized price on physical sales ($/Bbl)(3)	$	45.49		$	40.85	$	46.38	$	35.96
Average realized price, including financial derivatives ($/Bbl)(3)(4)	$	51.75		$	74.97	$	52.82	$	74.96
Natural gas
Average realized price on physical sales ($/Mcf)(3)	$	2.26		$	2.24	$	2.38	$	1.85
Average realized price, including financial derivatives ($/Mcf)(3)(4)	$	2.49		$	2.53	$	2.48	$	2.09
NGLs
Average realized price on physical sales ($/Bbl)	$	18.98		$	12.02	$	17.53	$	10.71
Average realized price, including financial derivatives ($/Bbl)(4)	$	18.45		$	12.23	$	17.58	$	10.98

(1) For the nine months ended September 30, 2016, Haynesville Shale production volumes were 13,589 MMcf of natural gas and 2,266 MBoe (8.3 MBoe/d) of equivalent volumes.

(2) Natural gas prices for the quarter and nine months ended September 30, 2017 reflect operating revenues for natural gas reduced by less than $1 million and approximately $2 million, respectively, for natural gas purchases associated with managing our physical sales. Natural gas prices for the quarter and nine months ended September 30, 2016 reflect operating revenues for natural gas reduced by approximately $1 million and $8 million, respectively, for natural gas purchases associated with managing our physical sales. Oil prices for the quarter and nine months ended September 30, 2016 reflect operating revenues for oil reduced by less than $1 million and approximately $1 million, respectively, for oil purchases associated with managing our physical sales.

(3) Changes in realized oil and natural gas prices reflect the effects of unfavorable 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.

(4) The quarters ended September 30, 2017 and 2016, include cash received of approximately $26 million and $141 million, respectively, for the settlement of crude oil derivative contracts and approximately $2 million and $3 million, respectively, for the settlement of natural gas financial derivatives. The nine months ended September 30, 2017 and 2016, include cash received of approximately $83 million and $502 million, respectively, for the settlement of crude oil derivative contracts and approximately $3 million and $11 million, respectively, for the settlement of natural gas financial derivatives. The quarters ended September 30, 2017 and 2016 include cash paid of approximately $1 million and cash received of less than $1 million for the settlement of NGLs derivative contracts. The nine months ended September 30, 2017 and 2016 include cash received of less than $1 million and approximately $1 million for the settlement of NGLs derivative contracts.

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Physical sales.  Physical sales represent accrual-based commodity sales transactions with customers. For the quarter and nine months ended September 30, 2017, physical sales increased by $30 million (14%) and $151 million (25%), respectively, compared to the same periods in 2016. Physical sales have increased in both the quarter and nine month periods in 2017 primarily due to higher commodity prices. The table below displays the price and volume variances on our physical sales when comparing the quarter and nine months ended September 30, 2017 and 2016.

	Quarter ended
	Oil		Natural gas			NGLs		Total
	(in millions)
September 30, 2016 sales	$	169	$	27		$	16	$	212
Change due to prices	19		(1		)	10		28
Change due to volumes	1		1			—		2
September 30, 2017 sales	$	189	$	27		$	26	$	242

	Nine months ended
	Oil			Natural gas			NGLs		Total
	(in millions)
September 30, 2016 sales	$	463		$	94		$	42	$	599
Change due to prices	133			14			27		174
Change due to volumes	(1		)	(24		)	2		(23		)
September 30, 2017 sales	$	595		$	84		$	71	$	750

Oil sales for the quarter and nine months ended September 30, 2017, compared to the same periods in 2016, increased by $20 million (12%) and $132 million (29%), respectively, due primarily to higher oil prices and higher oil production in Wolfcamp and Altamont. Partially offsetting this increase was a decrease in oil volumes in Eagle Ford reflecting the slowed pace of development of that program in 2016 and 2017. For the quarter and nine months ended September 30, 2017 compared to the same periods in 2016, Eagle Ford oil production decreased by 17% (4.0 MBbls/d) and 16% (4.5 MBbls/d), respectively.

Natural gas sales remained flat for the quarter ended September 30, 2017 and decreased by $10 million (11%) for the nine months ended September 30, 2017 compared to the same periods in 2016. The decrease for the nine months ended September 30, 2017, was primarily due to lower volumes from the sale of Haynesville Shale assets in May 2016, which produced a total of 50 MMcf/d of natural gas for the nine months ended September 30, 2016. Partially offsetting this decrease were higher natural gas prices and higher natural gas volumes in Wolfcamp and Altamont.

Our oil, natural gas and NGLs are sold at index prices (WTI, 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 to benchmark LLS crude oil.  In Wolfcamp, physical barrels are generally sold at the WTI Midland Index, which trades at a spread to WTI Cushing.  In Altamont, market pricing of our oil is based upon NYMEX based agreements which reflect a locational difference at the wellhead.  Across all regions, natural gas realized pricing is influenced by factors such as excess royalties paid on flared gas and the percentage of proceeds retained under processing contracts, in addition to the normal seasonal supply and demand influences and those factors discussed above. The table below displays the weighted average differentials and deducts on our oil and natural gas sales on an average NYMEX price.

	Quarter ended September 30,
	2017						2016
	Oil (Bbl)			Natural gas (MMBtu)			Oil (Bbl)			Natural gas (MMBtu)
Differentials and deducts	$	(2.87	)	$	(0.76	)	$	(4.27	)	$	(0.57	)
NYMEX	$	48.21		$	3.00		$	44.94		$	2.81
Net back realization %	94.0		%	74.7		%	90.5		%	79.7		%

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	Nine months ended September 30,
	2017						2016
	Oil (Bbl)			Natural gas (MMBtu)			Oil (Bbl)			Natural gas (MMBtu)
Differentials and deducts	$	(3.30	)	$	(0.79	)	$	(5.38	)	$	(0.44	)
NYMEX	$	49.47		$	3.17		$	41.33		$	2.29
Net back realization %	93.3		%	75.1		%	87.0		%	80.8		%

     The higher oil realization percentage in the quarter and nine months ended September 30, 2017 was primarily a result of improved LLS to WTI basis spread in Eagle Ford and improved physical sales contracts in all programs. The lower natural gas realization percentage in the quarter and nine months ended September 30, 2017 was primarily a result of the impact of the sale of our Haynesville assets and its associated lower basis differentials. Also impacting the lower natural gas realization percentage in 2017 was the impact on basis differentials in Wolfcamp due to constrained natural gas takeaway capacity in the basin.

NGLs sales increased by $10 million (63%) and $29 million (69%), respectively, for the quarter and nine months ended September 30, 2017 compared with the same periods in 2016. Average realized prices for the quarter and nine months ended September 30, 2017 were higher compared to the same periods in 2016, due to higher pricing on all liquids components. NGLs pricing is largely tied to crude oil prices. NGLs volumes increased approximately 4% for both the quarter and nine months ended September 30, 2017 compared to the same periods in 2016 due to NGLs volume growth in Wolfcamp.

Future growth in our overall oil and natural gas sales (including the impact of financial derivatives) will largely be impacted by commodity pricing, our level of hedging, our ability to maintain or grow oil volumes and by the location of our production and the nature of our sales contracts. 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 quarter ended September 30, 2017, we recorded $23 million of derivative losses compared to derivative gains of $43 million during the quarter ended September 30, 2016. For the nine months ended September 30, 2017, we recorded derivative gains of $92 million compared to derivative losses of $20 million during the nine months ended September 30, 2016. 

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Operating Expenses

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

	Quarter ended September 30,
	2017				2016
	Total		Per Unit(1)		Total		Per Unit(1)
	(in millions, except per unit costs)
Operating expenses
Oil and natural gas purchases	$	—	$	—	$	2	$	0.25
Transportation costs	29		3.91		27		3.71
Lease operating expense	42		5.66		37		5.13
General and administrative(2)	25		3.28		31		4.21
Depreciation, depletion and amortization	118		15.92		132		17.97
Loss on sale of assets	—		—		4		0.53
Impairment charges	1		0.09		—		—
Exploration and other expense	6		0.83		1		0.21
Taxes, other than income taxes	16		2.10		15		1.94
Total operating expenses	$	237	$	31.79	$	249	$	33.95
Total equivalent volumes (MBoe)	7,456				7,326

	Nine months ended September 30,
	2017				2016
	Total		Per Unit(1)		Total			Per Unit(1)
	(in millions, except per unit costs)
Operating expenses
Oil and natural gas purchases	$	2	$	0.08	$	9		$	0.37
Transportation costs	86		3.80		81			3.32
Lease operating expense	121		5.36		117			4.78
General and administrative(2)	71		3.13		101			4.14
Depreciation, depletion and amortization	368		16.29		342			13.97
Gain on sale of assets	—		—		(78		)	(3.20		)
Impairment charges	2		0.06		—			—
Exploration and other expense	10		0.47		3			0.13
Taxes, other than income taxes	50		2.22		43			1.73
Total operating expenses	$	710	$	31.41	$	618		$	25.24
Total equivalent volumes (MBoe)	22,612				24,483

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

(2) For the quarter and nine months ended September 30, 2017, amount includes approximately $5 million or $0.65 per Boe and $7 million or $0.30 per Boe, respectively, of non-cash compensation expense. For the quarter ended September 30, 2016, amount includes approximately $5 million or $0.74 per Boe of non-cash compensation expense. For the nine months ended September 30, 2016, amount includes approximately $10 million or $0.41 per Boe of transition and severance costs related to workforce reductions and $12 million or $0.49 per Boe of non-cash compensation expense.

Oil and natural gas purchases.  From time to time, we purchase and sell oil and natural gas to improve the prices we would otherwise receive for our oil and natural gas or to manage firm transportation agreements. Oil and natural gas purchases for the quarter and nine months ended September 30, 2017decreased by $2 million and $7 million, respectively, compared to the same periods in 2016 primarily due to fewer transactions following the sale of our Haynesville assets in May 2016.

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Transportation costs.  Transportation costs for the quarter and nine months ended September 30, 2017increased by $2 million and $5 million, respectively, compared to the same periods in 2016 due to an increase in gas transportation costs in Wolfcamp as a result of production growth in that area and certain legacy transportation commitments that commenced in August 2016.

Lease operating expense.  Lease operating expense increased for the quarter and nine months ended September 30, 2017 compared to the same periods in 2016 by $5 million and $4 million, respectively. The increase for the quarter ended September 30, 2017 compared to 2016 is due to higher maintenance, repair, disposal and chemical costs in Wolfcamp, higher chemical costs in Eagle Ford and higher power and fuel costs in Altamont. For the nine months ended September 30, 2017 compared to 2016, these increases were partially offset by lower disposal costs in Eagle Ford and the sale of Haynesville in May 2016. On an equivalent per unit basis, lease operating expense for the quarter and nine months ended September 30, 2017 compared to the same periods in 2016 increased by 10% and 12%, respectively, due to the increase in lease operating expenses in both quarter and nine month periods in 2017 and lower production volumes for the nine months ended September 30, 2017.

General and administrative expenses.  General and administrative expenses for the quarter and nine months ended September 30, 2017decreased by $6 million and $30 million, respectively, compared to the same periods in 2016. Lower costs during the quarter and nine months ended September 30, 2017 compared to the same periods in 2016 included lower payroll, benefits and administrative costs of $4 million and $19 million, respectively, lower rent expense of $3 million and $6 million, respectively, and lower severance expense for the nine months of $10 million. The lower payroll, benefits and administrative costs resulted from lower headcount in 2017 when compared to the same periods in 2016.

Depreciation, depletion and amortization expense. Depreciation, depletion and amortization expense decreased for the quarter ended September 30, 2017 due primarily to the impact of an adjustment in the third quarter of 2016 of approximately $19 million to accrue for certain non-income tax items that would have been historically capitalized and amortized or impaired in prior periods. Depreciation, depletion and amortization expense increased for the nine months ended September 30, 2017 compared to the same period in 2016 due primarily to a reduction in reserves in Eagle Ford and higher Wolfcamp and Altamont volumes. Our Wolfcamp and Altamont areas have a higher depreciation, depletion and amortization cost per unit than Eagle Ford as a result of a non-cash impairment charge recorded in 2015 on our proved properties in Eagle Ford. Our average depreciation, depletion and amortization costs per unit for the quarters and nine months ended September 30 were:

	Quarter ended   September 30,				Nine months ended    September 30,
	2017		2016		2017		2016
Depreciation, depletion and amortization ($/Boe)	$	15.92	$	17.97	$	16.29	$	13.97

Our depreciation, depletion and amortization rate in the future will be impacted by the level and timing of capital spending, the overall cost of capital and the level and type of reserves recorded on completed projects. For the full year 2017, we currently anticipate our depreciation, depletion and amortization costs per unit to be between $16.00 and $17.00 per Boe.

Loss (gain) on sale of assets. For the quarter and nine months ended September 30, 2016, we recorded a $4 million loss and a $79 million gain related to the sale of our assets in the Haynesville and Bossier shales completed in May 2016.

Exploration and other expense. Exploration and other expense increased for the quarter and nine months ended September 30, 2017 by $5 million and $7 million, respectively, compared to the same periods in 2016 reflecting an increase in amortization of insignificant unproved leasehold costs, Wolfcamp geological and geophysical costs, and other expenses associated with certain contractual commitments.

Taxes, other than income taxes.  Taxes, other than income taxes, for the quarter and nine months ended September 30, 2017 increased by $1 million and $7 million, respectively, from the same periods in 2016 due to an increase of severance taxes as a result of higher commodity prices.

Other Income Statement Items.

Gain (loss) on extinguishment of debt. During the first quarter of 2017, we retired our senior secured term loans due 2021 and a portion of our 9.375% senior notes due 2020, recording a loss on extinguishment of debt of approximately $53 million (including $30 million in non-cash expense related to eliminating associated unamortized debt issue costs and debt discounts). In 2017 and 2016, we also repurchased additional debt as follows:

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	Quarter ended September 30,		Nine months ended September 30,
	2017	2016	2017	2016
	(in millions)
Debt repurchased - face value(1)	101	75	157	812
Cash paid	76	47	118	407
Gain on extinguishment of debt(2)(3)	24	26	37	393

(1) In 2017, repurchases were associated with 2020 and 2023 senior unsecured notes. In 2016, repurchases were associated with certain senior unsecured notes and terms loans.

(2) Includes $1 million and $2 million, for the quarter and nine months ended September 30, 2017, respectively, and $1 million and $12 million for the quarter and nine months ended September 30, 2016, respectively, of non-cash expense related to eliminating associated unamortized debt issue costs.

(3) For the nine months ended September 30, 2016, we also recorded a loss on extinguishment of debt of approximately $9 million primarily related to eliminating a portion of the unamortized debt issue costs on our Reserve-Based Loan facility (RBL Facility) due to the reduction of our borrowing base in May 2016.

Interest expense. Interest expense for the quarter and nine months ended September 30, 2017increased by $6 million and $14 million, respectively, compared to the same periods in 2016 due primarily to higher average interest rates on outstanding borrowings in 2017 compared to 2016, partially offset by lower average borrowings under our RBL Facility. In late 2016 and early 2017, we issued $1.5 billion in senior secured notes due in 2024 and 2025. Proceeds from these offerings were used, in part, to repay or repurchase certain of our debt obligations and repay certain amounts outstanding under our RBL Facility.

Income taxes. For the quarter and nine months ended September 30, 2017, our effective tax rates were approximately 4% and 6%, respectively. For both the quarter and nine months ended September 30, 2016, our effective tax rates were approximately 1%. Our effective tax rates in 2017 and 2016 differed from the statutory rate primarily as a result of our recognition of a full valuation allowance on our net deferred tax assets. For the quarters ended September 30, 2017 and 2016 we recorded adjustments to the valuation allowance on our net deferred tax assets which offset deferred income tax benefit of $24 million and $16 million, respectively, and offset deferred income tax benefit and deferred income tax expense of $36 million and $43 million for the nine months ended September 30, 2017 and 2016, respectively. Our effective tax rate for the quarter and nine months ended September 30, 2017 also reflects recording a current income tax benefit and related receivable for the recovery of previously paid alternative minimum taxes based on a change in our tax depreciation elections.

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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 adjusted for cash payments made under these plans), transition, severance and other costs that affect comparability, gains and losses on sale of assets, gains and losses on extinguishment of debt and impairment charges.

We believe that the presentation of EBITDAX and Adjusted EBITDAX is important to provide management and investors with additional information (i) to evaluate our ability to service debt adjusting for items required or permitted in calculating covenant compliance under our debt agreements, (ii) to provide an important supplemental indicator of the operational performance of our business without regard to financing methods and capital structure, (iii) for evaluating our performance relative to our peers, (iv) to measure our liquidity (before cash capital requirements and working capital needs) and (v) to provide supplemental information about certain material non-cash and/or other items that may not continue at the same level in the future. EBITDAX and Adjusted EBITDAX have limitations as analytical tools and should not be considered in isolation or as a substitute for analysis of our results as reported under GAAP or as an alternative to net income (loss), operating income (loss), operating cash flows or other measures of financial performance or liquidity presented in accordance with GAAP.

Below is a reconciliation of our consolidated net (loss) income to EBITDAX and Adjusted EBITDAX:

	Quarter ended   September 30,						Nine months ended    September 30,
	2017			2016			2017			2016
	(in millions)
Net (loss) income	$	(72	)	$	(43	)	$	(122	)	$	113
Income tax (benefit) expense	(2		)	1			(7		)	1
Interest expense, net of capitalized interest	80			74			245			231
Depreciation, depletion and amortization	118			132			368			342
Exploration expense	3			1			7			3
EBITDAX	127			165			491			690
Mark-to-market on financial derivatives(1)	23			(43		)	(92		)	20
Cash settlements and cash premiums on financial derivatives(2)	27			145			86			514
Non-cash portion of compensation expense(3)	5			5			7			12
Transition, severance and other costs(4)	—			—			—			10
Loss (gain) on sale of assets(5)	—			4			—			(78		)
(Gain) loss on extinguishment of debt	(24		)	(26		)	16			(384		)
Impairment charges	1			—			2			—
Adjusted EBITDAX	$	159		$	250		$	510		$	784

(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 or nine months ended September 30, 2017 and 2016.  

(3) For the nine months ended September 30, 2017, the non-cash portion of compensation expense includes cash payments of approximately $4 million. For the quarter and nine months ended September 30, 2016, cash payments were less than $1 million and approximately $3 million, respectively.

(4) Reflects transition and severance costs related to workforce reductions.

(5) Represents the gains and losses on the sale of our Haynesville Shale assets sold in May 2016.

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Commitments and Contingencies

For a further discussion of our commitments and contingencies, see Part I, Item 1, Financial Statements, Note 8.

Liquidity and Capital Resources

Our primary sources of liquidity are cash generated by our operations and borrowings under our RBL Facility. Our primary uses of cash are capital expenditures, debt service, including interest, and working capital requirements. Our available liquidity was approximately $934 million as of September 30, 2017.

In 2017, we have taken steps to improve our liquidity and expand our financial flexibility by (i) issuing $1 billion of 8.00% senior secured notes which mature in 2025 and using the net proceeds to repay in full $580 million senior secured term loans due 2021, repurchase $250 million of 9.375% senior notes due 2020, and repay $111 million of the amounts outstanding under our RBL Facility and (ii) repurchasing for cash a total of $157 million in aggregate principal amount of senior unsecured notes due 2020 and 2023 for approximately $118 million.

Our RBL Facility will mature in May 2019 and has a borrowing base subject to semi-annual redetermination. In February 2017, as a result of the issuance of our $1 billion senior secured notes due 2025, our RBL borrowing base was reduced from $1.5 billion to $1.44 billion. In October 2017 our RBL borrowing base was affirmed at $1.4 billion. 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.

In April 2017, in conjunction with the redetermination, we extended our first lien debt to EBITDAX covenant through March 31, 2019, and the ratio was reduced to 3.0 to 1.0. In April 2019, this financial covenant will revert to a requirement that our total debt to EBITDAX ratio not exceed 4.5 to 1.0. As of September 30, 2017, we were in compliance with our debt covenants, and our ratio of first lien debt to EBITDAX was 0.66x while our total net debt to EBITDAX was 5.21x. Under our RBL Facility, we are also limited in non-RBL Facility debt repurchases to $350 million, subject to certain adjustments. As of September 30, 2017, the non-RBL Facility debt repurchases limit was approximately $885 million as a result of divestitures and financing transactions and will continue to be subject to future adjustments.

As of September 30, 2017, we have three-way collars and fixed price swap derivative contracts on 2.5 MMBbls and 8.9 MMBbls of our anticipated oil production at a weighted average price of $60.34 and $60.00 per barrel of oil for 2017 and 2018, respectively. Our 2017 and 2018 three-way collar contracts contain certain sub-floor prices (weighted average prices of $46.24 per barrel of oil for 2017 and $50.00 per barrel of oil for 2018) that limit the amount of our derivative settlements under these three-way contracts should prices drop below the sub-floor prices. At September 30, 2017 prices, forward commodity prices exceeded those sub-floor prices. For 2017, 2018 and 2019, we have derivative contracts on 9 TBtu, 26 TBtu and 7 TBtu of our anticipated natural gas production at a weighted average price of $3.28, $3.04 and $2.97 per MMBtu, respectively. Refer to "Our Business" for more detailed information on our derivative instruments. As of September 30, 2017 based on the mid-point of our forecasted 2017 guidance, our oil and natural gas derivative contracts provide price protection on approximately 63% and 69%, respectively, of our anticipated 2017 oil and natural gas production and approximately 52% and 55% on our 2018 oil and natural gas production, respectively.

For the full year 2017, we expect to spend approximately $550 million to $600 million in capital in our programs. Based upon our current price and cost assumptions, including the impact of our hedges, we believe that our current capital program will exceed our estimated operating cash flows. We believe the borrowing capacity under our RBL Facility together with expected cash flows from our operations will be sufficient to fund our capital program and meet current obligations and projected working capital requirements through the next twelve months.

Our ability to (i) generate sufficient cash flows from operations or obtain future borrowings under the RBL Facility, (ii) repay or refinance any of our indebtedness on commercially reasonable terms or at all, or (iii) obtain additional capital if required on acceptable terms or at all to fund our capital programs or any potential future acquisitions, joint ventures or other similar transactions, will depend on prevailing economic conditions many of which are beyond our control. The ongoing volatility in the energy industry and in commodity prices will likely continue to impact our outlook. Our plans are intended to address the impacts of the current volatility in commodity prices while (i) maintaining sufficient liquidity to fund capital in our drilling programs, (ii) meeting our debt maturities, and (iii) managing and working to strengthen our balance sheet. We will continue to be opportunistic and aggressive in managing our cost structure and in turn, our liquidity, to meet our capital and operating needs. Accordingly, we will continue to pursue cost saving measures where possible to reduce our capital, operating,

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and general and administrative costs, which may include renegotiating contracts with contractors, suppliers and service providers, deferring and eliminating various discretionary costs, and/or reducing the number of staff and contractors, if necessary.

To the extent commodity prices remain low or decline further, or we experience disruptions in the financial markets impacting our longer-term access to them or that affect our cost of capital, our ability to fund future growth projects may be further impacted. We continually monitor the capital markets and our capital structure and make changes from time to time, with the goal of maintaining financial flexibility, preserving or improving liquidity and/or achieving cost efficiency. For example, we could (i) elect to continue to repurchase additional amounts of our outstanding debt in the future for cash through open market repurchases or privately negotiated transactions with certain of our debtholders subject to the limitations in our RBL Facility or (ii) issue additional secured debt as permitted under our debt agreements, although there is no assurance we would do so. It is also possible that additional adjustments to our plan and outlook may occur based on market conditions and the needs of the Company at that time, which could include selling assets, liquidating all or a portion of our hedge portfolio, seeking additional partners to develop our assets, issuing equity, and/or further reducing our planned capital spending program.

Capital Expenditures.  Our capital expenditures and average drilling rigs by area for the nine months ended September 30, 2017 were: 

	Capital Expenditures(1) (in millions)		Average Drilling Rigs
Eagle Ford Shale	$	135	1.0
Wolfcamp Shale(2)	239		2.0
Altamont	68		1.7
Total	$	442	4.7

(1) Represents accrual-based capital expenditures.

(2) Includes approximately $29 million of acquisition capital.

    Debt. As of September 30, 2017, our total debt was approximately $4.0 billion, comprised of $29 million in senior secured term loans with maturity dates in 2018 and 2019, $505 million outstanding under the RBL Facility which matures in 2019, $2.0 billion in senior unsecured notes due in 2020, 2022 and 2023, and $1.5 billion in senior secured notes due in 2024 and 2025. For additional details on our long-term debt, including maturities, borrowing capacity and restrictive covenants under our debt agreements, see above and Part I, Item 1, Financial Statements, Note 7.

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

	Nine months ended    September 30,
	2017			2016
Cash Inflows
Operating activities
Net (loss) income	$	(122	)	$	113
Gain on sale of assets	—			(78		)
Loss (gain) on extinguishment of debt	16			(384		)
Other income adjustments	394			369
Changes in assets and liabilities	10			638
Total cash flow from operations	$	298		$	658
Investing activities
Proceeds from the sale of assets	—			389
Cash inflows from investing activities	$	—		$	389
Financing activities
Proceeds from issuance of long-term debt	1,645			630
Cash inflows from financing activities	$	1,645		$	630
Total cash inflows	$	1,943		$	1,677
Cash Outflows
Investing activities
Capital expenditures	$	405		$	398
Cash paid for acquisitions	29			—
Cash outflows from investing activities	$	434		$	398
Financing activities
Repayments and repurchases of long-term debt	$	1,484		$	1,239
Debt issue costs	21			24
Other	3			2
Cash outflows from financing activities	$	1,508		$	1,265
Total cash outflows	$	1,942		$	1,663
Net change in cash and cash equivalents	$	1		$	14

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Contractual Obligations

We are party to various contractual obligations. Some of these obligations are reflected in our financial statements,

such as liabilities from financing obligations and commodity-based derivative contracts, while other obligations, such as operating leases and capital commitments, are not reflected on our consolidated balance sheet. The following table and discussion summarizes our contractual cash obligations as of September 30, 2017, for each of the periods presented:

	2017		2018- 2019		2020 - 2021		Thereafter		Total
					(in millions)
Financing obligations:
Principal	$	—	$	534	$	1,200	$	2,269	$	4,003
Interest	77		604		382		428		1,491
Liabilities from derivatives	1		1		—		—		2
Operating leases	2		10		10		22		44
Other contractual commitments and purchase obligations:
Volume and transportation commitments	17		126		109		47		299
Other obligations	14		42		—		—		56
Total contractual obligations	$	111	$	1,317	$	1,701	$	2,766	$	5,895

Financing Obligations (Principal and Interest). Debt obligations included in the table above represent stated maturities. Interest payments are shown through the stated maturity date of the related debt based on (i) the contractual

interest rate for fixed rate debt and (ii) current market interest rates and the contractual credit spread for variable rate debt. See Note 7 for more information on the maturities of our long-term debt.

Operating Leases. Amounts include leases related to our office space and various equipment.

Other Contractual Commitments and Purchase Obligations. Other contractual commitments and purchase obligations

are legally enforceable agreements to purchase goods or services that have fixed or minimum quantities and fixed or minimum

variable price provisions. Amounts in the schedule above approximate the timing of the underlying obligations. Included are the following:

• Volume and Transportation Commitments. Included in these amounts are commitments for demand charges for firm access to natural gas transportation, volume deficiency contracts and firm oil capacity contracts.

• Other Obligations. Included in these amounts are commitments for drilling, completion and seismic

activities for our operations and various other maintenance, engineering, procurement and construction

contracts. Our future commitments under these contracts may change reflecting changes in commodity prices

and any related effect on the supply and demand for these services. We have excluded asset retirement

obligations and reserves for litigation and environmental remediation, as these liabilities are not contractually

fixed as to timing and amount.

31

Item 3. Qualitative and Quantitative Disclosures About Market Risk

This information updates, and should be read in conjunction with the information disclosed in our 2016 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 2016 Annual Report on Form 10-K, except as presented below:

Commodity Price Risk

The table below presents the change in fair value of our commodity-based derivatives due to hypothetical changes in oil and natural gas prices, discount rates and credit rates at September 30, 2017:

			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)	$	64	$	13	$	(51	)	$	108	$	44

			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)	$	64	$	63	$	(1	)	$	64	$	—
Credit rate(3)	$	64	$	63	$	(1	)	$	64	$	—

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

(2) Presents the hypothetical sensitivity of our commodity-based derivatives to changes in the discount rates we used to determine the fair value of our derivatives.

(3) Presents the hypothetical sensitivity of our commodity-based derivatives to changes in credit risk of our counterparties.

Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

As of September 30, 2017, we carried out an evaluation under the supervision and with the participation of our management, including our Chief Executive Officer (CEO) and our interim Chief Financial Officer (CFO), as to the effectiveness, design and operation of our disclosure controls and procedures. This evaluation considered the various processes carried out under the direction of our disclosure committee in an effort to ensure that information required to be disclosed in the U.S. Securities and Exchange Commission reports we file or submit under the Securities Exchange Act of 1934, as amended (Exchange Act), is accurate, complete and timely. Our management, including our CEO and our CFO, does not expect that our disclosure controls and procedures or our internal controls will prevent and/or detect all errors and all fraud. A control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Further, the design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, within our company have been detected. Our disclosure controls and procedures are designed to provide reasonable assurance of achieving their objectives and our CEO and CFO concluded that our disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) were effective as of September 30, 2017.

Changes in Internal Control over Financial Reporting

There were no changes in EP Energy Corporation’s internal control over financial reporting during the first nine months of 2017 that materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

32

PART II — OTHER INFORMATION

Item 1. Legal Proceedings

See Part I, Item 1, Financial Statements, Note 8.

Item 1A. Risk Factors

There have been no material changes to the risk factors previously disclosed in the 2016 Annual Report on Form 10-K.

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 Exhibit Index is incorporated herein by reference.

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

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

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

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

• were made only as of the date of the applicable agreement or such other date or dates as may be specified in the agreement and are subject to more recent developments.

Accordingly, these representations and warranties may not describe the actual state of affairs as of the date they were made or at any other time.

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

33

Exhibit Number	Description
*12.1	Ratio of Earnings to Fixed Charges.
*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.

34

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: November 3, 2017	/s/ Kyle A. McCuen
	Kyle A. McCuen
	Vice President, Interim Chief Financial Officer and Treasurer
	(Principal Financial Officer)
Date: November 3, 2017	/s/ Francis C. Olmsted III
	Francis C. Olmsted III
	Vice President and Chief Accounting Officer
	(Principal Accounting Officer)

35

EP ENERGY CORPORATION

EXHIBIT INDEX

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

Exhibit Number	Description
*12.1	Ratio of Earnings to Fixed Charges.
*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.