EP Energy Corp - FORM 10-Q

Attached files

file	filename
EX-31.1 - EXHIBIT 31.1 - EP Energy Corp	ex31103311610q.htm
EX-12.1 - EXHIBIT 12.1 - EP Energy Corp	ex12103311610q.htm
EX-32.1 - EXHIBIT 32.1 - EP Energy Corp	ex32103311610q.htm
EX-32.2 - EXHIBIT 32.2 - EP Energy Corp	ex32203311610q.htm
EX-31.2 - EXHIBIT 31.2 - EP Energy Corp	ex31203311610q.htm

Table of Contents

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 March 31, 2016

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

EXCHANGE ACT OF 1934

For the transition period from to

Commission File Number 001-36253

EP Energy Corporation

(Exact Name of Registrant as Specified in Its Charter)



Delaware	46-3472728
(State or Other Jurisdiction of Incorporation or Organization)	(I.R.S. Employer Identification No.)

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

Telephone Number: (713) 997-1000

Internet Website: www.epenergy.com

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, or a smaller reporting company. See the definitions of “large accelerated filer”, “accelerated filer” and “smaller reporting 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)

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 April 25, 2016: 251,896,088

Class B Common Stock, par value $0.01 per share. Shares outstanding as of April 25, 2016: 793,508

Table of Contents

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	30
Item 4.	Controls and Procedures	30

PART II — OTHER INFORMATION

Item 1.	Legal Proceedings	31
Item 1A.	Risk Factors	31
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	31
Item 3.	Defaults Upon Senior Securities	31
Item 4.	Mine Safety Disclosures	31
Item 5.	Other Information	31
Item 6.	Exhibits	31
Signatures		32

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
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 our subsidiaries.

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

Table of Contents

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 2015 Annual Report on Form 10-K. There have been no material changes to the risk factors described in the Form 10-K.

Table of Contents

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 March 31,
	2016			2015
Operating revenues
Oil	$	129		$	229
Natural gas	42			48
NGLs	11			13
Financial derivatives	42			203
Total operating revenues	224			493

Operating expenses
Oil and natural gas purchases	4			7
Transportation costs	30			27
Lease operating expense	42			47
General and administrative	38			47
Depreciation, depletion and amortization	113			224
Exploration and other expense	1			6
Taxes, other than income taxes	14			22
Total operating expenses	242			380

Operating (loss) income	(18		)	113
Gain on extinguishment of debt	196			—
Interest expense	(84		)	(84		)
Income before income taxes	94			29
Income tax expense	—			10
Net income	$	94		$	19

Basic net income per common share
Net income	$	0.39		$	0.08
Basic weighted average common shares outstanding	244			244
Diluted net income per common share
Net income	$	0.38		$	0.08
Diluted weighted average common shares outstanding	248			244

See accompanying notes.

Table of Contents

EP ENERGY CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS

(In millions)

(Unaudited)



	March 31, 2016		December 31, 2015
ASSETS
Current assets
Cash and cash equivalents	$	91	$	26
Accounts receivable
Customer, net of allowance of $1 in 2016 and 2015	107		189
Other, net of allowance of $1 in 2016 and 2015	6		12
Income tax receivable	3		3
Materials and supplies	25		24
Derivative instruments	539		694
Assets held for sale	328		344
Prepaid assets	5		5
Other	21		—
Total current assets	1,125		1,297
Property, plant and equipment, at cost
Oil and natural gas properties	6,844		6,721
Other property, plant and equipment	82		80
	6,926		6,801
Less accumulated depreciation, depletion and amortization	2,468		2,374
Total property, plant and equipment, net	4,458		4,427
Other assets
Derivative instruments	68		85
Unamortized debt issue costs - revolving credit facility	22		23
Other	1		1
	91		109
Total assets	$	5,674	$	5,833

See accompanying notes.

Table of Contents

EP ENERGY CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS

(In millions)

(Unaudited)



	March 31, 2016			December 31, 2015
LIABILITIES AND EQUITY
Current liabilities
Accounts payable
Trade	$	52		$	69
Other	99			164
Accrued interest	90			47
Asset retirement obligations	1			1
Liabilities related to assets held for sale	23			24
Short-term debt, net of debt issue costs	261			—
Other accrued liabilities	79			46
Total current liabilities	605			351

Long-term debt, net of debt issue costs	4,303			4,812
Other long-term liabilities
Derivative instruments	7			8
Asset retirement obligations	38			37
Other	6			6
Total non-current liabilities	4,354			4,863

Commitments and contingencies (Note 8)

Stockholders’ equity
Class A shares, $0.01 par value; 550 million shares authorized; 252 million shares issued and outstanding at March 31, 2016; 248 million shares issued and outstanding at December 31, 2015	2			2
Class B shares, $0.01 par value; 0.8 million shares authorized, issued and outstanding at March 31, 2016 and December 31, 2015	—			—
Preferred stock, $0.01 par value; 50 million shares authorized; no shares issued or outstanding	—			—
Treasury stock (at cost); 0.4 million shares at March 31, 2016 and 0.1 million shares at December 31, 2015	(2		)	—
Additional paid-in capital	3,533			3,529
Accumulated deficit	(2,818		)	(2,912		)
Total stockholders’ equity	715			619
Total liabilities and equity	$	5,674		$	5,833

See accompanying notes.

Table of Contents

EP ENERGY CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(In millions)

(Unaudited)



	Quarter ended March 31,
	2016			2015
Cash flows from operating activities
Net income	$	94		$	19
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation, depletion and amortization	113			224
Deferred income tax expense	—			10
Gain on extinguishment of debt	(196		)	—
Other	9			13
Asset and liability changes
Accounts receivable	91			38
Accounts payable	(32		)	(90		)
Derivative instruments	171			14
Accrued interest	43			53
Other asset changes	(1		)	23
Other liability changes	9			(13		)
Net cash provided by operating activities	301			291

Cash flows from investing activities
Cash paid for capital expenditures	(179		)	(432		)
Net cash used in investing activities	(179		)	(432		)

Cash flows from financing activities
Proceeds from issuance of long-term debt	325			364
Repayments and repurchases of long-term debt	(380		)	(236		)
Purchases of treasury stock	(2		)	—
Net cash (used in) provided by financing activities	(57		)	128

Change in cash and cash equivalents	65			(13		)
Cash and cash equivalents
Beginning of period	26			22
End of period	$	91		$	9

See accompanying notes

Table of Contents

EP ENERGY CORPORATION

CONDENSED CONSOLIDATED STATEMENT OF CHANGES IN EQUITY

(In millions)

(Unaudited)



	Stockholders’ Equity
	Class A Stock			Class B Stock			Treasury			Additional Paid-in		(Accumulated Deficit) Retained
	Shares	Amount		Shares	Amount		Stock			Capital		Earnings			Total
Balance at December 31, 2015	248	$	2	0.8	$	—	$	—		$	3,529	$	(2,912	)	$	619
Share-based compensation	4	—		—	—		(2		)	4		—			2
Net income	—	—		—	—		—			—		94			94
Balance at March 31, 2016	252	$	2	0.8	$	—	$	(2	)	$	3,533	$	(2,818	)	$	715

See accompanying notes.

Table of Contents

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 2015 Annual Report on

Form 10-K. The condensed consolidated financial statements as of March 31, 2016 and 2015 are unaudited. The consolidated balance sheet as of December 31, 2015 has been derived from the audited consolidated balance sheet included in our 2015 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 2015 Annual Report on Form 10-K.

New Accounting Pronouncements Issued But Not Yet Adopted

The following accounting standards have been issued but not yet adopted as of March 31, 2016.

Stock Compensation. In March 2016, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) No. 2016-09, Improvements to Employee Share-Based Payment Accounting, which updates several aspects of the accounting for and disclosure of share-based payment transactions. Adoption of this standard is required beginning in the first quarter of 2017 and early adoption is allowed. We are evaluating the impact this update will have in our financial statements.

Leases. In February 2016, the FASB issued ASU No. 2016-02, Leases, which requires lessees to recognize on the balance sheet a right-of-use asset and a lease liability for most leases 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 are evaluating the impact this update will have in 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. In July 2015, the FASB approved the deferral of the new revenue standard by one year, with the option of early adoption in 2017 or, if not adopted early, beginning in the first quarter of 2018. Retrospective application of this standard is required upon adoption. We are currently evaluating the impact, if any, that this update will have on our financial statements.

Table of Contents

2. Divestitures

On March 18, 2016, we entered into an agreement to sell our assets located in the Haynesville and Bossier shales for approximately $420 million in cash (with net proceeds received of approximately $395 million after customary adjustments). In May 2016, we completed the sale, with the buyer also assuming a transportation commitment totaling $106 million. We have classified the assets and liabilities associated with the assets to be sold as held for sale on our balance sheets.

Summarized operating results and financial position data of our assets held for sale were as follows (in millions):



	Quarter ended March 31,
	2016			2015
Operating revenues	$	20		$	19

Operating expenses
Transportation costs	5			6
Lease operating expense	1			2
Depreciation, depletion and amortization	16			6
Other expense	4			2
Total operating expenses	26			16
(Loss) income before income taxes	$	(6	)	$	3



	March 31, 2016		December 31, 2015
Assets
Current assets	$	13	$	16
Property, plant and equipment, net	315		328
Total assets held for sale	$	328	$	344

Liabilities
Accounts payable	$	19	$	17
Other current liabilities	1		4
Asset retirement obligations	3		3
Total liabilities related to assets held for sale	$	23	$	24

3. Income Taxes

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

For the quarter ended March 31, 2016, our effective tax rate was 0%. Our effective tax rate differed from the statutory rate as a result of adjustments to the valuation allowance on our deferred tax assets which offset deferred income tax expense by $35 million. As noted in our 2015 Annual Report on Form 10-K, we evaluate the realization of our deferred tax assets and record the corresponding 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 $941 million as of March 31, 2016.

Our effective tax rate for the quarter ended March 31, 2015 was relatively consistent with the statutory tax rate.

Other. The Company's and certain subsidiaries' income tax years remain open and subject to examination by both federal and state tax authorities. One of our subsidiary’s 2013 U.S. tax return is under examination by the IRS.

Table of Contents

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 income from continuing operations per common share is antidilutive. Potentially dilutive securities consist of employee stock options, restricted stock and performance units. For the quarter ended March 31, 2016, approximately 3.7 million shares are included in our calculation of diluted earnings per share related to our restricted stock awards and performance units (see Note 9). For the quarter ended March 31, 2015, potentially dilutive shares did not have a material effect upon our diluted earnings per share.

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 March 31, 2016 and December 31, 2015, all derivative financial instruments were classified as Level 2. Our assessment of the level of an instrument can change over time based on the maturity or liquidity of the instrument.

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



	March 31, 2016				December 31, 2015
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	(in millions)
Short-term debt	$	264	$	134	$	—	$	—

Long-term debt (see Note 7)	$	4,348	$	2,816	$	4,869	$	3,379

Derivative instruments	$	600	$	600	$	771	$	771

As of March 31, 2016 and December 31, 2015, 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, including consideration of 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 March 31, 2016, we had fixed price derivative contracts for 15.6 MMBbls (10.5 MMBbls of 2016 fixed price swap positions and 5.1 MMBbls of 2017 fixed price swap positions) of oil. In addition, as of March 31, 2016 we had derivative contracts that offset positions on 3.1 MMBbls of 2016 oil fixed price swaps. As of December 31, 2015, we had fixed price derivative contracts for 23.1 MMBbls of oil. As of March 31, 2016 and December 31, 2015, we also had derivative contracts on 6 TBtu of natural gas and 12 MMGal and 7 TBtu of natural gas and 15 MMGal of propane, respectively. In addition, we have derivative contracts related to locational basis differences and/or timing of physical settlement prices on our oil and natural gas. 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 March 31, 2016 and December 31, 2015. 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 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.

Table of Contents



	Level 2
	Derivative Assets									Derivative Liabilities
	Gross Fair Value					Balance Sheet Location				Gross Fair Value					Balance Sheet Location
	Gross Fair Value		Impact of Netting			Current		Non- current		Gross Fair Value			Impact of Netting		Current		Non- current
	(in millions)									(in millions)
March 31, 2016
Derivative instruments	$	626	$	(19	)	$	539	$	68	$	(26	)	$	19	$	—	$	(7	)

December 31, 2015
Derivative instruments	$	795	$	(16	)	$	694	$	85	$	(24	)	$	16	$	—	$	(8	)

For the quarters ended March 31, 2016 and 2015, we recorded derivative gains of $42 million and $203 million, respectively, on our oil, natural gas and NGLs financial derivative instruments. Derivative gains and losses on our oil, natural gas and NGLs financial derivative instruments are recorded in operating revenues in our consolidated income statement.

Interest Rate Derivative Instruments. We have interest rate swaps with a notional amount of $600 million that extend through March 2017 and are intended to reduce variable interest rate risk. As of March 31, 2016, we had a balance of less than $1 million and as of December 31, 2015, we had a net asset of $1 million related to interest rate derivative instruments included on our consolidated balance sheets. For the quarters ended March 31, 2016 and 2015, we recorded $2 million and $4 million of interest expense, respectively, related to the change in fair market value and cash settlements of our interest rate derivative instruments.

6. Property, Plant and Equipment

Oil and Natural Gas Properties. As of March 31, 2016 and December 31, 2015, we had approximately $4.5 billion and $4.4 billion of total property, plant, and equipment, net of accumulated depreciation, depletion and amortization on our balance sheet, 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:



	March 31, 2016		December 31, 2015
	(in millions)
Proved
Eagle Ford	$	2,907	$	2,833
Wolfcamp	2,212		2,174
Altamont	1,574		1,553
Total Proved	6,693		6,560
Unproved
Wolfcamp	94		97
Altamont	57		64
Total Unproved	151		161
Less accumulated depletion	2,427		2,335
Net capitalized costs for oil and natural gas properties	$	4,417	$	4,386

During the quarter ended March 31, 2016, we transferred approximately $7 million from unproved properties to proved properties. For the quarters ended March 31, 2016 and 2015, we recorded less than $1 million and $4 million, respectively, of amortization of unproved leasehold costs in exploration expense in our consolidated income statement. Suspended well costs were not material as of March 31, 2016 or December 31, 2015.

We evaluate capitalized costs related to proved properties at least annually or upon a triggering event (such as a significant continued forward commodity price decline) to determine if 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 for impairment based on estimated drilling plans and capital expenditures which may also change relative to forward commodity prices and/or potential lease expirations.

Table of Contents

Commodity prices have a significant impact on our impairment assessments and remained volatile subsequent to December 31, 2015. While forward commodity price changes as of March 31, 2016 did not result in any impairment charges of our proved or unproved property costs during the quarter, future commodity price declines may cause changes to our future capital, 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.

Leasehold acquisition costs associated with non-producing or unproved areas are assessed for impairment based on our estimated drilling plans and capital expenditures relative to potential lease expirations. Generally, economic recovery of unproved reserves in such 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 will be 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. Currently, we have the intent and believe we have the ability to fulfill our drilling commitments prior to the expiration of the associated leases. Should oil prices not justify sufficient capital allocation to the continued development of properties where we have these 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 7-9 percent on a significant portion of our obligations and a projected inflation rate of 2.5 percent. Changes in estimates in the table below represent changes to the expected amount and timing of payments to settle our asset retirement obligations. Typically, these changes 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. The net asset retirement liability as of March 31, 2016 on our consolidated balance sheet in other current and non-current liabilities and the changes in the net liability from January 1 through March 31, 2016 were as follows:



	2016
	(in millions)
Net asset retirement liability at January 1	$	38
Accretion expense	1
Net asset retirement liability at March 31	$	39

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 the quarters ended March 31, 2016 and 2015 was approximately $2 million and $4 million, respectively.

7. Long-Term Debt

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



	Interest Rate	March 31, 2016			December 31, 2015
		(in millions)
$2.75 billion RBL credit facility - due May 24, 2019⁽¹⁾	Variable	$	1,160		$	1,072
Senior secured term loan - due May 24, 2018⁽²⁾⁽⁴⁾	Variable	467			497
Senior secured term loan - due April 30, 2019⁽³⁾⁽⁴⁾	Variable	142			150
Senior unsecured notes - due May 1, 2020	9.375%	1,675			2,000
Senior unsecured notes - due September 1, 2022	7.75%	257			350
Senior unsecured notes - due June 15, 2023	6.375%	647			800
Total long-term debt		4,348			4,869
Less unamortized debt issue costs		(45		)	(57		)
Total long-term debt, net		4,303			4,812
Short-term debt, net of debt issue costs		261			—
Total debt		$	4,564		$	4,812

Table of Contents


(1)	Prior to the redetermination in May 2016, the RBL Facility (as defined below), carried interest at a specific margin over LIBOR of 1.50% to 2.50%, based on borrowing utilization. Following the redetermination, the RBL Facility now carries interest at specific margin over LIBOR of 2.50% to 3.50%, based on borrowing utilization.

(2) The term loan was 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 March 31, 2016 and December 31, 2015, the effective interest rate of the term loan was 3.50%.

(3) The term loan carries interest at a specified margin over the LIBOR of 3.50%, with a minimum LIBOR floor of 1.00%. As of March 31, 2016 and December 31, 2015, the effective interest rate for the term loan was 4.50%.

(4) The term loans are secured by a second priority lien on all of the collateral securing the RBL Facility, and effectively rank junior to any existing and future first lien secured indebtedness of the Company.

During the first quarter of 2016, we paid approximately $143 million in cash to repurchase a total of approximately $345 million in aggregate principal amount of our senior unsecured notes. We recorded a gain on extinguishment of debt of approximately $196 million (including $6 million of non-cash expense related to eliminating associated unamortized debt issue costs). Subsequent to March 31, 2016, we have also entered into contracts to repurchase or repurchased an additional $264 million of our term loans and our senior unsecured notes for approximately $144 million in cash. We classified the principal amount of this additional long-term debt repurchased or to be repurchased as short-term debt on our consolidated balance sheet as of March 31, 2016.

Unamortized Debt Issue Costs. As of March 31, 2016 and December 31, 2015, we had total unamortized debt issue costs of $70 million and $80 million. Of these amounts, $22 million and $23 million, respectively, are associated with our Reserve-Based Loan facility (RBL Facility) and $48 million, ($3 million of which are classified as short-term debt, net of debt issue costs) and $57 million, respectively, are associated with our senior secured term loans and senior notes. During the first quarter of 2016, we expensed approximately $6 million in conjunction with the repurchase of a portion of our senior unsecured notes. During the quarters ended March 31, 2016 and 2015, we amortized $4 million and $5 million, respectively, of deferred financing costs into interest expense.

$2.75 Billion Reserve-based Loan Facility. As of March 31, 2016, we had a $2.75 billion credit facility in place which allows us to borrow funds or issue letters of credit (LCs). As of March 31, 2016, we had $1.5 billion of available capacity remaining with approximately $95 million of LC's issued and approximately $1.2 billion outstanding under the facility. In May, we used the net proceeds of approximately $395 million from the sale of our Haynesville assets to reduce outstanding borrowings under the facility and also reduced letters of credit by approximately $60 million as a result of the release of a transportation commitment.

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 May 2016, we completed our semi-annual redetermination, and the borrowing base of our RBL Facility was reduced to $1.65 billion, reflecting significantly lower bank commodity price forecasts, the sale of our Haynesville assets and the roll-off of certain hedge positions. Our next redetermination date is in November 2016. Downward revisions of our oil and natural gas reserves due to declines in commodity prices, performance revisions, sales of assets or the incurrence of certain types of additional debt, among other items, could cause a further reduction of our borrowing base which could negatively impact our borrowing capacity under the RBL Facility in the future.

In 2015, we agreed with our lenders to extend the maturity of our RBL Facility to May 2019, provided that we retire or refinance our 2018 and 2019 secured notes and term loans (collectively, the "second lien debt") at least six months prior to their maturity. Accordingly, we will be required to retire or refinance remaining amounts outstanding under our (i) $500 million senior secured term loans due 2018 by November 2017 and (ii) $150 million senior secured term loans due 2019 by November 2018.

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. At March 31, 2016 we were in compliance with all of our debt covenants. In conjunction with our RBL Facility redetermination in May 2016, we amended certain covenants, the most significant of which suspended the requirement that our debt to EBITDAX ratio, as defined in the credit agreement, not exceed 4.5 to 1.0 and replaced it with a requirement that our ratio of first lien debt to EBITDAX not exceed 3.5 to 1.0. The 4.5 to 1.0 debt to EBITDAX requirement will be reinstated beginning in April 2018. As part of the amendment, we also agreed to limit debt repurchases to $350 million subject to certain future adjustments.

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

Table of Contents

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 March 31, 2016, we had approximately $2 million accrued for all outstanding legal matters.

Indemnifications and Other Matters. We periodically enter into indemnification arrangements as part of the divestitures 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 recent decline in commodity prices has created an environment where there is an increased risk that owners and/or operators of assets previously purchased from us may no longer be able to satisfy plugging and abandonment obligations that attach to such assets. In that event, under various laws or regulations, we could be required to assume these plugging or abandonment obligations on assets no longer owned or operated by us. As of March 31, 2016, we had approximately $8 million accrued related to these indemnifications and other 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. These laws and regulations may require the acquisition of a permit before drilling commences, restrict the types, quantities and concentrations of various substances that can be released into the environment in connection with drilling and production activities, limit or prohibit construction or drilling activities on certain lands lying within wilderness, wetlands, ecologically sensitive and other protected areas, require action to prevent or remediate pollution from current or former operations, such as plugging abandoned wells or closing pits, result in the suspension or revocation of necessary permits, licenses and authorizations, require that additional pollution controls be installed and impose substantial liabilities for pollution resulting from our operations or relate to our owned or operated facilities. The strict and joint and several liability nature of such laws and regulations could impose liability upon us regardless of fault. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances, hydrocarbons or other waste products into the environment. Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent and costly pollution control or waste handling, storage, transport, disposal or cleanup requirements could materially adversely affect our operations and financial position, as well as the oil and natural gas industry in general. 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.

The environmental laws and regulations to which we are subject also require us to remove or remedy the effect on the environment of the disposal or release of specified substances at current and former operating sites. As of March 31, 2016, we had accrued and had exposure of approximately $1 million for related environmental remediation costs associated with onsite, offsite and groundwater technical studies and for related environmental legal costs. Our accrual represents a combination of two estimation methodologies. First, where the most likely outcome can be reasonably estimated, that cost has been accrued. Second, where the most likely outcome cannot be estimated, a range of costs is established and if no one amount in that range is more likely than any other, the lower end of the expected range has been accrued. Our environmental remediation projects are in various stages of completion. The liabilities we have recorded reflect our current estimates of amounts that we will expend to remediate these sites. However, depending on the stage of completion or assessment, the ultimate extent of contamination or remediation required may not be known. As additional assessments occur or remediation efforts continue, we may incur additional liabilities.

Climate Change and Other Emissions. The EPA and several state environmental agencies have adopted regulations to regulate GHG emissions. Although the EPA has adopted a “tailoring” rule to regulate GHG emissions, the U.S. Supreme Court partially invalidated it in an opinion decided June 2014. The tailoring rule remains applicable for those facilities considered major sources of six other “criteria” pollutants and at this time we do not expect a material impact to our existing operations from the rule. Any regulations regarding GHG emissions would likely increase our costs of compliance by potentially delaying the receipt of permits and other regulatory approvals; requiring us to monitor emissions, install additional equipment or modify facilities to reduce GHG and other emissions; purchase emission credits; and utilize electric-driven compression at facilities to obtain regulatory permits and approvals in a timely manner.

As part of the White House’s Climate Action Plan Strategy to Reduce Methane Emissions, the EPA, the Pipeline and Hazardous Materials Safety Administration (PHMSA) and the Bureau of Land Management (BLM) have recently proposed

Table of Contents

new regulations affecting the oil and gas industry. On September 18, 2015, the EPA published several proposed regulations under the Clean Air Act to reduce methane and volatile organic compounds emissions, in part through green completions at oil wells, fugitive emission surveys, limits on pneumatic pumps and controllers, and draft guidelines for controls on equipment in ozone nonattainment areas. On October 13, 2015, the PHMSA published a proposed rule for oil pipelines, in part requiring inspections in areas affected by natural disasters, expanding use of leak detection systems, and increased use of inline inspection tools. On January 22, 2016, the BLM released a proposed rule for oil and gas facilities on onshore federal and Indian leases to prohibit venting, limit flaring, require leak detection, and allow adjustment of royalty rates for new leases. Although we are examining these proposed regulations, it is uncertain what impact they might have on our operations until they are implemented.

Air Quality Regulations. The EPA has promulgated various performance and emission standards that mandate air pollutant emission limits and operating requirements for stationary reciprocating internal combustion engines and process equipment. We do not anticipate material capital expenditures to meet these requirements.

In August 2012, the EPA promulgated additional standards to reduce various air pollutants associated with hydraulic fracturing of natural gas wells and equipment including compressors, storage vessels, and pneumatic valves. Parts of the new standard were amended August 2013. We do not anticipate material capital expenditures to meet these requirements. Effective December 31, 2014, additional amendments to the new standard were finalized, for which we do not anticipate material capital expenditure.

The EPA has promulgated regulations to require pre-construction permits for minor sources of air emissions in tribal lands as of September 2, 2014. The EPA has twice extended this deadline, to March 2, 2016 and then to October 3, 2016. Meanwhile the EPA has proposed a federal implementation plan (FIP), rather than a general permit that incorporates emission limits and other requirements from six standards under the Clean Air Act for the oil and gas industry. Additionally, the proposed FIP would require an operator to document compliance with the Endangered Species Act and National Historic Preservation Act. Until such regulations are adopted, it is uncertain what impact they might have on our operations in tribal lands.

Hydraulic Fracturing Regulations. We use hydraulic fracturing extensively in our operations. Various regulations have been adopted and proposed at the federal, state and local levels to regulate hydraulic fracturing operations. These regulations range from banning or substantially limiting hydraulic fracturing operations, requiring disclosure of the hydraulic fracturing fluids and requiring additional permits for the use, recycling and disposal of water used in such operations. In addition, various agencies, including the EPA and Department of Energy are reviewing changes in their regulations to address the environmental impacts of hydraulic fracturing operations. Until such regulations are implemented, it is uncertain what impact they might have on our operations. In March 2015, the BLM published final rules for hydraulic fracturing on federal and certain tribal lands, including use of tanks for recovered water, updated cementing and testing requirements, and disclosure of chemicals used in hydraulic fracturing. Several states and the Ute Indian Tribe have filed suit to challenge these rules, and on September 30, 2015, a federal court issued a preliminary injunction suspending the rules. No material cost is expected for the Company’s 2016 program.

Comprehensive Environmental Response, Compensation and Liability Act (CERCLA) Matters. As part of our environmental remediation projects, we are or have received notice that we could be designated as a Potentially Responsible Party (PRP) with respect to one active site under the CERCLA or state equivalents. As of March 31, 2016, we have estimated our share of the remediation costs at this site to be less than $1 million. Because the clean-up costs are estimates and are subject to revision as more information becomes available about the extent of remediation required, and because in some cases we have asserted a defense to any liability, our estimates could change. Moreover, liability under the federal CERCLA statute may be joint and several, meaning that we could be required to pay in excess of our pro-rata share of remediation costs. Our understanding of the financial strength of other PRPs has been considered, where appropriate, in estimating our liabilities. Accruals for these matters are included in the reserve for environmental matters discussed above.

Waste Handling. Administrative, civil and criminal penalties can be imposed for failure to comply with waste handling requirements imposed under the Resource Conservation and Recovery Act, as amended, and comparable state laws. We believe that we are in substantial compliance with applicable requirements related to waste handling, and that we hold all necessary and up-to-date permits, registrations and other authorizations to the extent that our operations require them under such laws and regulations. Any legislative or regulatory reclassification of oil and natural gas exploration and production wastes could increase our costs to manage and dispose of such wastes.

It is possible that new information or future developments could require us to reassess our potential exposure related to environmental matters. We may incur significant costs and liabilities in order to comply with existing environmental laws and regulations. It is also possible that other developments, such as increasingly strict environmental laws, regulations, and orders

Table of Contents

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, could result in substantial costs and liabilities in the future. As this information becomes available, or other relevant developments occur, we will adjust our accrual amounts accordingly. While there are still uncertainties related to the ultimate costs we may incur, based upon our evaluation and experience to date, we believe our reserves are adequate.

9. Long-Term Incentive Compensation

Our long-term incentive (LTI) programs consist of certain equity and liability based compensation awards including restricted stock, stock options and performance units. A summary of the changes in our non-vested restricted shares for the quarter ended March 31, 2016 is presented below:



	Number of Shares		Weighted Average Grant Date Fair Value per Share
Non-vested at December 31, 2015	3,987,654		$	10.98
Granted	4,475,737		$	6.13
Vested	(900,623	)	$	9.82
Forfeited	(247,286	)	$	10.90
Non-vested at March 31, 2016	7,315,482		$	8.16

During the first quarter of 2016, we granted 83,150 performance units to certain members of EP Energy's management team. Performance units have a target value of $100 per unit; however, the ultimate value of each performance unit will range from zero to $200 depending on the level of total shareholder return (TSR) relative to that of EP Energy’s peer group of companies. The performance units vest in three separate tranches (1 year, 2 year and 3 year calendar periods). For accounting purposes, the performance units are treated as a liability award with the expense recognized on an accelerated basis. The fair value measured at the grant date was approximately $8 million which will be subsequently remeasured at the end of each reporting period. The fair value of the performance-based units granted is estimated on the date of grant using a Monte-Carlo simulation for each of three separate performance tranches based on the relative TSR results for each separate tranche period beginning January 1, 2016. The performance units may be settled in either stock or cash at the election of the Board of Directors. Assuming such amounts were settled in stock at March 31, 2016, the number of shares that we would issue upon settlement of the 2016 performance unit grants, assuming the awards were vested and relative TSR performance was determined at that date, would be approximately 3.7 million shares.

We record compensation expense on our LTI awards as general and administrative expense over the requisite service period, net of estimates of forfeitures. Pre-tax compensation expense related to all of our LTI awards (both equity and liability based) was approximately $5 million for both the quarters ended March 31, 2016 and 2015. As of March 31, 2016, we had unrecognized compensation expense of $74 million. We will recognize an additional $20 million related to our outstanding awards during the remainder of 2016, $39 million over the remaining requisite service periods subsequent to 2016 and $15 million upon a specified capital transaction when the right to such amounts becomes non-forfeitable.

10. Related Party Transactions

Affiliate Supply Agreement. For the quarters ended March 31, 2016 and 2015, we recorded approximately $4 million and $7 million, respectively, in capital expenditures for amounts expended under supply agreements entered into with an affiliate of Apollo Management, LLC (Apollo) to provide certain fracturing materials to our Eagle Ford drilling operations.

Table of Contents

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 2015 Annual Report on Form 10-K. Actual results may differ materially from those contained in any forward-looking statements. Unless otherwise indicated or the context otherwise requires, references in this MD&A section to “we”, “our”, “us” and “the Company” refer to EP Energy Corporation and each of its consolidated subsidiaries.

Our Business

Overview. We are an independent exploration and production company engaged in the acquisition and development of unconventional onshore oil and natural gas properties in the United States. We are focused on creating shareholder value through the development of our low-risk drilling inventory located in three core areas: the Eagle Ford Shale (South Texas), the Wolfcamp Shale (Permian Basin in West Texas) and the Altamont Field in the Uinta Basin (Northeastern Utah). In March 2016, we entered into an agreement to sell our assets located in the Haynesville and Bossier shales for $420 million in cash (with net proceeds received of approximately $395 million after customary adjustments). We completed the sale in May 2016.

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 sell oil and natural gas properties if they no longer meet our long-term goals.

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 cash 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, 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.

We attempt to mitigate certain risks through actions such as entering into longer term contractual arrangements to control costs and by entering into derivative contracts to stabilize cash flows and reduce the financial impact of downward commodity price movements on commodity sales. 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. 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.

Derivative Instruments. Our realized prices from the sale of our oil and natural gas are affected by (i) commodity price movements, including locational or basis price differences that exist between the commodity index price (e.g., WTI) and the actual price at which we sell our oil and natural gas, 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 locational price differences.

Table of Contents

During the quarter ended March 31, 2016, we (i) settled commodity index hedges on approximately 97% of our oil production, 77% of our total liquids production and 9% of our natural gas production at average floor prices of $80.29 per barrel of oil, $0.55 per gallon of NGLs and $4.20 per MMBtu of natural gas, respectively and (ii) hedged basis risk on approximately 97% of our year-to-date Eagle Ford oil production. To the extent our oil and natural gas production is unhedged, either from a commodity index or locational price perspective, our financial results 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 March 31, 2016.



	2016				2017
	Volumes⁽¹⁾	Average Price⁽¹⁾			Volumes⁽¹⁾	Average Price⁽¹⁾
Oil
Fixed Price Swaps
WTI	6,394	$	80.03		4,015	$	66.11
LLS	4,055	$	80.51		—	$	—
Three Way Collars
Ceiling - WTI	—	$	—		1,095	$	75.13
Floors - WTI⁽²⁾	—	$	—		1,095	$	65.00
Basis Swaps
LLS vs. WTI⁽³⁾	1,513	$	3.91		—	$	—
LLS vs. Brent⁽⁴⁾	—	$	—		3,650	$	(3.14	)
Midland vs. Cushing⁽⁵⁾	550	$	(0.83	)	1,460	$	(0.68	)
WTI - CM vs. TM⁽⁶⁾	4,055	$	0.31		—	$	—
NYMEX Roll⁽⁷⁾	5,500	$	(0.84	)	—	$	—
Natural Gas
Fixed Price Swaps	6	$	4.20		—	$	—
Propane
Fixed Price Swaps	12	$	0.55		—	$	—


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


(2)	If market prices settle at or below $55.00 in 2017, we will receive a “locked-in” cash settlement of the market price plus $10.00 per Bbl.


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


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


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


(6)	EP Energy receives WTI trade month (TM) plus the spread listed and pays WTI calendar month (CM).

(7)

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

In addition to the derivative contracts presented in the table above, during the first quarter of 2016 we entered into contracts offsetting 3,095 MBbls of 2016 LLS fixed price swaps, 1,650 MBbls of 2016 LLS vs. Brent basis swaps and 4,745 MBbls of 2016 WTI - CM vs. TM. By entering into these offsetting positions, we effectively “locked-in” net cash settlements of approximately $109 million which will be received during the remainder of 2016.

For the period from April 1, 2016 through May 4, 2016, we have entered into additional derivative contracts to offset certain fixed price swaps and basis swaps (current month to trade month) on approximately 920 MBbls of oil. By entering into these offsetting positions, we effectively “locked-in” cash settlements of approximately $36 million which will be received during the remainder of 2016.

Table of Contents

Summary of Liquidity and Capital Resources. As of March 31, 2016, we had available liquidity, including existing cash, of approximately $1.6 billion. To date in 2016, we have taken a number of steps to maintain or improve our liquidity, strengthen our balance sheet and expand our financial flexibility. These steps have included (i) completing the sale of our Haynesville Shale assets in May 2016, (ii) repurchasing for cash or entering into agreements to repurchase certain of our unsecured notes and/or term loans and (iii) completing the semi-annual redetermination of our RBL Facility in May 2016. The RBL redetermination resulted in a revised borrowing base of $1.65 billion and amendments to certain restrictive debt covenants for 2017 and through the first quarter of 2018. Following the actions described above, our available liquidity as of March 31, 2016 on a pro-forma basis was approximately $0.8 billion. See additional details of these transactions in “Liquidity and Capital Resources”.

Outlook for 2016. For the full year 2016, we expect the following:


•	Capital expenditures between $500 million to $900 million.


•	Average daily production volumes for the year of approximately 81 MBoe/d to 88 MBoe/d, including average daily oil production volumes of approximately 45 MBbls/d to 50 MBbls/d.


•	Per unit adjusted cash operating costs for the year of approximately $10.40 to $11.40 per Boe, and per unit transportation costs of approximately $3.30 to $3.40 per Boe.


•	Per unit depreciation, depletion and amortization rate of approximately $13.00 to $14.00 per Boe.

Table of Contents

Production Volumes and Drilling Summary

Production Volumes. Below is an analysis of our production volumes for the quarters ended March 31:



	2016	2015
United States (MBoe/d)
Eagle Ford Shale	50.8	54.7
Wolfcamp Shale	18.3	17.9
Altamont	16.2	17.1
Haynesville Shale	18.6	12.6
Other	0.1	0.1
Total	104.0	102.4

Oil (MBbls/d)	50.8	60.0
Natural Gas (MMcf/d)	232	185
NGLs (MBbls/d)	14.5	11.6


•	Eagle Ford Shale—Our Eagle Ford Shale equivalent volumes decreased by 3.9 MBoe/d (approximately 7%) and oil production by 5.6 MBbls/d (15%) for the quarter ended March 31, 2016 compared to the same period in 2015. During the quarter ended March 31, 2016, we completed 16 additional operated wells in the Eagle Ford, and we had a total of 579 net operated wells as of March 31, 2016.


•	Wolfcamp Shale—Our Wolfcamp Shale equivalent volumes increased 0.4 MBoe/d (approximately 2%) for the quarter ended March 31, 2016 compared to the same period in 2015 as we continue to progress the development of the program. During the quarter ended March 31, 2016, we completed 5 additional operated wells, for a total of 242 net operated wells as of March 31, 2016.


•	Altamont—Our Altamont equivalent volumes decreased 0.9 MBoe/d (approximately 5%) for the quarter ended March 31, 2016 compared to the same period in 2015. Altamont produced an average of 11.4 MBbls/d of oil during the quarter ended March 31, 2016, and we completed an additional 2 operated oil wells for a total of 380 net operated wells as of March 31, 2016.

•

Haynesville Shale—Our Haynesville Shale equivalent volumes increased 6 MMcf/d (approximately 48%) for the quarter ended March 31, 2016 compared to the same period ended March 31, 2015. As of March 31, 2016, we have a total of 103 net operated wells in the Haynesville Shale, and our total natural gas production for the quarter ended March 31, 2016 was approximately 111 MMcf/d. We completed the sale of the Haynesville Shale in May 2016.

Our oil production declines in our Eagle Ford, Wolfcamp and Altamont core areas reflect the slowed pace of development in our drilling programs due to reduced capital spending in the latter part of 2015 and the first quarter of 2016. Future volumes will be impacted by our levels of capital spending and the timing of that spending. In the current commodity price environment, we could see this level of spending decrease which may result in lower reported volumes in the future.

Table of Contents

Results of Operations

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



	Quarter ended March 31,
	2016			2015
	(in millions)
Operating revenues
Oil	$	129		$	229
Natural gas	42			48
NGLs	11			13
Total physical sales	182			290
Financial derivatives	42			203
Total operating revenues	224			493

Operating expenses
Oil and natural gas purchases	4			7
Transportation costs	30			27
Lease operating expense	42			47
General and administrative	38			47
Depreciation, depletion and amortization	113			224
Exploration and other expense	1			6
Taxes, other than income taxes	14			22
Total operating expenses	242			380

Operating (loss) income	(18		)	113
Gain on extinguishment of debt	196			—
Interest expense	(84		)	(84		)
Income before income taxes	94			29
Income tax expense	—			10
Net income	$	94		$	19

Table of Contents

Operating Revenues

The table below provides our operating revenues, volumes and prices per unit for the quarters ended March 31, 2016 and 2015. 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 March 31,
	2016		2015
	(in millions)
Operating revenues:
Oil	$	129	$	229
Natural gas	42		48
NGLs	11		13
Total physical sales	182		290
Financial derivatives	42		203
Total operating revenues	$	224	$	493

Volumes:
Oil (MBbls)	4,624		5,402
Natural gas (MMcf)	21,150		16,628
NGLs (MBbls)	1,317		1,044
Equivalent volumes (MBoe)	9,466		9,218
Total MBoe/d	104.0		102.4

Prices per unit⁽¹⁾:
Oil
Average realized price on physical sales ($/Bbl)⁽²⁾	$	27.89	$	42.40
Average realized price, including financial derivatives ($/Bbl)⁽²⁾⁽³⁾	$	72.73	$	78.39
Natural gas
Average realized price on physical sales ($/Mcf)⁽²⁾	$	1.81	$	2.51
Average realized price, including financial derivatives ($/Mcf)⁽³⁾	$	1.99	$	3.69
NGLs
Average realized price on physical sales ($/Bbl)	$	8.24	$	12.04
Average realized price, including financial derivatives ($/Bbl)⁽³⁾	$	8.69	$	12.26

(1)

Oil prices for the quarter ended March 31, 2016 are calculated including a reduction of less than $1 million for oil purchases associated with managing our physical sales. Natural gas prices for the quarters ended March 31, 2016 and 2015 are calculated including a reduction of approximately $4 million and $7 million, respectively, for natural gas purchases associated with managing our physical sales.


(2)	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.

(3)

The quarters ended March 31, 2016 and 2015, include approximately $207 million and $194 million of cash received, respectively, for the settlement of crude oil derivative contracts and approximately $4 million and $20 million of cash received, respectively, for the settlement of natural gas financial derivatives. The quarters ended March 31, 2016 and 2015 also include approximately $1 million of cash received and less than $1 million of cash paid, respectively, for the settlement of NGLs derivative contracts. No cash premiums were received or paid for the quarters ended March 31, 2016 and 2015.

Table of Contents

Physical sales. Physical sales represent accrual-based commodity sales transactions with customers. For the quarter ended March 31, 2016, physical sales decreased by $108 million (37%) compared to the same period in 2015. Physical sales have decreased due to lower commodity prices across all commodity types and lower oil volumes reflecting the slowed pace of development in our drilling programs due to reduced capital spending in the latter part of 2015 and the first quarter of 2016. These decreases have been partially offset by natural gas volume growth primarily from our Wolfcamp and Haynesville drilling programs. The table below displays the price and volume variances on our physical sales when comparing the quarters ended March 31, 2016 and 2015.



	Oil			Natural gas			NGLs			Total
	(in millions)
March 31, 2015 sales	$	229		$	48		$	13		$	290
Change due to prices	(67		)	(19		)	(5		)	(91		)
Change due to volumes	(33		)	13			3			(17		)
March 31, 2016 sales	$	129		$	42		$	11		$	182

Oil sales for the quarter ended March 31, 2016 compared to the same period in 2015 decreased by $100 million (44%) due primarily to lower oil prices and a decline in oil volumes in all of our oil programs. For the quarter ended March 31, 2016 compared to the same period in 2015, Eagle Ford oil production decreased by 15% (5.6 MBbls/d), Wolfcamp oil production decreased by 26% (2.5 MBbls/d) and Altamont oil production decreased by 9% (1.1 MBbls/d) reflecting the slowed pace of development of our core areas.

Natural gas sales decreased for the quarter ended March 31, 2016 compared to the same period in 2015 primarily due to lower natural gas prices, offset by natural gas volume growth primarily in Wolfcamp and Haynesville.

Our oil and natural gas is sold at index prices (WTI, LLS and Henry Hub) or 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 deducts, differentials from the index to the delivery point, adjustments for time, and/or discounts for quality or grade. Generally as the index price of our commodities decreases, the fixed contractual deducts in our physical sales contracts reduce the realized prices we receive on a percentage of NYMEX basis.

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. Pricing for both areas has been influenced by the weakening average price adjustments we receive on physical sales. In Altamont, market pricing of our oil is based upon both Salt Lake City refinery postings and NYMEX based agreements which reflect transportation and handling costs associated with moving wax crude to end users. 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 March 31,
	2016						2015
	Oil (Bbl)			Natural gas (MMBtu)			Oil (Bbl)			Natural gas (MMBtu)
Differentials and deducts	$	(5.52	)	$	(0.29	)	$	(6.49	)	$	(0.50	)
NYMEX	$	33.45		$	2.09		$	48.63		$	2.98
Net back realization %	83.5		%	86.1		%	86.7		%	83.2		%

The lower realization percentage in the quarter ended March 31, 2016 relative to the quarter ended March 31, 2015 was primarily a result of a reduced LLS premium relative to NYMEX in Eagle Ford, the increasingly negative average pricing adjustments on physical sales, and increased fixed contract deductions in Wolfcamp, partially offset by improved physical sales contract pricing in Eagle Ford and improved refinery postings in Altamont. The smaller natural gas differentials and deducts in the quarter ended March 31, 2016 were primarily a result of improved locational basis differentials in the Haynesville area and lower excess royalties paid on flared gas.

NGLs sales decreased for the quarter ended March 31, 2016 compared to the same period in 2015. Average realized prices decreased in 2016 compared to the same period in 2015, due to lower pricing on all liquids components. NGLs pricing

Table of Contents

is largely tied to crude oil prices. NGLs volume increased primarily as a result of our Eagle Ford and Wolfcamp drilling programs.

Future growth in our overall oil sales (including the impact of financial derivatives) will largely be impacted by commodity pricing, our ability to maintain or grow oil volumes, by the location of our production and by the nature of our sales contracts. Based on our hedges in place as of March 31, 2016, we have over 11 MMBbls hedged for 2016 at a weighted average price of $80.29 per barrel. We also have contracts that effectively "lock-in" approximately $40.00 per barrel in cash settlements, on an additional 3.1 MMBbls of 2016 LLS fixed price swaps, 1,650 MBbls of 2016 LLS vs. Brent basis swaps and 4,745 MBbls of 2016 WTI - CM vs. TM, representing net cash settlements of approximately $109 million which will be received during the remainder of 2016. See "Our Business" 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 March 31, 2016, we recorded $42 million of derivative gains compared to derivative gains of $203 million during the quarter ended March 31, 2015.

Operating Expenses

Transportation costs. Transportation costs for the quarters ended March 31, 2016 and 2015 were $30 million and $27 million, respectively. Total transportation costs increased for the quarter ended March 31, 2016 primarily due to gas transportation costs associated with Eagle Ford and Wolfcamp as a result of higher gas volumes, partially offset by a decrease in NGLs transportation costs in Eagle Ford.

Lease operating expense. Lease operating expense for the quarters ended March 31, 2016 and 2015 was $42 million and $47 million, respectively. For the quarter ended March 31, 2016, we incurred a decrease in lease operating expense in Wolfcamp of approximately $5 million due to lower disposal costs from lower produced water, lower flowback, maintenance and repair costs and a general decrease in costs across all our programs due to ongoing contract negotiations.

General and administrative expenses. General and administrative expenses for the quarters ended March 31, 2016 and 2015 were $38 million and $47 million, respectively. Lower costs in 2016 reflected lower payroll, benefits and administrative costs of $5 million compared to the same period in 2015. Period over period, we had a general and administrative headcount reduction of approximately 25% in response to the lower price environment.

Depreciation, depletion and amortization expense. Depreciation, depletion and amortization expense for the quarter ended March 31, 2016 and 2015 were $113 million and $224 million, respectively. Our depreciation, depletion and amortization costs decreased in 2016 compared to the same period in 2015 due primarily to the impact of the non-cash impairment charge on our proved properties recorded in the fourth quarter of 2015 and an overall decrease in production volumes. Our average depreciation, depletion and amortization costs per unit for the quarters ended March 31 were:



	Quarter ended March 31,
	2016		2015
Depreciation, depletion and amortization ($/Boe)	$	11.94	$	24.30

Our depreciation, depletion and amortization rate in the future will be impacted by level of timing of capital spending, overall cost savings on capital and the level and type of reserves recorded on completed projects.

Exploration and other expense. For the quarters ended March 31, 2016 and 2015, we recorded $1 million and $6 million of exploration expense, respectively. Included in exploration expense for the quarters ended March 31, 2016 and 2015, are less than $1 million and $4 million, respectively, of amortization of unproved leasehold costs. In addition, in the first quarter of 2015, we recorded approximately $2 million for the early termination of contracts for drilling rigs, released in response to the lower price environment.

Taxes, other than income taxes. Taxes, other than income taxes for the quarters ended March 31, 2016 and 2015, were $14 million and $22 million, respectively. Production taxes decreased in 2016 compared to the same period in 2015 due to the significant impact on severance taxes of lower commodity prices.

Table of Contents

Cash Operating Costs and Adjusted Cash Operating Costs. We monitor cash operating costs required to produce our oil and natural gas. Cash operating costs is a non-GAAP measure calculated on a per Boe basis and includes total operating expenses less depreciation, depletion and amortization expense, transportation costs, exploration expense, oil and natural gas purchases and other expenses. Adjusted cash operating costs is a non-GAAP measure and is defined as cash operating costs less transition, restructuring and other non-recurring costs, and the non-cash portion of compensation expense (which represents compensation expense under our long-term incentive programs adjusted for cash payments made under our long-term incentive plans). We believe cash operating costs and adjusted cash operating costs per unit are valuable measures of operating performance and efficiency; however, these measures may not be comparable to similarly titled measures used by other companies. The table below represents a reconciliation of our cash operating costs and adjusted cash operating costs to operating expenses for the quarters ended March 31:



	Quarter ended March 31,
	2016						2015
	Total			Per Unit⁽¹⁾			Total			Per Unit⁽¹⁾
	(in millions, except per unit costs)
Total operating expenses	$	242		$	25.61		$	380		$	41.27

Depreciation, depletion and amortization	(113		)	(11.94		)	(224		)	(24.30		)
Transportation costs	(30		)	(3.11		)	(27		)	(2.90		)
Exploration expense	(1		)	(0.13		)	(5		)	(0.51		)
Oil and natural gas purchases	(4		)	(0.46		)	(7		)	(0.74		)
Total cash operating costs	94			9.97			117			12.82
Transition/restructuring costs, non-cash portion of compensation expense and other⁽²⁾	(12		)	(1.26		)	(12		)	(1.38		)
Total adjusted cash operating costs and adjusted per-unit cash costs	$	82		$	8.71		$	105		$	11.44

Total equivalent volumes (MBoe)	9,466						9,218


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

(2)

For the quarter ended March 31, 2016, amount includes approximately $8 million of transition and severance costs related to restructuring and $4 million of non-cash compensation expense, adjusted for cash payments made on long-term incentive plans of less than $1 million. For the quarter ended March 31, 2015, amount includes $8 million of transition and severance costs related to restructuring and $5 million of non-cash compensation expense, adjusted for cash payments made on long-term incentive plans of less than $1 million.

The table below displays the average cash operating costs and adjusted cash operating costs per equivalent unit:



	Quarter ended March 31,
	2016			2015
Average cash operating costs ($/Boe)
Lease operating expenses	$	4.38		$	5.12
Production taxes⁽¹⁾	1.27			2.13
General and administrative expenses⁽²⁾	4.04			5.09
Taxes, other than production and income taxes	0.28			0.28
Other expenses⁽³⁾	—			0.20
Total cash operating costs	9.97			12.82
Transition/restructuring costs, non-cash portion of compensation expense and other⁽²⁾	(1.26		)	(1.38		)
Total adjusted cash operating costs	$	8.71		$	11.44


(1)	Production taxes include ad valorem and severance taxes which decreased during the quarter ended March 31, 2016 due primarily to lower commodity prices.


(2)	For additional detail of adjusted items, which are part of general and administrative expenses, refer to the reconciliation of cash operating costs and adjusted cash operating costs above.


(3)	Includes early rig termination fees of $2 million incurred during the first quarter of 2015.

Table of Contents

Other Income Statement Items.

Gain on extinguishment of debt. During the first quarter of 2016, we paid approximately $143 million in cash to repurchase a total of approximately $345 million in aggregate principal amount of our senior unsecured notes. We recorded a gain on extinguishment of debt of approximately $196 million (including $6 million of non-cash expense related to eliminating associated unamortized debt issue costs).

Income Taxes. For the quarter ended March 31, 2016, our effective tax rate was 0%. Our effective tax rate differed from the statutory rate as a result of adjustments to the valuation allowance on our deferred tax assets which offset deferred income tax expense by $35 million (See Part I, Item 1, Financial Statements, Note 3). The effective tax rate for the quarter ended March 31, 2015 was relatively consistent with the statutory tax rate.

Table of Contents

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 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 our long-term incentive plans), transition, restructuring and other non-recurring costs and gains on extinguishment of debt.

We believe that the presentation of EBITDAX and Adjusted EBITDAX is important to provide management and investors with additional information (i) to evaluate our ability to service debt adjusting for items required or permitted in calculating covenant compliance under our debt agreements, (ii) to provide an important supplemental indicator of the operational performance of our business, (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 EBITDAX and Adjusted EBITDAX to our consolidated net income:



	Quarter ended March 31,
	2016			2015
	(in millions)
Net income	$	94		$	19
Income tax expense	—			10
Interest expense, net of capitalized interest	84			84
Depreciation, depletion and amortization	113			224
Exploration expense	1			5
EBITDAX	292			342
Mark-to-market on financial derivatives⁽¹⁾	(42		)	(203		)
Settlements and cash premiums on financial derivatives⁽²⁾	212			214
Non-cash portion of compensation expense⁽³⁾	4			5
Transition, restructuring and other costs⁽⁴⁾	8			8
Gain on extinguishment of debt	(196		)	—
Adjusted EBITDAX	$	278		$	366


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


(2)	Represents actual settlements related to financial derivatives, including cash premiums. No cash premiums were received or paid for the quarters ended March 31, 2016 and 2015.


(3)	For both the quarters ended March 31, 2016 and 2015, cash payments were less than $1 million.


(4)	Reflects transition and severance costs related to restructuring for the quarters ended March 31, 2016 and 2015.

Table of Contents

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 $1.6 billion as of March 31, 2016, and on a pro-forma basis was approximately $0.8 billion following the redetermination of our RBL Facility and other actions completed as further described below.

During 2016, we have taken a number of steps to improve our liquidity, strengthen our balance sheet and expand our financial flexibility. These steps have included (i) completing the sale of our Haynesville Shale assets for approximately $420 million (net proceeds of approximately $395 million) in May 2016, (ii) repurchasing for cash or entering into agreements to repurchase a total of $609 million in aggregate principal amount ($345 million repurchased as of March 31, 2016) of our unsecured notes and/or term loans for approximately $287 million ($143 million as of March 31, 2016) in cash which is expected to reduce our annual interest expense costs by approximately $49 million and (iii) completing the semi-annual redetermination of our RBL Facility in May 2016.

The RBL redetermination resulted in a revised borrowing base of $1.65 billion, reflecting significantly lower bank commodity price forecasts, the sale of our Haynesville assets and the roll-off of certain hedge positions. In conjunction with the redetermination, we amended certain restrictive debt covenants for 2017 and through the first quarter of 2018, the most significant of which suspended the requirement that our debt to EBITDAX ratio, as defined in the credit agreement, not exceed 4.5 to 1.0 which was replaced with a requirement that our ratio of first lien debt to EBITDAX not exceed 3.5 to 1.0. However, the 4.5 to 1.0 debt to EBITDAX requirement will be reinstated beginning in April 2018. We also agreed to limit debt repurchases to $350 million subject to certain future adjustments. Our RBL facility matures in 2019 subject to retiring or refinancing certain senior secured term loans six months prior to their maturity as further noted in Long-Term Debt below and Part I, Item 1, Financial Statements, Note 7. Our next redetermination date for the RBL Facility is in November 2016. Downward revisions of our oil and natural gas reserves volume and value due to declines in commodity prices, the impact of lower estimated capital spending in response to lower prices, performance revisions, sales of assets or the incurrence of certain types of additional debt, among other items, could cause a further reduction of our borrowing base in the future, and these reductions could be significant.

As a result of the revisions to our RBL Facility borrowing base, the sale of our Haynesville Shale assets and repurchases of our debt subsequent to March 31, 2016, our available liquidity as of March 31, 2016, on a pro-forma basis reflecting these items would have been approximately $0.8 billion. For the remainder of 2016, we have derivative contracts providing us commodity price protection on a significant portion of our anticipated oil production. These derivative contracts, which are primarily fixed price swaps, allow us to realize a weighted average price of $80.29 per barrel on a remaining 11 MMBbls of oil in 2016. We also have derivative contracts where we have effectively “locked-in” approximately $40.00 per barrel in cash settlements on an additional 3.1 MMBbls of oil in 2016. For 2017, we have derivative contracts on 5.1 MMBbls of our anticipated oil production at a weighted average price of $65.87 per barrel of oil. See "Our Business" for further information on our derivative instruments.

Based upon our actions to date, we believe our liquidity, and expected cash flows from 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 extreme ongoing volatility in the energy industry and 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 core drilling programs, (ii) meeting our debt maturities, and (iii) managing and working to strengthen our balance sheet. We continue to implement various cost saving measures to reduce our capital, operating, and general and administrative costs including renegotiating contracts with contractors, suppliers and service providers, reducing the number of staff and contractors and deferring and eliminating various discretionary costs. 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.

Table of Contents

To the extent commodity prices remain low or decline further, or we experience disruptions in the financial markets impacting our longer-term access to or 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 may make changes to our capital structure 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 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 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 additional assets, liquidating all or a portion of our hedge portfolio, seeking additional partners to develop our assets, and/or further reducing our planned capital program.

Capital Expenditures. For the full year 2016, we expect our capital expenditures will be between $500 million to $900 million, exclusive of acquisition capital. Our capital expenditures and average drilling rigs by area for the quarter ended March 31, 2016 were:



	Capital Expenditures⁽¹⁾ (in millions)		Average Drilling Rigs
Eagle Ford Shale	$	75	2.0
Wolfcamp Shale	37		0.3
Altamont	17		1.0
Haynesville Shale	3		—
Total	$	132	3.3

(1) Represents accrual-based capital expenditures.

Debt. As of March 31, 2016, our total debt was approximately $4.6 billion, comprised of $2.8 billion in senior notes due in 2020, 2022 and 2023, $647 million in senior secured term loans with maturity dates in 2018 and 2019 and $1.2 billion outstanding under the RBL Facility expiring in 2019 (provided that we refinance or retire remaining amounts outstanding under our (i) $500 million senior secured term loans due 2018 by November 2017 and (ii) $150 million senior secured term loans due 2019 by November 2018). 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.

Table of Contents

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



	Quarter ended March 31,
	2016			2015
Cash Flow from Operations
Operating activities
Net income	$	94		$	19
Other income adjustments	(74		)	247
Changes in assets and liabilities	281			25
Total cash flow from operations	$	301		$	291

Other Cash Inflows
Financing activities
Proceeds from issuance of long-term debt	325			364
Total cash inflows	$	325		$	364

Cash Outflows
Investing activities
Capital expenditures	$	179		$	432
	$	179		$	432
Financing activities
Repayments and repurchases of long-term debt	380			236
Purchases of treasury stock	2			—
	382			236
Total cash outflows	$	561		$	668

Net change in cash and cash equivalents	$	65		$	(13	)

Table of Contents

Item 3. Qualitative and Quantitative Disclosures About Market Risk

This information updates, and should be read in conjunction with the information disclosed in our 2015 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 2015 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 March 31, 2016:



			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⁾	$	601	$	539	$	(62	)	$	662	$	61



			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⁾	$	601	$	598	$	(3	)	$	604	$	3
Credit rate⁽³⁾	$	601	$	598	$	(6	)	$	604	$	3


(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 March 31, 2016, we carried out an evaluation under the supervision and with the participation of our management, including our Chief Executive Officer (CEO) and our Chief Financial Officer (CFO), as to the effectiveness, design and operation of our disclosure controls and procedures. This evaluation considered the various processes carried out under the direction of our disclosure committee in an effort to ensure that information required to be disclosed in the U.S. Securities and Exchange Commission reports we file or submit under the Securities Exchange Act of 1934, as amended (Exchange Act), is accurate, complete and timely. Our management, including our CEO and our CFO, does not expect that our disclosure controls and procedures or our internal controls will prevent and/or detect all errors and all fraud. A control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Further, the design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, within our company have been detected. Our disclosure controls and procedures are designed to provide reasonable assurance of achieving their objectives and our CEO and CFO concluded that our disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) were effective as of March 31, 2016.

Changes in Internal Control over Financial Reporting

There were no changes in EP Energy Corporation’s internal control over financial reporting during the first three months of 2016 that materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

Table of Contents

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 2015 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.

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: May 5, 2016	/s/ Dane E. Whitehead
	Dane E. Whitehead
	Executive Vice President and Chief Financial Officer
	(Principal Financial Officer)


Date: May 5, 2016	/s/ Francis C. Olmsted III
	Francis C. Olmsted III
	Vice President and Controller
	(Principal Accounting Officer)

Table of Contents

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

2.1^#		Purchase and Sale Agreement, dated as of March 18, 2016, by and among EP Energy E&P Company, L.P., EP Energy Management, L.L.C., and Crystal E&P Company, L.L.C., as Seller, and Covey Park Gas LLC, as Buyer. (Exhibit 2.1 to Company's Current Report on Form 8-K, filed with the SEC on May 4, 2016).

*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.



#		The exhibits and schedules to this agreement have been omitted from this filing pursuant to Item 601(b)(2) of Regulation S-K. A list of the exhibits and schedules is included after the table of contents in the agreement. The Company will furnish copies of such exhibits and schedules to the Securities and Exchange Commission upon request.

Attached files

Stock widget

Investing forum

EP Energy Corp Reports