EP Energy Corp - FORM 10-Q

Attached files

file	filename
EXCEL - IDEA: XBRL DOCUMENT - EP Energy Corp	Financial_Report.xls
EX-32.1 - EX-32.1 - EP Energy Corp	a14-14201_1ex32d1.htm
EX-31.2 - EX-31.2 - EP Energy Corp	a14-14201_1ex31d2.htm
EX-31.1 - EX-31.1 - EP Energy Corp	a14-14201_1ex31d1.htm
EX-32.2 - EX-32.2 - EP Energy Corp	a14-14201_1ex32d2.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 June 30, 2014

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) 997-1200

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 o

Non-accelerated filer x		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 August 1, 2014: 244,939,724

Class B Common Stock, par value $0.01 per share. Shares outstanding as of August 1, 2014: 822,052

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	15
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	28
Item 4.	Controls and Procedures	28

PART II — OTHER INFORMATION

Item 1.	Legal Proceedings	29
Item 1A.	Risk Factors	29
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	29
Item 3.	Defaults Upon Senior Securities	29
Item 4.	Mine Safety Disclosures	29
Item 5.	Other Information	29
Item 6.	Exhibits	29
Signatures		30

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
CBM	=	coal bed methane
Gal	=	gallons
LLS	=	light Louisiana sweet crude oil
Mboe	=	thousand barrels of oil equivalent
MBbls	=	thousand barrels
Mcf	=	thousand cubic feet
MMGal	=	million gallons
MMBtu	=	million British thermal units
MMBbls	=	million barrels
MMcf	=	million cubic feet
MMcfe	=	million cubic feet of natural gas equivalents
NGLs	=	natural gas liquids
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 variances 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 2013 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)

	Quarters ended June 30,						Six months ended June 30,
	2014			2013			2014			2013

Operating revenues
Oil	$	461		$	284		$	867		$	541
Natural gas	75			91			153			165
NGLs	30			15			57			29
Financial derivatives	(290		)	166			(425		)	35
Total operating revenues	276			556			652			770

Operating expenses
Natural gas purchases	5			8			8			10
Transportation costs	26			22			49			42
Lease operating expense	50			36			94			71
General and administrative	42			55			175			113
Depreciation, depletion and amortization	214			137			406			253
Exploration expense	5			13			13			25
Taxes, other than income taxes	34			13			67			34
Total operating expenses	376			284			812			548

Operating (loss) income	(100		)	272			(160		)	222
Other income	—			5			—			7
Loss on extinguishment of debt	—			(2		)	(17		)	(3		)
Interest expense	(80		)	(86		)	(159		)	(178		)
(Loss) income from continuing operations before income taxes	(180		)	189			(336		)	48
Income tax benefit	(68		)	—			(124		)	—
(Loss) income from continuing operations	(112		)	189			(212		)	48
(Loss) income from discontinued operations, net of tax	(6		)	12			4			39
Net (loss) income	$	(118	)	$	201		$	(208	)	$	87

Basic and diluted net income (loss) per common share
(Loss) income from continuing operations	$	(0.46	)	$	0.90		$	(0.88	)	$	0.23
(Loss) income from discontinued operations, net of tax	(0.03		)	0.06			0.01			0.19
Net (loss) income	$	(0.49	)	$	0.96		$	(0.87	)	$	0.42
Basic and diluted weighted average common shares outstanding	244			209			240			209

See accompanying notes.

Table of Contents

EP ENERGY CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS

(In millions)

(Unaudited)

	June 30, 2014		December 31, 2013

ASSETS
Current assets
Cash and cash equivalents	$	77	$	51
Accounts receivable
Customer, net of allowance of less than $1 in 2014 and 2013	275		231
Other, net of allowance of $1 in 2014 and 2013	24		43
Materials and supplies	20		20
Derivative instruments	3		47
Assets of discontinued operations	68		293
Deferred income taxes	138		28
Prepaid assets	7		10
Total current assets	612		723
Property, plant and equipment, at cost
Oil and natural gas properties	9,288		8,136
Other property, plant and equipment	71		56
	9,359		8,192
Less accumulated depreciation, depletion and amortization	1,147		770
Total property, plant and equipment, net	8,212		7,422
Other assets
Derivative instruments	2		97
Unamortized debt issue costs	101		116
Other	8		8
	111		221
Total assets	$	8,935	$	8,366

See accompanying notes.

Table of Contents

EP ENERGY CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS

(In millions)

(Unaudited)

	June 30, 2014			December 31, 2013

LIABILITIES AND EQUITY
Current liabilities
Accounts payable
Trade	$	180		$	135
Other	396			386
Income tax payable	8			2
Derivative instruments	154			35
Accrued interest	53			54
Asset retirement obligations	2			2
Liabilities of discontinued operations	85			125
Other accrued liabilities	61			63
Total current liabilities	939			802

Long-term debt	4,295			4,421
Other long-term liabilities
Derivative instruments	112			—
Deferred income taxes	145			171
Asset retirement obligations	35			28
Other	5			7
Total non-current liabilities	4,592			4,627

Commitments and contingencies (Note 8)

Stockholders’ equity
Class A shares, $0.01 par value; 550 million shares authorized; 245 million shares issued and outstanding at June 30, 2014; 209 million shares issued and outstanding at December 31, 2013	2			—
Class B shares, $0.01 par value; 0.8 million and 0.9 million shares authorized, issued and outstanding at June 30, 2014 and December 31, 2013	—			—
Preferred stock, $0.01 par value; 50 million shares authorized; no shares issued or outstanding	—			—
Additional paid-in capital	3,505			2,832
(Accumulated deficit) Retained earnings	(103		)	105
Total stockholders’ equity	3,404			2,937
Total liabilities and equity	$	8,935		$	8,366

See accompanying notes.

Table of Contents

EP ENERGY CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(In millions)

(Unaudited)

	Six months ended June 30,
	2014			2013

Cash flows from operating activities
Net (loss) income	$	(208	)	87
Adjustments to reconcile net (loss) income to net cash provided by operating activities
Depreciation, depletion and amortization	414			318
Impairment charges	15			10
Deferred income tax benefit	(136		)	—
Loss on extinguishment of debt	17			3
Amortization of equity compensation expense	10			13
Non-cash portion of exploration expense	11			24
Amortization of debt issuance costs	11			12
Other	—			11
Asset and liability changes
Accounts receivable	(21		)	(23		)
Accounts payable	3			61
Derivative instruments	370			(21		)
Accrued interest	(1		)	(2		)
Other asset changes	6			(15		)
Other liability changes	(2		)	(28		)
Net cash provided by operating activities	489			450

Cash flows from investing activities
Capital expenditures	(988		)	(914		)
Net proceeds from the sale of assets	150			10
Cash paid for acquisitions, net of cash acquired	(154		)	(2		)
Net cash used in investing activities	(992		)	(906		)

Cash flows from financing activities
Proceeds from long-term debt	1,300			985
Repayment of long-term debt	(1,440		)	(305		)
Proceeds from issuance of stock	669			—
Other	—			(10		)
Net cash provided by financing activities	529			670

Change in cash and cash equivalents	26			214
Cash and cash equivalents
Beginning of period	51			69
End of period	$	77		$	283

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				Additional Paid-in		(Accumulated deficit) Retained
	Shares	Amount		Shares		Amount		Capital		Earnings			Total
Balance at December 31, 2013	209	$	—	0.9		$	—	$	2,832	$	105		$	2,937
Share-based compensation	1	—		(0.1	)	—		6		—			6
Initial public offering of common stock	35	2		—		—		667		—			669
Net loss	—	—		—		—		—		(208		)	(208		)
Balance at June 30, 2014	245	$	2	0.8		$	—	$	3,505	$	(103	)	$	3,404

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 Stated Securities and Exchange Commission (SEC) and in accordance with United States generally accepted accounting principles (U.S. GAAP) as it applies to interim condensed consolidated 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 2013 Annual Report on Form 10-K. The condensed consolidated financial statements as of June 30, 2014 and 2013 are unaudited. The consolidated balance sheet as of December 31, 2013 has been derived from the audited consolidated balance sheet included in our 2013 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 2013 Annual Report on Form 10-K.

New Accounting Pronouncements Issued But Not Yet Adopted

The following accounting standards have been issued but not yet been adopted.

Revenue Recognition. In May 2014, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update 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. Retrospective application of this standard is required beginning in the first quarter of 2017. We are currently evaluating the impact, if any, that this standard will have on our financial statements.

Discontinued Operations. In April 2014, the FASB issued Accounting Standards Update No. 2014-08, Presentation of Financial Statements and Property, Plant, and Equipment: Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity, which alters the criteria under which assets to be disposed of are evaluated for reporting as a discontinued operation. While early adoption of this standards update is permitted, prospective application is required in the first quarter of 2015. Accordingly, the standard will not impact our historical presentation of assets as discontinued operations. We are currently evaluating the requirements of the standards update that could impact future disposal transactions subsequent to implementation.

2. Acquisitions and Divestitures

Acquisitions. On April 30, 2014, we acquired approximately 37,000 net acres of certain producing properties and undeveloped acreage in the Southern Midland Basin adjacent to our existing Wolfcamp Shale position for an aggregate cash purchase price of approximately $152 million. The acquisition represents an approximate 25 percent expansion of our current Wolfcamp acreage. The fair value of the business acquired was allocated to the underlying properties and no goodwill or bargain purchase was recorded.

Discontinued Operations. We have reflected as discontinued operations certain non-core assets sold or in the process of being sold including (i) certain domestic natural gas assets in our Arklatex area and those in our South Louisiana Wilcox areas sold in May 2014, (ii) domestic natural gas assets sold in June 2013 (including CBM properties located in the Raton, Black Warrior and Arkoma basins; Arklatex conventional natural gas assets located in East Texas and North Louisiana, and legacy South Texas conventional natural gas assets) and (iii) our Brazilian operations which are under contract to be sold. We expect the sale of our Brazilian operations (which represents the sale of our remaining international assets) to close in 2014, subject to Brazilian regulatory approval and certain other customary closing conditions.

We have classified the assets and liabilities associated with these properties as discontinued operations in our condensed consolidated balance sheets in this Form 10-Q in periods prior to the completion of the sale. We have classified the results of operations of these assets as income (loss) from discontinued operations in all periods presented.

Table of Contents

Summarized operating results and financial position data of our discontinued operations were as follows (in millions):

	Quarters ended June 30,						Six months ended June 30,
	2014			2013			2014		2013

Operating revenues	$	37		$	125		$	68	$	248

Operating expenses
Natural gas purchases	—			8			—		16
Transportation costs	2			10			5		19
Lease operating expense	12			32			25		61
Depreciation, depletion and amortization	2			32			8		65
Impairment charges(1)	12			10			15		10
Other expense	8			17			13		34
Total operating expenses	36			109			66		205

(Loss) gain on sale of assets	(12		)	—			1		—
Other income (expense)	2			(3		)	5		(2		)
(Loss) income from discontinued operations before income taxes	(9		)	13			8		41
Income tax (benefit) expense	(3		)	1			4		2
(Loss) income from discontinued operations, net of tax	$	(6	)	$	12		$	4	$	39

(1) During the quarter and six months ended June 30, 2014, we recorded $12 million and $15 million in impairment charges to impair earnings subsequent to entering into a Quota Purchase Agreement to sell our Brazil operations. During the quarter and six months ended June 30, 2013, we also recorded a $10 million impairment charge based on a comparison of the fair value of our Brazil operations to its underlying carrying value.

	June 30, 2014		December 31, 2013
Assets of discontinued operations
Current assets	$	26	$	37
Property, plant and equipment, net	37		246
Other non-current assets	5		10
Total assets of discontinued operations	$	68	$	293

Liabilities of discontinued operations
Accounts payable	$	42	$	50
Other current liabilities	6		10
Asset retirement obligations	37		60
Other non-current liabilities	—		5
Total liabilities of discontinued operations	$	85	$	125

Other Divestitures. During the first quarter of 2013, we received approximately $10 million from the sale of certain domestic oil and natural gas properties. No gain or loss was recorded on this sale.

3. Income Taxes

General. Prior to August 30, 2013, we conducted our activities through EPE Acquisition, LLC, a holding company formed on February 14, 2012. On August 30, 2013, we reorganized our structure to form EP Energy Corporation, a new corporate holding company (Corporate Reorganization). As a result of the Corporate Reorganization, we became a corporation subject to federal and state income taxes. Accordingly, we began recording the effects of income taxes in our financial statements. We are currently not under any U.S. or state income tax audits and we have no uncertain tax positions from our continuing operations.

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 are recorded in the period in which they occur. Changes in tax laws or rates are recorded in the period they are enacted. For the quarter and six months ended June 30, 2014, we recorded an income tax benefit of $68 million and $124 million, respectively. Our effective tax rates for the quarter and six months ended June 30, 2014 were 38% and 37%, respectively, which differ from the statutory federal tax rate of 35% as a result of the effects of state income taxes and non-deductible compensation expense, substantially offset by the tax effects of discrete adjustments for certain transaction costs related to our initial public offering. For the quarter and six months ended June 30, 2013, we were a partnership not subject to federal and state income taxes. If we had recorded income taxes effective January 1, 2013, through June 30,

Table of Contents

2013, pro forma income from continuing operations would have been approximately $32 million based on applying a federal statutory tax rate of 35%.

4. Earnings Per Share

On January 2, 2014, we completed a 62.553-for-1 stock split of our common stock. For the quarter and six months ended June 30, 2013, we retrospectively reflected earnings per common share/earnings per member unit (each member unit was converted into an equivalent common share in connection with the August 2013 Corporate Reorganization), giving effect to the stock split. On January 23, 2014, we completed a public offering of 35.2 million shares of Class A Common Stock, $0.01 par value 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. These potentially dilutive securities consist of our employee stock options and restricted stock. For the quarter and six months ended June 30, 2014, we incurred losses from continuing operations and accordingly excluded all potentially dilutive securities from the determination of diluted earnings per share as their impact on loss per common share was antidilutive.

5. Financial Instruments

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

	June 30, 2014						December 31, 2013
	Carrying Amount			Fair Value			Carrying Amount		Fair Value
	(in millions)
Long-term debt	$	4,295		$	4,683		$	4,421	$	4,841

Derivative instruments — (liability)/asset	$	(261	)	$	(261	)	$	109	$	109

As of June 30, 2014 and December 31, 2013, 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 (see Note 7) 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 related to these instruments.

Oil, Natural Gas and NGLs Derivative Instruments. We attempt to mitigate a portion of our commodity price risk and stabilize cash flows associated with forecasted sales of oil, natural gas and NGLs through the use of financial derivatives. As of June 30, 2014 and December 31, 2013, we had total derivative contracts on 48 MMBbls and 47 MMBbls of oil and 108 TBtu and 135 TBtu of natural gas, respectively. As of June 30, 2014, we also had derivative contracts on 23 MMGal of propane. None of these contracts are designated as accounting hedges. From July 1, 2014 to August 4, 2014, we added 0.1 MMBbls of LLS fixed price swaps on our anticipated 2014 production, 1.5 MMBbls of LLS hedges on our anticipated 2016 production, and entered into offsetting positions on 3 TBtu of natural gas fixed price swaps related to our anticipated 2014 production in conjunction with the sale of certain natural gas assets.

Interest Rate Derivative Instruments. We have interest rate swaps with a notional amount of $600 million that extend through April 2017 and are intended to reduce variable interest rate risk. As of June 30, 2014 and December 31, 2013, we had a net asset of $2 million and $4 million, respectively, related to interest rate derivative instruments included in our consolidated balance sheets. For the quarters ended June 30, 2014 and 2013, we recorded $3 million in interest expense and $8 million in interest income related to the change in fair market value and cash settlements of our interest rate derivative instruments, respectively. For the six months ended June 30, 2014 and 2013, we recorded $4 million in interest expense and $7 million in interest income, respectively, related to the change in fair market value and cash settlements of our interest rate derivative instruments.

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 values of our financial instruments into three levels (Levels 1, 2 and 3) based on our assessment of the availability of observable market data and the significance of non-observable data used to determine fair value. As of June 30, 2014 and December 31, 2013, all financial instruments were classified as Level 2. Our assessment of an instrument within a level can change over time based on the maturity or liquidity of the instrument, which could result in a change in the classification of our financial instruments between other levels.

Financial Statement Presentation. The following table presents the fair value associated with derivative financial instruments as of June 30, 2014 and December 31, 2013. 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

Table of Contents

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.

	Level 2
	Derivative Assets									Derivative Liabilities
	Gross(1)					Balance Sheet Location				Gross(1)					Balance Sheet Location
	Fair value		Impact of Netting			Current		Non- current		Fair value			Impact of Netting		Current			Non- current
	(in millions)									(in millions)
June 30, 2014
Derivative instruments	$	62	$	(57	)	$	3	$	2	$	(323	)	$	57	$	(154	)	$	(112	)

December 31, 2013
Derivative instruments	$	164	$	(20	)	$	47	$	97	$	(55	)	$	20	$	(35	)	$	—

(1) Gross derivative assets are comprised primarily of $57 million of oil, natural gas and NGLs derivatives as of June 30, 2014, $157 million of oil and natural gas derivatives as of December 31, 2013, $5 million of interest rate derivatives as of June 30, 2014, and $7 million of interest rate derivatives as of December 31, 2013. Gross derivative liabilities are comprised primarily of $320 million of oil, natural gas and NGLs derivatives as of June 30, 2014, $52 million of oil and natural gas derivatives as of December 31, 2013, and $3 million of interest rate derivatives for each of the periods ended June 30, 2014 and December 31, 2013.

For the quarters ended June 30, 2014 and 2013, we recorded a derivative loss of $290 million and a derivative gain of $166 million, respectively, on our oil, natural gas and NGLs financial derivative instruments. For the six months ended June 30, 2014 and 2013, we recorded a derivative loss of $425 million and a derivative gain of $35 million, respectively. Derivative gains and losses are recorded in operating revenues in our consolidated income statement.

6. Property, Plant and Equipment

General. As of June 30, 2014 and December 31, 2013, we had $1.1 billion and $1.4 billion of unproved oil and natural gas properties on our consolidated balance sheet, respectively. During the six months ended June 30, 2014, we transferred approximately $0.4 billion from unproved properties to proved properties. For the quarters ended June 30, 2014 and 2013, we recorded $4 million and $13 million, respectively, of amortization of unproved leasehold costs in exploration expense in our consolidated income statement. For the six months ended June 30, 2014 and 2013 we recorded $11 million and $24 million of amortization of unproved leasehold costs in exploration expense in our consolidated income statement. Suspended well costs were not material as of June 30, 2014 or December 31, 2013. For a discussion of our impairment assessment of oil and natural gas properties see Note 3 to our 2013 Annual Report on Form 10-K.

Asset Retirement Obligations. We have legal asset retirement obligations associated with the retirement of our oil and natural gas wells and related infrastructure. We incur 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 of 7 percent and a projected inflation rate of 2.5 percent. The net asset retirement liability as of June 30, 2014 on our consolidated balance sheet in other current and non-current liabilities and the changes in the net liability from January 1 through June 30, 2014 were as follows:

	2014
	(in millions)
Net asset retirement liability at January 1	$	30
Liabilities incurred	6
Liabilities settled	(1		)
Accretion expense	1
Changes in estimate	2
Other	(1		)
Net asset retirement liability at June 30	$	37

Capitalized Interest. Interest expense is reflected in our financial statements net of capitalized interest. Capitalized interest for the quarter and six months ended June 30, 2014 was approximately $5 million and $10 million, respectively. Capitalized interest for the quarter and six months ended June 30, 2013 was approximately $3 million and $8 million, respectively.

Table of Contents

7. Long-Term Debt

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

	Interest Rate	June 30, 2014
		(in millions)
$2.5 billion RBL credit facility - due May 24, 2017	Variable	$	550
$750 million senior secured term loan - due May 24, 2018(1)(3)	Variable	495
$400 million senior secured term loan - due April 30, 2019(2)(3)	Variable	150
$750 million senior secured notes - due May 1, 2019(3)	6.875%	750
$2.0 billion senior unsecured notes - due May 1, 2020	9.375%	2,000
$350 million senior unsecured notes - due September 1, 2022	7.75%	350
Total		$	4,295

(1) The term loan was issued at 99 percent 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 June 30, 2014, the effective interest rate of the term loan was 3.50%.

(2) The term loan carries interest at a specified margin over the LIBOR of 3.50%, with a minimum LIBOR floor of 1.00%.

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

As of June 30, 2014 and December 31, 2013, we had $101 million and $116 million, respectively, in deferred financing costs on our consolidated balance sheets. During the quarters and six months ended June 30, 2014 and 2013, we amortized $6 million and $11 million of deferred financing costs, respectively, in interest expense.

During the first quarter of 2014, we repaid and retired our senior PIK toggle note with a portion of the proceeds from our initial public offering. During the quarter ended June 30, 2013 and each of the six month periods ended June 30, 2014 and 2013, we recorded $2 million, $17 million and $3 million, respectively, in losses on the extinguishment of debt in our consolidated income statement. In 2014, these losses resulted from the retirement of the PIK toggle note. In 2013, the losses were associated with writing off the pro-rata portion of deferred financing costs in conjunction with our $750 million term loan repricing in May 2013 and the semi-annual redetermination of our RBL Facility in March 2013.

$2.5 Billion Reserve-based Loan (RBL). Under the RBL Facility, we can borrow funds or issue letters of credit and as of June 30, 2014, we had a $2.5 billion RBL borrowing base, $550 million of outstanding borrowings and approximately $8 million of letters of credit issued under the facility, leaving $1.9 billion of remaining capacity. As of August 4, 2014, we had $650 million in outstanding borrowings under the facility.

The RBL Facility is collateralized by certain of our oil and natural gas properties and has a borrowing base subject to semi-annual redeterminations. In April 2014, we completed our semi-annual redetermination maintaining the borrowing base of our RBL Facility at $2.5 billion. Downward revisions of our oil and natural gas reserves due to future declines in commodity prices, performance revisions, sales of assets or the incurrence of certain types of additional debt, among other items, could cause a redetermination of the borrowing base and could negatively impact our ability to borrow funds under the RBL Facility in the future.

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. There have been no significant changes to our restrictive covenants, and as of June 30, 2014, we were in compliance with all of our debt covenants. For a further discussion of our debt agreements and restrictive covenants, see our 2013 Annual Report on Form 10-K.

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 of these matters, we evaluate the merits of the case or claim, our exposure to the matter, possible legal or settlement strategies and the likelihood of an unfavorable outcome. If we determine that an unfavorable outcome is probable and can be estimated, we establish the necessary accruals. While the outcome of our current matters cannot be predicted with certainty and there are still uncertainties related to the costs we may incur, based upon our evaluation and experience to date, we believe we have established appropriate reserves for these matters. It is possible, however, that new information or future developments could require

Table of Contents

us to reassess our potential exposure related to these matters and adjust our accruals accordingly, and these adjustments could be material. As of June 30, 2014, we had less than $1 million accrued for all outstanding legal matters.

Southeast Louisiana Flood Protection Authority v. EP Energy Management, L.L.C. The levee authority for New Orleans and surrounds has filed a lawsuit against 97 oil, gas and pipeline companies, seeking (among other relief) restoration of wetlands allegedly lost due to historic industry operations in those areas. The suit, which does not specify an amount of damages, was filed in Louisiana state court in New Orleans but then removed to the U.S. District Court for the Eastern District of Louisiana. The Louisiana State Legislature has passed legislation that could result in dismissal of the lawsuit. Our subsidiary, EP Energy Management, L.L.C., is named as successor to Colorado Oil Company, Inc. and Gas Producing Enterprises as operators of five wells from the mid-1970s to 1980. The validity of the causes of action as well as our costs and legal exposure, if any, related to the lawsuit are not currently determinable.

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, plugging and abandonment obligations for assets no longer owned or operated by us. As of June 30, 2014, we had approximately $5 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. 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 June 30, 2014, we had accrued 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 exposure could be as high as $1 million. 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 Environmental Protection Agency (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. At this time we do not expect a material impact to our existing operations. There have also been various legislative and regulatory proposals and final rules at the federal and state levels to address emissions from power plants and industrial boilers. Although such rules and proposals will generally favor the use of natural gas over other fossil fuels such as coal, it remains uncertain what regulations will ultimately be adopted and when they will be adopted. As part of the White House’s Climate Action Plan, the EPA intends to examine technical white papers about methane emissions in the oil and gas industry and may propose additional regulations in 2016. Further, the Bureau of Land Management may propose additional regulations for public lands in 2014. 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.

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. In July 2014, EPA proposed additional amendments to the new standard for which we would not anticipate material capital expenditure, if the amendments as proposed become final.

Table of Contents

The EPA has promulgated regulations to require pre-construction permits for minor sources of air emissions in tribal lands as of September 2, 2014. On May 22, 2014, the EPA extended this deadline to March 2, 2016, during which time the EPA anticipates separate rulemaking to create general permits for true minor sources in the oil and gas production industry. Until such regulations are adopted, it is uncertain what impact they might have on our operations in tribal lands.

In the State of Utah we are currently obtaining or amending air quality permits for a number of small oil and natural gas production facilities. As part of this permitting process, we anticipate that we will incur less than $1 million during the remainder of 2014.

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, the Department of Interior 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.

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 June 30, 2014, 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.

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 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) awards currently include a cash-based incentive award and certain equity-based compensation programs, as further described in our 2013 Annual Report on Form 10-K. During the quarter ended June 30, 2014, we issued 1,103,938 shares of restricted common stock and granted 253,740 stock options as compensation for future service. Under our stock-based compensation plans, we are authorized to grant awards of up to 12,433,749 shares of our common stock. The restricted stock granted had a grant date fair value of $19.82 per share equal to the market value of our stock on the grant date, and stock options issued had a grant date fair value of $9.03 per option granted. The fair value of each stock option granted was estimated on the date of grant using a Black-Scholes option-pricing model based on several assumptions utilizing management’s best estimate at the time of grant. These assumptions included an expected term of 7 years, volatility of approximately 40 percent, a risk free rate of approximately 2.3%, and assumed no dividend yield. We estimated expected volatility based on an analysis of historical stock price volatility of a group of similar publicly traded peer companies which share similar characteristics with us over the expected term because our stock has been publicly traded for a very short period of time. We estimate the expected term of our option awards based on the vesting period and average remaining contractual term, and use this method to provide a reasonable basis for estimating our expected term based on insufficient historical data prior to 2014.

Restricted stock grants carry voting and dividend rights, vest ratably over a three-year period for a substantial portion of the awards granted, and may not be sold or transferred until they are vested. Stock options granted have contractual terms of 10 years and vest in three tranches over a five-year period (with the first tranche vesting on the third anniversary of the grant date, the second tranche vesting on the fourth anniversary of the grant date and the third tranche vesting on the fifth anniversary thereof), but commence vesting earlier in the event of a complete sell-down by certain of our Sponsors of their shares of our common stock. We do not pay dividends on unexercised options. We record stock-based compensation expense on our restricted stock and stock option grants as general and administrative expense over the requisite service period on a straight-line basis, net of estimates of forfeitures. If actual forfeitures differ from our estimates, additional adjustments to compensation expense will be required in future periods.

Table of Contents

Compensation expense (recorded as general and administrative expense on our income statement) related to all of our long-term incentive awards (both cash-based and equity-based) was approximately $8 million and $17 million during the quarter and six months ended June 30, 2014, respectively, and approximately $11 million and $24 million during the quarter and six months ended June 30, 2013. During the quarters ended June 30, 2014 and 2013, we paid approximately $12 million and $10 million, respectively, under our long-term incentive programs. As of June 30, 2014, we had unrecognized compensation expense of $60 million. We will recognize an additional $11 million related to outstanding awards as of June 30, 2014 during the rest of 2014, $32 million over the remaining requisite service periods subsequent to 2014 and $17 million upon a specified capital transaction when the right to such amounts become non-forfeitable.

10. Investment in Unconsolidated Affiliate

In September 2013, we sold our equity investment in Four Star Oil & Gas Company (Four Star) for net proceeds of $183 million. For the quarter and six months ended June 30, 2013, we recorded $4 million and $6 million in earnings from unconsolidated affiliate reflecting $7 million and $12 million for our share of net equity earnings directly attributable to Four Star and $3 million and $6 million of amortization of the excess of the carrying value of our investment relative to the underlying equity in the net assets of the entity. Total operating revenues, operating expenses and net income of Four Star for the quarter ended June 30, 2013 were $53 million, $34 million, and $12 million, respectively. Total operating revenues, operating expenses and net income of Four Star for the six months ended June 30, 2013 were $102 million, $67 million, and $22 million, respectively. For the quarter and six months ended June 30, 2013, we received dividends from Four Star of approximately $9 million and $17 million, respectively.

11. Related Party Transactions

Management Fee Agreement. In January 2014, we paid a quarterly management fee of $6.25 million to our private equity investors (affiliates of Apollo Global Management LLC (Apollo), Riverstone Holdings LLC, Access Industries and Korea National Oil Corporation, collectively the Sponsors). Additionally, subject to the terms and conditions of the amended and restated Management Fee Agreement, upon the closing of our initial public offering in January 2014, we paid the Sponsors an additional transaction fee equal to approximately $83 million. We recorded both of these fees in general and administrative expense. The amended and restated Management Fee Agreement, including the obligation to pay the quarterly management fee, terminated automatically in accordance with its terms upon the closing of our initial public offering.

Affiliate Supply Agreement. As of June 30, 2014, we have recorded approximately $185 million, cumulatively, in capital expenditures for amounts provided under a supply agreement with an Apollo affiliate through October 2014 to provide certain fracturing materials for 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 2013 Annual Report on Form 10-K. Actual results may differ materially from those contained in any forward-looking statements. All periods included in these interim financial statements present our Brazil operations and certain domestic natural gas assets sold as discontinued operations. 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 four areas: the Eagle Ford Shale (South Texas), the Wolfcamp Shale (Permian Basin in West Texas), the Altamont field in the Uinta Basin (Northeastern Utah) and the Haynesville Shale (North Louisiana). Further information regarding each of our programs is below:

· Eagle Ford Shale. The Eagle Ford Shale continues to provide the highest economic returns in our portfolio. We currently are running five rigs in this program.

· Wolfcamp Shale. In our Wolfcamp Shale program, we are focused on optimizing our drilling, completion and artificial lift systems. We currently are running four rigs in this program.

· Altamont. In Altamont, we are gaining operational efficiencies as we develop this oil-based field. Most of our acreage in this area is held-by-production. We are currently running three rigs in this program.

· Haynesville Shale. The Haynesville Shale generates positive cash flow and remains a core natural gas option for us when natural gas prices return to more economic levels in the future. Our acreage in the Haynesville Shale is predominately held-by-production.

We evaluate growth opportunities that are aligned with our core competencies and that are in areas that can provide a competitive advantage. Strategic acquisitions of leasehold acreage or producing assets can provide us with opportunities to achieve our long-term goals by leveraging existing expertise in each of our operating 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.

On April 30, 2014, we acquired approximately 37,000 net acres of certain producing properties and undeveloped acreage in the Southern Midland Basin adjacent to our existing Wolfcamp Shale position for an aggregate cash purchase price of $152 million. The acquisition represents an approximate 25 percent expansion of our current Wolfcamp acreage. The acquired properties are 100 percent operated with net production of approximately 1,000 Boe/d which is 75 percent liquids. We are integrating the acquired properties into our existing development program with minimal additional capital.

Additionally, on May 30, 2014, we completed the sale of certain non-core assets in the Arklatex area and in our South Louisiana Wilcox area (approximately 78,000 net acres) for $150 million of cash proceeds, with the buyer also assuming a transportation commitment of approximately $20 million. Net estimated annual production associated with the divested properties is approximately 21 MMcfe/d, approximately 85 percent of which is natural gas.

Table of Contents

We have reflected as discontinued operations in all periods presented certain non-core assets sold or in the process of being sold including (i) certain domestic natural gas assets in our Arklatex area and those in our South Louisiana Wilcox areas sold in May 2014, (ii) domestic natural gas assets sold in June 2013 (including CBM properties located in the Raton, Black Warrior and Arkoma basins; Arklatex conventional natural gas assets located in East Texas and North Louisiana, and legacy South Texas conventional natural gas assets) and (iii) our Brazilian operations which are under contract to be sold. We expect the sale of our Brazilian operations (which represents the sale of our remaining international assets) to close in 2014, subject to Brazilian regulatory approval and certain other customary closing conditions.

Factors Influencing Our Profitability. Our profitability is dependent on the prices we receive for our oil, natural gas and NGLs, the costs to explore, develop, and produce our oil, natural gas and NGLs, 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. Additionally, we may be impacted by weather events, or domestic or regulatory issues in Brazil or other third party actions outside of our control (e.g., oil spills).

To the extent possible, we attempt to mitigate certain of these risks through actions such as entering into longer term contractual arrangements to control costs and entering into derivative contracts to stabilize cash flows and reduce the financial impact of downward commodity price movements on commodity sales. In addition, because we apply mark-to-market accounting, 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 positions or to alter existing positions are made based on the goals of the overall company.

Derivative Instruments. Our realized prices from the sale of our oil, natural gas and NGLs are affected by (i) commodity price movements, including locational or basis price differences that exist between the commodity index price (e.g., WTI) and the actual price at which we sell our oil, natural gas, or NGLs, and (ii) other contractual pricing adjustments contained in the underlying sales contract. 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 unfavorable commodity price movements and locational price differences. During the six months ended June 30, 2014, we (i) settled commodity index hedges on approximately 89% of our liquids (oil and NGLs) production and 99% of our natural gas production at average floor prices of $97.97 per barrel of oil and $4.02 per MMBtu, respectively and (ii) settled basis hedges on approximately 61% of our estimated Eagle Ford oil production. To the extent our oil, natural gas, and NGLs production is unhedged, either from a commodity index price or locational price perspective, our financial results will be impacted from period to period as further described in Operating Revenues. The following table reflects the contracted volumes and the prices we will receive under derivative contracts we held as of June 30, 2014.

Table of Contents

	2014				2015				2016
	Volumes(1)	Average Price(1)			Volumes(1)	Average Price(1)			Volumes(1)	Average Price(1)
Oil
Fixed Price Swaps
WTI	6,431	$	97.06		17,373	$	89.34		5,216	$	85.25
Brent	1,840	$	102.47		2,555	$	100.01		4,026	$	95.01
LLS	—	$	—		—	$	—		6,222	$	92.22
Ceilings	766	$	100.92		1,095	$	100.00		—	$	—
Three Way Collars
Ceiling - WTI	1,472	$	103.76		—	$	—		—	$	—
Floors - WTI(2)	1,472	$	95.00		—	$	—		—	$	—
Ceiling - Brent	—	$	—		1,095	$	110.02		—	$	—
Floors - Brent(3)	—	$	—		1,095	$	100.00		—	$	—
Basis Swaps
LLS vs. WTI(4)(6)	1,472	$	5.78		—	$	—		183	$	3.00
LLS vs. Brent(5)(6)	1,840	$	(3.72	)	3,650	$	(3.77	)	1,830	$	(1.89	)
Midland vs. Cushing(7)	368	$	(1.20	)	—	$	—		—	$	—
Natural Gas
Fixed Price Swaps	38	$	4.02		62	$	4.26		7	$	4.20
NGLs
Propane Fixed Price Swaps	15	$	1.14		—	$	—		—	$	—
Propane Collars
Ceilings	8	$	1.30		—	$	—		—	$	—
Floors	8	$	1.00		—	$	—		—	$	—

(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 $75.00 in 2014, we will receive a “locked-in” cash settlement of the market price plus $20.00 per Bbl.

(3) If market prices settle at or below $85.00 in 2015, we will receive a “locked-in” cash settlement of the market price plus $15.00 per Bbl.

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

(5) EP Energy receives Brent less basis spread listed and pays LLS.

(6) We have effective LLS floor prices on future hedged production of $100.57 per Bbl for 2014, $96.24 per Bbl for 2015 and $92.33 per Bbl for 2016. These floors are derived using a combination of fixed price positions and basis positions and do not include any customary refinery or contractual deductions.

(7) EP Energy receives Cushing less basis spread listed and pays Midland.

From July 1, 2014 to August 4, 2014, we added additional LLS fixed price swaps of 0.1 MMBbls on our anticipated 2014 production with an average price of $102.00 per Bbl and LLS hedges of 1.5 MMBbls on our anticipated 2016 production with an average ceiling price of $99.29 per Bbl and an average floor price of $94.00 per Bbl. If market prices settle at or below $80.00 in 2016, we will receive a “locked-in” cash settlement of the market price plus $14.00 per Bbl on the 2016 LLS hedges. Additionally, we entered into offsetting positions on 3 TBtu of natural gas fixed price swaps at an average price of $4.06 per MMBtu related to our anticipated 2014 production in conjunction with the sale of certain natural gas assets. These derivative instruments are not included in the table above.

Summary of Liquidity and Capital Resources. As of June 30, 2014, we had available liquidity, including existing cash, of approximately $2.0 billion. We believe we have sufficient liquidity for 2014 from our cash flows from operations, combined with the availability under our RBL Facility and available cash, to fund our current obligations, projected working capital requirements and capital spending plan. In April 2014, we completed our semi-annual redetermination maintaining the borrowing base of our RBL Facility at $2.5 billion. Additionally, the earliest maturity date of our debt obligations is in 2017. See “Liquidity and Capital Resources” for more information.

Outlook for 2014. For the full year 2014, we expect the following:

· Capital expenditures of approximately $2 billion, allocated entirely to our core oil programs: $1 billion for Eagle Ford, $725 million for Wolfcamp, $250 million for Altamont, and additional acquisition capital of approximately $154 million.

· Well completions between 255 and 275.

· Average daily production volumes for the year of approximately 96 MBoe/d to 100 MBoe/d, including average daily oil production volumes of approximately 54 MBbls/d to 56 MBbls/d.

· Per unit adjusted cash operating costs for the year of approximately $12.90 to $13.90 per Boe, and transportation costs of $3.00 to $3.25 per Boe.

· Per unit depreciation, depletion and amortization rate for the year of approximately $24.35 to $25.35 per Boe.

Table of Contents

Production Volumes and Drilling Summary

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

	2014	2013

United States (MBoe/d)
Eagle Ford Shale	49	33
Wolfcamp Shale	13	3
Altamont	15	11
Haynesville Shale	17	32
Other(1)	—	9
Total (MBoe/d)	94	88

Oil (MBbls/d)(1)	51	33
Natural Gas (MMcf/d)(1)	194	291
NGLs (MBbls/d)(1)	10	7

(1) 2013 includes volumes of Four Star Oil & Gas Company (Four Star), our equity investment sold in September 2013. For the six months ended June 30, 2013, Four Star’s production volumes were 1 MBbls/d of oil, 40 MMcf/d of natural gas and 1 MBbls/d of NGLs.

· Eagle Ford Shale—Our Eagle Ford Shale equivalent volumes and oil production increased 16 MBoe/d (47%) and 11 MBbls/d (54%), respectively, for the six months ended June 30, 2014 compared to the six months ended June 30, 2013 due to the success of our drilling program in the area. During the six months ended June 30, 2014, we completed 69 additional operated wells in the Eagle Ford, and we had a total of 336 net operated wells as of June 30, 2014. With a majority of our acreage located in the core of the oil window, primarily in LaSalle and Atascosa counties, we continue to grow our oil and NGLs production in the area.

· Wolfcamp Shale—Our Wolfcamp Shale equivalent volumes increased 10 MBoe/d (281%) for the six months ended June 30, 2014 compared to the six months ended June 30, 2013 as we continue to progress the development of the program. During the six months ended June 30, 2014, we completed 43 additional operated wells, and as of June 30, 2014 we had a total of 162 net operated wells (which includes wells acquired in April 2014).

· Altamont—Our Altamont equivalent volumes increased 3 MBoe/d (30%) for the six months ended June 30, 2014 compared to the six months ended June 30, 2013. Altamont produced an average of 11 MBbls/d of oil during the six months ended June 30, 2014, and we completed 22 additional operated oil wells for a total of 335 net operated wells at June 30, 2014.

· Haynesville Shale—Our Haynesville Shale equivalent volumes decreased 14 MMcf/d (45%) for the six months ended June 30, 2014 compared to the six months ended June 30, 2013, due to natural production declines. Our Haynesville drilling program remains suspended based on current natural gas prices. As of June 30, 2014, we had 99 net operated wells in the Haynesville Shale, and our total production for the six months ended June 30, 2014 was approximately 105 MMcf/d.

Table of Contents

Results of Operations

The information in the table below provides a summary of our generally accepted accounting principles (GAAP) financial results.

	Quarters ended June 30,						Six months ended June 30,
	2014			2013			2014			2013
	(in millions)

Operating revenues
Oil	$	461		$	284		$	867		$	541
Natural gas	75			91			153			165
NGLs	30			15			57			29
Total physical sales	566			390			1,077			735
Financial derivatives	(290		)	166			(425		)	35
Total operating revenues	276			556			652			770

Operating expenses
Natural gas purchases	5			8			8			10
Transportation costs	26			22			49			42
Lease operating expense	50			36			94			71
General and administrative	42			55			175			113
Depreciation, depletion and amortization	214			137			406			253
Exploration expense	5			13			13			25
Taxes, other than income taxes	34			13			67			34
Total operating expenses	376			284			812			548

Operating (loss) income	(100		)	272			(160		)	222
Other income	—			5			—			7
Loss on extinguishment of debt	—			(2		)	(17		)	(3		)
Interest expense	(80		)	(86		)	(159		)	(178		)
(Loss) income from continuing operations before income taxes	(180		)	189			(336		)	48
Income tax benefit	(68		)	—			(124		)	—
(Loss) income from continuing operations	(112		)	189			(212		)	48
(Loss) income from discontinued operations, net of tax	(6		)	12			4			39
Net (loss) income	$	(118	)	$	201		$	(208	)	$	87

Table of Contents

Operating Revenues

The table below provides our operating revenues, volumes and prices per unit for the quarter and six months ended June 30, 2014 and 2013. 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.

	Quarters ended June 30,					Six months ended June 30,
	2014			2013		2014			2013
	(in millions)
Operating revenues:
Oil	$	461		$	284	$	867		$	541
Natural gas	75			91		153			165
NGLs	30			15		57			29
Total physical sales	566			390		1,077			735
Financial derivatives	(290		)	166		(425		)	35
Total operating revenues	$	276		$	556	$	652		$	770

Volumes:
Oil (MBbls)(1)	4,848			3,105		9,221			5,856
Natural gas (MMcf)(1)	17,429			25,529		35,128			52,779
NGLs (MBbls)(1)	1,051			716		1,894			1,269
Equivalent volumes (MBoe)(1)	8,804			8,077		16,970			15,923
Total MBoe/d	97			89		94			88

Prices per unit(2):
Oil
Average realized price on physical sales ($/Bbl)(3)	$	95.04		$	93.45	$	93.99		$	94.49
Average realized price, including financial derivatives ($/Bbl)(3)(4)	$	90.76		$	99.71	$	90.97		$	101.25
Natural gas
Average realized price on physical sales ($/Mcf)(3)	$	4.07		$	3.73	$	4.15		$	3.40
Average realized price, including financial derivatives ($/Mcf)(4)	$	3.38		$	2.68	$	3.32		$	3.07
NGLs
Average realized price on physical sales ($/Bbl)	$	27.93		$	25.80	$	29.87		$	28.30
Average realized price, including financial derivatives ($/Bbl)(4)	$	28.46		$	—	$	29.77		$	—

(1) In September 2013, we sold our equity investment in Four Star. For the quarter and six months ended June 30, 2013, Four Star’s production volumes were 68 MBbls and 136 MBbls of oil, 3,638 MMcf and 7,317 MMcf of natural gas, 117 MBbls and 229 MBbls of NGLs and 792 MBoe and 1,585 MBoe of equivalent volumes, respectively.

(2) Prices per unit are based on consolidated volumes and do not include volumes associated with Four Star which was sold in September 2013. Natural gas prices for the quarter and six months ended June 30, 2014 are calculated including a reduction of $5 million and $8 million, respectively, for natural gas purchases associated with managing our physical gas sales. Natural gas prices for the quarter and six months ended June 30, 2013 are calculated including a reduction of $8 million and $10 million, respectively, for natural gas purchases associated with managing our physical gas sales.

(3) Changes in realized oil and natural gas prices reflect the effects of unfavorable unhedged locational or basis differentials and contractual deductions between the commodity price index and the actual price at which we sold our oil and natural gas.

(4) The quarters ended June 30, 2014 and 2013, include approximately $22 million of cash paid and approximately $8 million of cash received, respectively, for the settlement of crude oil derivative contracts and approximately $12 million and $23 million of cash paid, respectively, for the settlement of natural gas financial derivatives. The six months ended June 30, 2014 and 2013, include approximately $29 million of cash paid and approximately $31 million of cash received, respectively, for the settlement of crude oil derivative contracts and approximately $29 million and $16 million of cash paid, respectively, for the settlement of natural gas financial derivatives. For the quarter and six months ended June 30, 2014, we received approximately $1 million and paid less than $1 million for the settlement of NGLs derivative contracts. Cash premiums received for the quarters ended June 30, 2014 and 2013 were approximately $1 million and less than $1 million and for the six months ended June 30, 2014 and 2013 were approximately $1 million and approximately $8 million.

Table of Contents

Physical sales. Physical sales represent accrual-based commodity sales transactions with customers. For the quarter and six months ended June 30, 2014, physical sales increased by $176 million (45%) and $342 million (47%), respectively, compared to the same periods in 2013 largely attributable to period-over-period increases in oil volumes. The table below displays the price and volume variances on our physical sales when comparing the quarters and six months ended June 30, 2014 and 2013.

	Quarter ended
	Oil			Natural gas			NGLs		Total
	(in millions)

June 30, 2013 sales	$	284		$	91		$	15	$	390
Change due to prices	8			3			3		14
Change due to volumes	169			(19		)	12		162
June 30, 2014 sales	$	461		$	75		$	30	$	566

	Six months ended
	Oil			Natural gas			NGLs		Total
	(in millions)

June 30, 2013 sales	$	541		$	165		$	29	$	735
Change due to prices	(4		)	26			3		25
Change due to volumes	330			(38		)	25		317
June 30, 2014 sales	$	867		$	153		$	57	$	1,077

Oil sales for the quarter and six months ended June 30, 2014 compared to the same periods in 2013 increased by $177 million (62%) and $326 million (60%), respectively, due primarily to oil volume growth from our Eagle Ford, Wolfcamp and Altamont drilling programs. For the quarter and six months ended June 30, 2014 compared to the same periods in 2013, Eagle Ford oil production increased by 52% (12 MBbls/d) and 54% (11 MBbls/d), respectively. Wolfcamp oil production increased by 169% (5 MBbls/d) and 239% (5 MBbls/d), respectively, and Altamont oil production volumes increased by 42% (3 MBbls/d) and 33% (3 MBbls/d), respectively.

Natural gas sales decreased for the quarter and six months ended June 30, 2014 compared to the same periods in 2013 primarily due to a decrease in volumes due to natural production declines in the Haynesville Shale partially offset by higher natural gas prices. Our Haynesville drilling program remains suspended based on current natural gas prices.

Our oil and natural gas is typically sold at index prices (NYMEX, LLS, WTI or 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 contractual deducts, differentials from the index to the delivery point and/or discounts for quality or grade. Generally as the index price of our commodities increase, deducts and differentials widen and can further widen for temporary or permanent changes in supply or demand, capacity constraints or the build out of infrastructure in developing areas.

In the Eagle Ford, our oil is sold in a largely LLS-based market. In Wolfcamp, physical barrels are generally sold at the WTI Midland Index, which trades at a spread to WTI Cushing. In Altamont, market pricing of our oil is based upon both Salt Lake City refinery postings and rail economics, which reflect transportation and handling costs associated with moving wax crude by truck and/or rail 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.

During the second quarter of 2014, weighted average differentials and deducts on our oil sales were approximately $(7.83) per barrel on an average NYMEX price during the quarter of $102.99 per barrel for oil, and $(0.66) per MMbtu on an average NYMEX price of $4.67 per MMbtu for natural gas sales. For the second quarter of 2013, average differentials and deducts on oil sales were approximately $(1.06) per barrel on an average NYMEX price of $94.22 per barrel of oil, and $(0.31) per MMbtu on an average NYMEX price of $4.09 per MMbtu for natural gas. The wider deducts and differentials were generally a result of higher index prices coupled with insufficient takeaway capacity to support regional growth and the costs associated with new builds or expansions to existing infrastructure.

NGLs sales increased for the quarter and six months ended June 30, 2014 compared to the same periods in 2013 primarily due to higher volumes as a result of our Eagle Ford and Wolfcamp drilling programs and higher NGLs prices. For the quarter and six months ended June 30, 2014 compared to the same periods in 2013, Eagle Ford NGLs volumes increased by 44% (3 MBbls/d) and 48% (2 MBbls/d), respectively, and Wolfcamp NGLs volumes increased by 372% (2 MBbls/d) and 403% (2 MBbls/d), respectively.

As of June 30, 2014, the NYMEX spot price of a barrel of oil was $105.37 versus the NYMEX spot price of natural gas of $4.46, or a ratio of 24 to 1. We have and will continue to target increases in our oil volumes due to this value difference, but we also expect volumes of natural gas to decline with less capital focus in this area. Growth in our physical revenue will largely be impacted by our ability to grow our oil volumes and by changes in oil prices.

Gains or losses on financial derivatives. We record gains or losses due to cash settlements and changes in the fair value of our derivative contracts based on forward commodity prices relative to the prices in the underlying contracts. During the quarter ended June 30, 2014, we recorded $290 million of derivative losses compared to derivative gains of $166 million during the quarter ended June 30, 2013. For the six months ended June 30, 2014, we recorded $425 million of derivative losses compared to derivative gains of $35 million for the six months ended June 30, 2013.

Table of Contents

Operating Expenses

Transportation costs. Transportation costs for the quarter and six months ended June 30, 2014 were $26 million and $49 million, respectively, compared to $22 million and $42 million for the same periods in 2013. Total transportation costs have increased in 2014 primarily due to oil transportation costs associated with Eagle Ford and Wolfcamp as a result of our production growth and new contracts in these areas.

Lease operating expense. Lease operating expense for the quarter and six months ended June 30, 2014 were $50 million and $94 million, respectively, compared to $36 million and $71 million for the same periods in 2013. Total lease operating expense has increased in 2014 due to higher chemical, maintenance, disposal, repair and power costs in Eagle Ford and higher chemical, disposal and compression costs in Wolfcamp associated with growing production volumes in the two areas.

General and administrative expenses. General and administrative expenses for the quarter ended June 30, 2014 decreased by $13 million and increased by $62 million for the six months ended June 30, 2014 compared to the same periods in 2013. Both the quarter and six months in 2014 reflect lower payroll, benefits and administrative costs; however, in the first quarter of 2014 we paid advisory fees to our Sponsors of $6.25 million and recorded a transaction fee of $83 million paid to our Sponsors in January 2014 under the amended and restated Management Fee Agreement upon completion of our initial public offering.

Depreciation, depletion and amortization expense. Our depreciation, depletion and amortization costs increased in 2014 compared to the same periods in 2013 due to an increase in production volumes and the ongoing development of higher cost oil programs (e.g., Eagle Ford and Wolfcamp). We expect our depletion rate will continue to increase as compared to our current levels as a result of this ongoing development of our higher cost liquids programs. Our average depreciation, depletion and amortization costs per unit for the quarters and six months ended June 30 were:

	Quarters ended June 30,				Six months ended June 30,
	2014		2013		2014		2013
Depreciation, depletion and amortization ($/Boe)(1)	$	24.31	$	18.75	$	23.90	$	17.64

(1) Includes $0.07 and $0.08 per Boe for the quarters ended June 30, 2014 and 2013 and $0.07 per Boe for both the six months ended June 30, 2014 and 2013 related to accretion expense on asset retirement obligations.

Exploration expense. For the quarter and six months ended June 30, 2014, we recorded $5 million and $13 million of exploration expense compared to $13 million and $25 million for the same periods in 2013. Included in exploration expense for the quarter and six months ended June 30, 2014 is $4 million and $11 million of amortization of unproved property costs compared to $13 million and $24 million for the same periods in 2013.

Taxes, other than income taxes. Taxes, other than income taxes for the quarter and six months ended June 30, 2014 were $34 million and $67 million, respectively, compared to $13 million and $34 million for the same periods in 2013. Production taxes increased in 2014 compared to the same periods in 2013 due to higher severance taxes associated with growing production volumes in our oil producing areas. Additionally, in the second quarter of 2013, we recorded a reduction in sales and use taxes of $13 million associated with settling a sales and use tax matter.

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, natural gas purchases, impairments and other expenses. Adjusted cash operating costs is a non-GAAP measure and is defined as cash operating costs less transition and restructuring costs, management, transaction and other fees paid to the Sponsors (which terminated on January 23, 2014), 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), and costs associated with our initial public offering. 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 and six months ended June 30:

Table of Contents

	Quarters ended June 30,
	2014						2013
	Total			Per Unit(1)			Total			Per Unit(1)
	(in millions, except per unit costs)
Total continuing operating expenses	$	376		$	42.68		$	284		$	38.97

Depreciation, depletion and amortization	(214		)	(24.31		)	(137		)	(18.75		)
Transportation costs	(26		)	(2.93		)	(22		)	(3.01		)
Exploration expense	(5		)	(0.53		)	(13		)	(1.80		)
Natural gas purchases	(5		)	(0.49		)	(8		)	(1.17		)
Total continuing cash operating costs	126			14.42			104			14.24
Transition/restructuring costs, non-cash portion of compensation expense and other(2)	5			0.46			(12		)	(1.53		)
Total adjusted cash operating costs and adjusted per-unit cash costs(2)	$	131		$	14.88		$	92		$	12.71

Total equivalent volumes (MBoe)(3)	8,804						7,285

	Six months ended June 30,
	2014						2013
	Total			Per Unit(1)			Total			Per Unit(1)
	(in millions, except per unit costs)
Total continuing operating expenses	$	812		$	47.83		$	548		$	38.19

Depreciation, depletion and amortization	(406		)	(23.90		)	(253		)	(17.64		)
Transportation costs	(49		)	(2.89		)	(42		)	(2.93		)
Exploration expense	(13		)	(0.75		)	(25		)	(1.76		)
Natural gas purchases	(8		)	(0.46		)	(10		)	(0.70		)
Total continuing cash operating costs	336			19.83			218			15.16
Transition/restructuring costs, non-cash portion of compensation expense and other(2)	(95		)	(5.62		)	(34		)	(2.31		)
Total adjusted cash operating costs and adjusted per-unit cash costs(2)	$	241		$	14.21		$	184		$	12.85

Total equivalent volumes (MBoe)(3)	16,970						14,338

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

(2) The non-cash portion of compensation expense represents non-cash compensation expense under our long-term incentive programs adjusted for cash payments made under our long-term incentive plans. For the quarter ended June 30, 2014 amount includes $7 million of non-cash compensation expense adjusted for cash payments made of approximately $12 million. For the six months ended June 30, 2014 amount includes $90 million of transaction, management and other fees paid to our Sponsors, $4 million of non-cash compensation expense and $1 million of restructuring costs. For the quarter ended June 30, 2013 amount includes $4 million of transition and severance costs, $7 million of management and other fees paid to our Sponsors and $11 million of non-cash compensation expense adjusted for cash payments of approximately $10 million. For the six months ended June 30, 2013 amount includes $7 million of transition and severance costs, $13 million of management and other fees paid to our Sponsors and $14 million of non-cash compensation expense.

(3) Excludes volumes associated with our equity investment in Four Star sold in September 2013.

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

	Quarters ended June 30,					Six months ended June 30,
	2014		2013			2014			2013

Average cash operating costs ($/Boe)
Lease operating expenses	$	5.69	$	5.01		$	5.56		$	4.95
Production taxes(1)	3.61		3.17			3.66			2.94
General and administrative expenses(2)	4.86		7.53			10.34			7.87
Taxes, other than production and income taxes(3)	0.26		(1.47		)	0.27			(0.60		)
Total cash operating costs	$	14.42	$	14.24		$	19.83		$	15.16
Transition/restructuring costs, non-cash portion of compensation expense and other(2)	$	0.46	$	(1.53	)	$	(5.62	)	$	(2.31	)
Total adjusted cash operating costs	$	14.88	$	12.71		$	14.21		$	12.85

Table of Contents

(1) Production taxes include ad valorem and severance taxes which increased during the quarter and six months ended June 30, 2014 primarily due to higher severance taxes associated with our higher oil production.

(2) For additional detail of transaction, management and other fees paid to Sponsors, non-cash portion of compensation expense and restructuring costs included in general and administrative expenses, refer to the reconciliation of cash operating costs and adjusted cash operating costs above.

(3) The quarter and six months ended June 30, 2013, include a reduction in sales and use taxes of $13 million associated with settling a sales and use tax matter.

Other Income Statement Items.

Loss on extinguishment of debt. For the six months ended June 30, 2014, we recorded a $17 million loss on extinguishment of debt for the portion of deferred financing costs written off in conjunction with the repayment and retirement of the PIK toggle note. For the quarter and six months ended June 30, 2013, we recorded $2 million and $3 million in losses of extinguishment of debt for the portion of deferred financing costs written off in conjunction with our $750 million term loan repricing in May 2013 and the first semi-annual redetermination of our RBL in March 2013.

Interest expense. Interest expense for the quarter and six months ended June 30, 2014 decreased compared to the same periods in 2013 due to the retirement of the PIK toggle note during January 2014 and the repayment of approximately $500 million under our term loans in August 2013.

Income taxes. For the quarter and six months ended June 30, 2014, our effective tax rates were 38% and 37%, respectively, which differs from the statutory federal tax rate of 35% as a result of the effects of state income taxes and non-deductible compensation expense, offset by the tax effects of discrete adjustments for certain transaction costs related to our initial public offering. We expect our annual effective tax rate to be approximately 39%. For the six months ended June 30, 2013, we were a partnership not subject to federal and state income taxes.

(Loss) income from discontinued operations. Our (loss) income from discontinued operations for the quarter and six months ended June 30, 2014 includes the financial results of assets classified as discontinued operations and any gain (loss) recorded on the sale of these non-core domestic natural gas and other assets.

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 income (loss) from continuing operations plus interest and debt expense, income taxes, depreciation, depletion and amortization and exploration expense. Adjusted EBITDAX is defined as EBITDAX, adjusted as applicable in the relevant period for the net change in the fair value of derivatives (mark-to-market effects of financial derivatives, net of cash settlements and premiums related to these derivatives), impairment charges, 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 and restructuring costs, transaction, management and other fees paid to our Sponsors, costs associated with our initial public offering, losses on extinguishment of debt and equity earnings from Four Star prior to its sale in 2013. 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 income (loss) from continuing operations, operating income, net cash provided by operating activities or any other measure of financial performance or liquidity presented in accordance with GAAP.

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

	Quarters ended June 30,						Six months ended June 30,
	2014			2013			2014			2013
	(in millions)
Net (loss) income	$	(118	)	$	201		$	(208	)	$	87
Loss (income) from discontinued operations, net of tax	6			(12		)	(4		)	(39		)
(Loss) income from continuing operations	(112		)	189			(212		)	48
Income tax benefit	(68		)	—			(124		)	—
Interest expense, net of capitalized interest	80			86			159			178
Depreciation, depletion and amortization	214			137			406			253
Exploration expense	5			13			13			25
EBITDAX	119			425			242			504
Mark-to-market on financial derivatives(1)	290			(166		)	425			(35		)
Cash settlements and premiums on financial derivatives(2)	(32		)	(5		)	(57		)	23
Non-cash portion of compensation expense(3)	(5		)	1			4			14
Transition and restructuring costs(4)	—			4			1			7
Fees paid to Sponsors(5)	—			7			90			13
Loss on extinguishment of debt(6)	—			2			17			3
Earnings from unconsolidated affiliate(7)	—			(4		)	—			(6		)
Adjusted EBITDAX	$	372		$	264		$	722		$	523

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

(2) Represents actual cash settlements received/(paid) related to financial derivatives, including cash premiums. For the quarters ended June 30, 2014 and 2013 we received approximately $1 million and less than $1 million, respectively, of cash premiums. For the six months ended June 30, 2014 and 2013 we received approximately $1 million and approximately $8 million, respectively, of cash premiums.

(3) For both the quarter and six months ended June 30, 2014, cash payments were approximately $12 million and for both the quarter and six months ended June 30, 2013 cash payments were approximately $10 million.

(4) Reflects transition and severance costs related to restructuring.

(5) Represents the transaction, management and other fees paid to the Sponsors.

(6) Represents the loss on extinguishment of debt recorded related to retirement of the PIK toggle note in 2014 and related to the redetermination of the RBL Facility in March 2013.

(7) Reflects the elimination of equity income recognized from Four Star, net of amortization of our purchase cost in excess of our equity interest in the underlying net assets, as a result of the sale of Four Star in September 2013.

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 capacity under the RBL Facility. Our primary uses of cash are capital expenditures, debt service requirements and working capital requirements. In January 2014, we completed our initial public offering of 35.2 million shares of Class A common stock and received net proceeds of approximately $669 million. We used the proceeds to repay our PIK toggle note and a portion of our outstanding RBL Facility balance. As of June 30, 2014, our available liquidity was approximately $2.0 billion, including approximately $1.9 billion of additional borrowing capacity available under the RBL Facility. In April 2014, we completed our semi-annual redetermination maintaining the borrowing base of our RBL Facility at $2.5 billion.

We believe we have sufficient liquidity from our cash flows from operations, combined with availability under the RBL Facility and available cash, to fund our capital program, current obligations and projected working capital requirements in 2014. 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 on the occurrence of certain events, such as a change of control, or (iii) obtain additional capital if required on acceptable terms or at all for any potential future acquisitions, joint ventures or other similar transactions, will depend on prevailing economic conditions many of which are beyond our control. We have attempted to mitigate certain of these risks. For example, we enter into oil and natural gas derivative contracts to reduce the financial impact of downward commodity price movements on a substantial portion of our anticipated production. These contracts have been effective in providing greater cash flow certainty. Additionally, we occasionally enter into transactions to supplement the prices we receive through our hedging programs that involve the receipt or payment of premiums. These transactions are usually short term in nature (less than one year) and during 2014, we received approximately $1 million in premiums on such transactions, all of which will settle during 2014. We could be required to take additional future actions if necessary to address further changes in the financial or commodity markets.

Capital Expenditures. For the full year 2014, we expect our capital budget will be approximately $2 billion, substantially all of which will be expended in our oil programs. Our capital expenditures and our average drilling rigs for the six months ended June 30, 2014 were:

	Capital Expenditures (in millions)		Average Drilling Rigs
Eagle Ford Shale	$	571	5.5
Wolfcamp Shale(1)	472		3.5
Altamont	138		3.5
Haynesville Shale	5		—
Total capital expenditures	$	1,186	12.5

(1) Includes approximately $154 million of acquisition capital.

Long-Term Debt. As of June 30, 2014, our long-term debt is approximately $4.3 billion, comprised of $3.1 billion in senior notes due in 2019, 2020 and 2022, $645 million in senior secured term loans with maturity dates in 2018 and 2019, and $550 million outstanding under the RBL Facility expiring in 2017. We continually monitor the debt capital markets and our capital structure and will make changes to our capital structure from time to time, with the goal of maintaining flexibility and cost efficiency. For additional details on our long-term debt, including restrictive covenants under our debt agreements, see Part I, Item 1, Financial Statements, Note 7.

Table of Contents

Overview of Cash Flow Activities. Our cash flows from operations (which include both continuing and discontinued activities) are summarized as follows (in millions):

	Six months ended June 30,
	2014			2013

Cash Flow from Operations
Operating activities
Net (loss) income	$	(208	)	$	87
Impairment charges	15			10
Other income adjustments	327			381
Change in other assets and liabilities	355			(28		)
Total cash flow from operations	$	489		$	450

Other Cash Inflows
Investing activities
Net proceeds from the sale of assets	$	150		$	10

Financing activities
Proceeds from long-term debt	1,300			985
Proceeds from issuance of stock	669			—
	1,969			985
Total cash inflows	$	2,119		$	995

Cash Outflows
Investing activities
Capital expenditures	$	988		$	914
Cash paid for acquisitions, net of cash acquired	154			2
	1,142			916
Financing activities
Repayment of long-term debt	1,440			305
Other	—			10
	1,440			315
Total cash outflows	$	2,582		$	1,231
Net change in cash and cash equivalents	$	26		$	214

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 2013 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 2013 Annual Report on Form 10-K, except as presented below:

Commodity Price Risk

The table below presents the change in fair value associated with our commodity-based price risk management activities due to hypothetical changes in prices, discount rates and credit rates at June 30, 2014:

				Oil, Natural Gas and NGLs Derivative Instruments
				10 Percent Increase						10 Percent Decrease
	Fair Value			Fair Value			Change			Fair Value			Change
							(in millions)
Price impact(1)	$	(263	)	$	(765	)	$	(502	)	$	228		$	491

				Oil, Natural Gas and NGLs Derivative Instruments
				1 Percent Increase						1 Percent Decrease
	Fair Value			Fair Value			Change			Fair Value			Change
							(in millions)
Discount rate(2)	$	(263	)	$	(260	)	$	3		$	(266	)	$	(3	)
Credit rate(3)	$	(263	)	$	(260	)	$	3		$	(266	)	$	(3	)

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

(2) Presents the hypothetical sensitivity of our commodity-based derivative instruments 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 derivative instruments to changes in credit risk.

Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

As of June 30, 2014, we carried out an evaluation under the supervision and with the participation of our management, including our Chief Executive Officer (CEO) and our Chief Financial Officer (CFO), as to the effectiveness, design and operation of our disclosure controls and procedures. This evaluation considered the various processes carried out under the direction of our disclosure committee in an effort to ensure that information required to be disclosed in the U.S. Securities and Exchange Commission reports we file or submit under the Securities Exchange Act of 1934, as amended (Exchange Act), is accurate, complete and timely. Our management, including our CEO and our CFO, does not expect that our disclosure controls and procedures or our internal controls will prevent and/or detect all errors and all fraud. A control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Further, the design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, within our company have been detected. Our disclosure controls and procedures are designed to provide reasonable assurance of achieving their objectives and our CEO and CFO concluded that our disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) were effective as of June 30, 2014.

Changes in Internal Control over Financial Reporting

There were no changes in EP Energy Corporation’s internal control over financial reporting during the first six months of 2014 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 2013 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.

Table of Contents

SIGNATURES

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

	EP ENERGY CORPORATION


Date: August 7, 2014	/s/ Dane E. Whitehead
	Dane E. Whitehead
	Executive Vice President and Chief Financial Officer
	(Principal Financial Officer)


Date: August 7, 2014	/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 “*”. Exhibits furnished 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

*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.

Attached files

Stock widget

Investing forum

EP Energy Corp Reports

Also read