EP Energy 10-Q 2013 Q3 Quarterly report

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q

(Mark One)

xQUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended September 30, 2013

OR

oTRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from             to               

Commission File Number 333-183815

EP Energy LLC

(Exact Name of Registrant as Specified in Its Charter)

Delaware	45-4871021
(State or Other Jurisdiction of Incorporation or Organization)	(I.R.S. Employer Identification No.)
1001 Louisiana Street Houston, Texas	77002
(Address of Principal Executive Offices)	(Zip Code)

Telephone Number: (713) 997-1200

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 o  No x

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

EP ENERGY LLC

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	30
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	44
Item 4.	Controls and Procedures	44
PART II — OTHER INFORMATION
Item 1.	Legal Proceedings	45
Item 1A.	Risk Factors	45
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	45
Item 3.	Defaults Upon Senior Securities	45
Item 4.	Mine Safety Disclosures	45
Item 5.	Other Information	45
Item 6.	Exhibits	46
Signatures		47

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
Mboe	=	thousand barrels of oil equivalent
MBbls	=	thousand barrels
Mcf	=	thousand cubic feet
MMBtu	=	million British thermal units
MMcf	=	million cubic feet
NGL	=	natural gas liquids
TBtu	=	trillion British thermal units

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 NGL is equal to six Mcf of natural gas. Also, when we refer to cubic feet measurements, all measurements are at a pressure of 14.73 pounds per square inch.

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

i

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

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

·capital and other expenditures;

·financing plans;

·capital structure;

·liquidity and cash flow;

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

·future economic and operating performance;

·operating income;

·management’s plans; and

·goals and objectives for future operations.

Forward-looking statements are subject to risks and uncertainties. While we believe the assumptions or bases underlying the forward-looking statements are reasonable and are made in good faith, we caution that assumed facts or bases almost always vary from actual results, and these 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 2012 Annual Report on Form 10-K. There have been no material changes to the risk factors described in the Form 10-K.

PART I — FINANCIAL INFORMATION

Item 1. Financial Statements

EP ENERGY LLC
CONDENSED CONSOLIDATED STATEMENTS OF INCOME

(In millions)

(Unaudited)

	Quarterly Periods						Year-to-Date Periods
	Successor						Successor						Predecessor
	Quarter ended September 30, 2013			Quarter ended September 30, 2012			Nine months ended September 30, 2013			March 23 (inception) to September 30, 2012			January 1 to May 24, 2012
Operating revenues
Oil and condensate	$	371		$	216		$	929		$	282		$	310
Natural gas	78			96			259			134			228
NGL	22			14			54			18			29
Financial derivatives	(142		)	(181		)	(107		)	(124		)	365
Total operating revenues	329			145			1,135			310			932
Operating expenses
Natural gas purchases	6			9			16			13			—
Transportation costs	24			21			70			30			45
Lease operating expense	41			28			119			38			80
General and administrative	49			75			162			281			69
Depreciation, depletion and amortization	172			81			443			106			307
Ceiling test charges	—			—			—			—			62
Impairment charges	2			—			2			1			—
Exploration expense	12			20			39			26			—
Taxes, other than income taxes	25			16			63			24			31
Total operating expenses	331			250			914			519			594
Operating (loss) income	(2		)	(105		)	221			(209		)	338
Loss from unconsolidated affiliates	(19		)	(2		)	(13		)	(3		)	(5		)
Other income	—			—			1			—			2
Loss on extinguishment of debt	(6		)	(14		)	(9		)	(14		)	—
Interest expense	(83		)	(84		)	(245		)	(137		)	(14		)
(Loss) income from continuing operations before income taxes	(110		)	(205		)	(45		)	(363		)	321
Income tax expense	—			—			—			—			134
(Loss) income from continuing operations	(110		)	(205		)	(45		)	(363		)	187
Income (loss) from discontinued operations	458			9			496			17			(9		)
Net income (loss)	$	348		$	(196	)	$	451		$	(346	)	$	178

See accompanying notes.

2

EP ENERGY LLC
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(In millions)

(Unaudited)

	Quarterly Periods					Year-to-Date Periods
	Successor					Successor					Predecessor
	Quarter ended September 30, 2013		Quarter ended September 30, 2012			Nine months ended September 30, 2013		March 23 (inception) to September 30, 2012			January 1 to May 24, 2012
Net income (loss)	$	348	$	(196	)	$	451	$	(346	)	$	178
Cash flow hedging activities:
Reclassification adjustment(1)	—		—			—		—			3
Comprehensive income (loss)	$	348	$	(196	)	$	451	$	(346	)	$	181

(1)Reclassification adjustment is stated net of tax. Taxes recognized for the predecessor period from January 1 to May 24, 2012 were $2 million.

See accompanying notes.

3

EP ENERGY LLC

CONDENSED CONSOLIDATED BALANCE SHEETS

(In millions)

(Unaudited)

	September 30, 2013		December 31, 2012
ASSETS
Current assets
Cash and cash equivalents	$	61	$	63
Accounts receivable
Customer, net of allowance of less than $1 for 2013 and 2012	219		158
Other, net of allowance of $1 for 2013 and 2012	25		14
Materials and supplies	22		16
Derivative instruments	28		108
Assets of discontinued operations	106		1,034
Prepaid assets	21		10
Total current assets	482		1,403
Property, plant and equipment, at cost
Oil and natural gas properties	7,866		6,513
Other property, plant and equipment	60		52
	7,926		6,565
Less accumulated depreciation, depletion and amortization	653		214
Property, plant and equipment, net	7,273		6,351
Other assets
Investment in unconsolidated affiliate	—		220
Derivative instruments	67		88
Assets of discontinued operations	—		93
Unamortized debt issue costs	116		134
Other	7		4
	190		539
Total assets	$	7,945	$	8,293

See accompanying notes.

4

EP ENERGY LLC

CONDENSED CONSOLIDATED BALANCE SHEETS

(In millions)

(Unaudited)

	September 30, 2013		December 31, 2012
LIABILITIES AND EQUITY
Current liabilities
Accounts payable
Trade	$	150	$	98
Other	345		302
Derivative instruments	28		17
Accrued taxes other than income	33		13
Accrued interest	106		57
Accrued taxes	—		19
Liabilities of discontinued operations	100		211
Asset retirement obligations	3		4
Other accrued liabilities	29		42
Total current liabilities	794		763
Long-term debt	3,744		4,346
Other long-term liabilities
Derivative instruments	1		14
Liabilities of discontinued operations	—		42
Asset retirement obligations	49		40
Other	4		3
Total non-current liabilities	3,798		4,445
Commitments and contingencies (Note 8)
Member’s equity	3,353		3,085
Total liabilities and equity	$	7,945	$	8,293

See accompanying notes.

5

EP ENERGY LLC
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(In millions)
(Unaudited)

	Year-to-Date Periods
	Successor						Predecessor
	Nine Months ended September 30, 2013			March 23 (Inception) to September 30, 2012			January 1 to May 24, 2012
Cash flows from operating activities
Net income (loss)	$	451		$	(346	)	$	178
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities
Depreciation, depletion and amortization	490			141			319
Gain on sale of assets	(455		)	—			—
Deferred income tax expense	—			—			199
Loss from unconsolidated affiliate, net of cash distributions	37			5			12
Ceiling test charges	—			—			62
Impairment charges	28			1			—
Loss on extinguishment of debt	9			14			—
Amortization of equity compensation expense	18			9			—
Non-cash portion of exploration expense	35			14			—
Amortization of debt issuance costs	16			8			7
Other non-cash income items	—			2			—
Asset and liability changes
Accounts receivable	(20		)	(32		)	132
Accounts payable	68			15			(56		)
Derivative instruments	99			268			(201		)
Accrued interest	49			113			(1		)
Other asset changes	(12		)	(4		)	(7		)
Other liability changes	(23		)	47			(64		)
Net cash provided by operating activities	790			255			580
Cash flows from investing activities
Capital expenditures	(1,420		)	(475		)	(636		)
Net proceeds from the sale of assets and investment	1,439			110			9
Cash paid for acquisitions, net of cash acquired	(2		)	(7,126		)	(1		)
Net cash provided by (used in) investing activities	17			(7,491		)	(628		)
Cash flows from financing activities
Proceeds from long-term debt	1,310			4,823			215
Repayment of long-term debt	(1,915		)	(609		)	(1,065		)
Member distribution	(200		)	—			—
Contributions from members	—			3,323			—
Contributions from parent	—			—			960
Debt issuance costs	(4		)	(149		)	—
Net cash (used in) provided by financing activities	(809		)	7,388			110
Change in cash and cash equivalents	(2		)	152			62
Cash and cash equivalents
Beginning of period	63			—			25
End of period	$	61		$	152		$	87

See accompanying notes

6

EP ENERGY LLC

CONDENSED CONSOLIDATED STATEMENT OF CHANGES IN EQUITY

(In millions)

(Unaudited)

	Total Member’s Equity
Balance at December 31, 2012	$	3,085
Compensation expense	17
Member distribution	(200		)
Net income	451
Balance at September 30, 2013	$	3,353

See accompanying notes.

7

EP ENERGY LLC
NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

1. Basis of Presentation and Significant Accounting Policies

Basis of Presentation

EP Energy LLC (the successor and formerly known as Everest Acquisition LLC) was formed as a Delaware limited liability company on March 23, 2012 by Apollo Global Management LLC (Apollo) and other private equity investors (collectively, the Sponsors). On April 24, 2012, we issued approximately $2.75 billion in private placement notes.  Proceeds from these notes, along with other sources, were used by the Sponsors to acquire EP Energy Global LLC (formerly known as EP Energy Corporation and EP Energy, L.L.C. after its conversion into a Delaware limited liability company) and subsidiaries for approximately $7.2 billion on May 24, 2012, from El Paso Corporation (El Paso) immediately prior to and in connection with its merger with Kinder Morgan, Inc. (KMI). We are engaged in the exploration for and the acquisition, development, and production of oil, natural gas and NGL primarily in the United States, with international activities in Brazil. EP Energy Global LLC constituted the oil and natural gas operations of El Paso prior to the Acquisition. Hereinafter, we refer to the May 24, 2012 transaction as the Acquisition and the acquired entities prior to the Acquisition are referred to as the predecessor for financial accounting and reporting purposes.

The condensed consolidated financial statements have been prepared in accordance with United States generally accepted accounting principles 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 United States generally accepted accounting principles. You should read this quarterly report along with our 2012 Annual Report on Form 10-K, which contains a summary of significant accounting policies and other disclosures. The condensed consolidated financial statements as of September 30, 2013 and for each of the successor and predecessor periods presented are unaudited. The consolidated balance sheet as of December 31, 2012 has been derived from the audited consolidated balance sheet included in our 2012 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. Our disclosures in this Form 10-Q are an update to those provided in our 2012 Annual Report on Form 10-K.

As further described in Note 2, in July and August 2013, we completed the sales of certain domestic natural gas properties 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.  In addition, in July 2013, we entered into a Quota Purchase Agreement to sell our Brazil operations.  We have classified the assets and liabilities associated with each of these dispositions as discontinued operations in our condensed consolidated balance sheets in this Form 10-Q to the extent they have not already been sold.  For our Brazil operations, we have classified the results of operations as income (loss) from discontinued operations in our condensed consolidated statements of income in all periods presented in this Form 10-Q.  As it relates to the sale of the CBM, Arklatex, and south Texas assets, we have classified the results of operations of these assets as income (loss) from discontinued operations only in successor periods subsequent to the Acquisition (May 25, 2012).  For periods prior to the Acquisition, the predecessor applied the full cost method of accounting for oil and natural gas properties where capitalized costs were aggregated by country (e.g., U.S.); accordingly, these domestic assets sold did not qualify for, and have not been reflected as, discontinued operations in the predecessor financial statement periods.  Additionally, the predecessor periods also reflect reclassifications to conform to EP Energy LLC’s financial statement presentation.

Significant Accounting Policies

Natural Gas Purchases/Sales.  We purchase and sell natural gas on a monthly basis to manage our overall natural gas production and sales.  These transactions are undertaken to optimize prices we receive for our natural gas, to physically move gas to its intended sales point, or to manage firm transportation agreements. Revenue related to these transactions is recorded in natural gas sales in operating revenues and associated purchases reflected in natural gas purchases in operating expenses on our consolidated income statement.  All historical successor periods have been adjusted to reflect these purchases and sales transactions on a gross basis.

There were no changes in significant accounting policies as described in the 2012 Annual Report on Form 10-K and no material accounting pronouncements issued but not yet adopted as of September 30, 2013.

8

2. Acquisitions and Divestitures

Acquisitions. On May 24, 2012, the Sponsors acquired all of the equity of EP Energy Global LLC for approximately $7.2 billion. The Acquisition was funded with approximately $3.3 billion in equity contributions and the issuance of approximately $4.25 billion of debt. In conjunction with the Acquisition, a portion of the proceeds was used to repay approximately $960 million of debt outstanding under the predecessor’s revolving credit facility at that time. See Note 7 for an additional discussion of debt.

The purchase transaction was accounted for under the acquisition method of accounting which requires, among other items, that assets and liabilities assumed be recognized on the balance sheet at their fair values as of the Acquisition date. Our consolidated balance sheet for all periods includes the following purchase price allocation based on available information to specific assets and liabilities assumed based on estimates of fair values and costs. There was no goodwill associated with the transaction.

Allocation of purchase price	May 24, 2012
	(In millions)
Current assets	$	587
Non-current assets	446
Property, plant and equipment	6,897
Current liabilities	(420		)
Non-current liabilities	(297		)
Total purchase price	$	7,213

The unaudited pro forma information below for the quarter and nine months ended September 30, 2012 has been derived from the historical, consolidated financial statements and has been prepared as though the Acquisition occurred on January 1, 2012. The unaudited pro forma information does not purport to represent what our results of operations would have been if the Acquisition had occurred on such date.

	Quarter ended September 30,			Nine months endedSeptember 30,
	2012			2012
	(In millions)
Operating revenues	$	145		$	1,242
Net income	(175		)	60

Discontinued Operations.  In June 2013, we entered into three separate agreements to sell our CBM properties located in the Raton, Black Warrior and Arkoma basins; our Arklatex conventional natural gas assets located in east Texas and north Louisiana and our legacy south Texas conventional natural gas assets.  In July and August 2013, we completed these sales for total consideration of approximately $1.3 billion and recorded a gain on the sale of approximately $455 million. On July 16, 2013, we entered into a Quota Purchase Agreement to sell our Brazil operations which is expected to close by the end of the first quarter of 2014.  The sale is subject to Brazilian regulatory approval, as well as certain other customary closing conditions.  During the second quarter of 2013, we recorded a $10 million impairment charge based on a comparison of the fair market value of our Brazil operations to its underlying carrying value.  We estimated the fair value of our Brazil operations (representing a Level 3 fair value measurement) based primarily on sales proceeds expected to be received less estimates of retained liabilities. We have reflected the domestic natural gas assets sold as discontinued operations in all successor periods and reflected our Brazilian operations as discontinued operations in all periods presented in these interim financial statements.

9

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

	Quarterly Periods				Year-to-Date Periods
	Successor				Successor				Predecessor
	Quarter ended September 30, 2013		Quarter ended September 30, 2012		Nine months ended September 30, 2013		March 23 (inception) to September 30, 2012		January 1 to May 24, 2012
Operating revenues	$	51	$	103	$	263	$	145	$	46
Operating expenses
Natural gas purchases	2		10		18		13		—
Transportation costs	2		9		17		13		—
Lease operating expense	18		28		72		38		16
Depreciation, depletion and amortization	1		26		47		35		12
Other expense	24		21		65		29		20
Total operating expenses	47		94		219		128		48
Other income
Gain on sale of assets	455		—		455		—		—
Other income (expense)	—		—		—		1		(5		)
Total other income	455		—		455		1		(5		)
Income (loss) from discontinued operations before income taxes	459		9		499		18		(7		)
Income tax expense	1		—		3		1		2
Income (loss) from discontinued operations	$	458	$	9	$	496	$	17	$	(9	)

	September 30, 2013		December 31, 2012
Assets of discontinued operations
Current assets	$	30	$	95
Property, plant and equipment, net	66		1,019
Other non-current assets	10		13
Total assets of discontinued operations	$	106	$	1,127
Liabilities of discontinued operations
Accounts payable	$	44	$	84
Other current liabilities	13		16
Asset retirement obligations	37		146
Other non-current liabilities	6		7
Total liabilities of discontinued operations	$	100	$	253

Other Divestitures. During the third quarter of 2013, we sold our approximate 49% equity interest in Four Star for proceeds of approximately $183 million.  In connection with entering into the sale we recorded an impairment in earnings from unconsolidated affiliates.  See Note 10 for further discussion.  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. In June 2012, we sold unevaluated property interests in Egypt for approximately $22 million and did not record a gain or loss on the sale. In addition, the predecessor received approximately $9 million from a sale of domestic oil and natural gas properties that had previously closed.

10

3. Impairment and Ceiling Test Charges

During the third quarter of 2013, we recorded a $2 million impairment to reflect a lower of cost or market adjustment on certain materials and supplies.  Prior to the Acquisition, the predecessor used the full cost method of accounting.  Under that method of accounting, the predecessor conducted quarterly ceiling tests of capitalized costs in each of its full cost pools. During the period from January 1, 2012 to May 24, 2012, the predecessor recorded a non-cash charge of approximately $62 million as a result of the decision to end all exploration activities in Egypt. The charge related to unevaluated costs in that country and included approximately $2 million related to equipment.

4. Income Taxes

Effective Tax Rate. We are a limited liability company treated as a partnership for federal and state income tax purposes. Our Brazil operations are subject to foreign income taxes; however, these have been reclassified as discontinued operations. See Note 2 for further discussion of discontinued operations.

Prior to the Acquisition, the predecessor was party to a tax accrual policy with El Paso whereby El Paso filed U.S. and certain state returns on the predecessor’s behalf.  The effective tax rate for the predecessor period from January 1, 2012 to May 24, 2012, was 42 percent, significantly higher than the statutory rate primarily due to the impact of an Egyptian non-cash charge without a corresponding tax benefit.

5. Financial Instruments

The following table presents the carrying value and fair value of our financial instruments:

	September 30, 2013				December 31, 2012
	CarryingValue		FairValue		CarryingValue		FairValue
	(In millions)
Long-term debt	$	3,744	$	4,060	$	4,346	$	4,690
Derivative instruments	$	66	$	66	$	165	$	165

As of September 30, 2013 and December 31, 2012, the carrying amounts of cash and cash equivalents, accounts receivable and accounts payable represent fair value because of the short-term nature of these instruments. We hold long-term debt obligations  with various terms (see Note 7). 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 those instruments.

Oil and natural gas derivative instruments.  We attempt to mitigate a portion of our commodity price risk and stabilize cash flows associated with forecasted sales of oil and natural gas production through the use of oil and natural gas swaps, basis swaps and option contracts.  As of September 30, 2013 and December 31, 2012, we had total derivative contracts related to 52 MMBbl and 34 MMBbl of oil and 140 TBtu and 276 TBtu of natural gas, respectively. None of these contracts are designated as accounting hedges.

Interest Rate Derivative Instruments. During July 2012, we entered into interest rate swaps with a notional amount of $600 million that are intended to reduce variable interest rate risk related to our LIBOR based loans. These interest rate derivative instruments started in November 2012 and extend through April 2017. For the quarter and nine months ended September 30, 2013, we recorded expense of $4 million and income of $3 million, respectively, in interest expense 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 September 30, 2013 and December 31, 2012, all of our 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 levels.

11

Financial Statement Presentation.  The following table presents the fair value associated with derivative financial instruments as of September 30, 2013 and December 31, 2012. All of our derivative instruments are subject to master netting arrangements which provide for the unconditional right of offset for all derivative assets and liabilities with a given counterparty in the event of default. We present assets and liabilities related to these instruments in our balance sheets as either current or non-current assets or liabilities based on their anticipated settlement date, net of the impact of master netting agreements.  On certain 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)
September 30, 2013
Derivatives	$	141	$	(46	)	$	28	$	67	$	(75	)	$	46	$	(28	)	$	(1	)
December 31, 2012
Derivatives	$	235	$	(39	)	$	108	$	88	$	(70	)	$	39	$	(17	)	$	(14	)

(1)Gross derivative assets are comprised primarily of $135 million and $231 million of oil and natural gas derivatives and $6 million and $4 million of interest rate derivatives as of September 30, 2013 and December 31, 2012, respectively.  Gross derivative liabilities are comprised primarily of $73 million and $64 million of oil and natural gas derivatives and $2 million and $6 million of interest rate derivatives as of September 30, 2013 and December 31, 2012, respectively.

The following table presents realized and unrealized net gains and losses on financial oil and gas derivative instruments presented in operating revenues and dedesignated cash flow hedges of the predecessor included in accumulated other comprehensive income (in millions):

	Quarterly Periods						Year-to-Date Periods
	Successor						Successor						Predecessor
	Quarter ended September 30, 2013			Quarter ended September 30, 2012			Nine Months ended September 30, 2013			March 23 (inception) to September 30, 2012			January 1 to May 24,  2012
Realized and unrealized (loss) gains	$	(142	)	$	(181	)	$	(107	)	$	(124	)	$	365
Accumulated other comprehensive income	—			—			—			—			5

6.  Property, Plant and Equipment

Unproved oil and natural gas properties.  As of September 30, 2013 and December 31, 2012, we had $1.5 billion and $2.3 billion of unproved oil and natural gas properties on our balance sheet. The reduction is largely attributable to transferring approximately $0.7 billion from unproved properties to proved properties.  For the quarter and nine months ended September 30, 2013, we recorded $10 million and $33 million of amortization of unproved leasehold costs in exploration expense in our income statement.  Suspended well costs were not material as of September 30, 2013.

Impairment Assessment.  Subsequent to the Acquisition, we applied the successful efforts method of accounting and evaluate capitalized costs related to proved properties at least annually or upon the occurrence of a triggering event to determine if impairment of such properties is necessary.  Forward commodity prices can play a significant role in determining impairments. Due to the significant amount of fair value allocated to our oil and natural gas properties in conjunction with the Acquisition, sustained lower oil and natural gas prices from present levels could result in an impairment of the carrying value of our proved properties in the future.

12

Asset Retirement Obligations.  We have legal asset retirement obligations associated with the retirement, replacement, or removal 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 our liability, 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 is reported on our consolidated balance sheet in other current and non-current liabilities.  Changes in the net liability from January 1 through September 30, 2013 related to our continuing operations were as follows:

	2013
	(In millions)
Net asset retirement liability at January 1	$	44
Property sales	(1		)
Accretion expense	3
Liabilities incurred	6
Changes in estimate	(1		)
Other	1
Net asset retirement liability at September 30	$	52

Capitalized Interest.  Interest expense is reflected in our financial statements net of capitalized interest. Capitalized interest for the quarter and nine months ended September 30, 2013 was $6 million and $14 million, respectively. Capitalized interest for the quarter ended September 30, 2012 and from March 23 (inception) to September 30, 2012 was $5 million and $7 million, respectively. Capitalized interest for the predecessor period from January 1 to May 24, 2012 was $4 million.

7. Long-Term Debt

Listed below are our debt obligations:

	Interest Rate	September 30, 2013
		(In millions)
$2.5 billion RBL credit facility - due May 24, 2017	Variable	$	—
$750 million senior secured term loan - due May 24, 2018 (1) (3)	Variable	494
$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		$	3,744

(1)The term loan was issued at 99 percent of par. In May 2013, we repriced our term loan which reduced the specified margin over LIBOR from 4.00% to 2.75%, and reduced the minimum LIBOR floor from 1.00% to 0.75%. As of September 30, 2013, the effective interest rate of the term loan was 3.50%.

(2)The term loan carries 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.

During the quarter and nine months ended September 30, 2013, we amortized $6 million and $16 million of deferred financing costs, respectively.  During the quarter ended September 30, 2012, and for the period from March 23 (inception) to September 30, 2012, we amortized $5 million and $8 million of deferred financing costs. During the predecessor period from January 1 to May 24, 2012, we amortized $7 million of deferred financing costs. These costs are included in interest expense.  As of September 30, 2013, we had $116 million remaining of unamortized debt issuance costs.  During the quarter and nine months ended September 30, 2013, we recorded a $6 million and $9 million in losses on the extinguishment of debt in our income statement reflecting the portion of deferred financing costs written off in conjunction with (i) the repayment of approximately $250 million under each of our $750 million and $400 million term loans (ii) our $750 million term loan re-pricing in May 2013 and (iii) the semi-annual redeterminations of our RBL Facility in March 2013.

$2.5 Billion Reserve-based Loan (RBL). In August 2013, we completed our semi-annual redetermination maintaining the borrowing base of our RBL Facility at $2.5 billion.  Under this facility, we can borrow funds or issue letters of credit (LCs). As of September 30, 2013, we had no outstanding borrowings and approximately $7 million of letters of credit issued, leaving $2.49 billion of remaining capacity available under the facility. As of  November 7, 2013, we had $270 million of outstanding borrowings under the facility.

The RBL Facility is collateralized by certain of our oil and natural gas properties and as noted has a borrowing base subject to semi-annual redetermination if there is a downward revision or a reduction of our oil and natural gas reserves due to future declines in commodity prices, performance revisions, sales of assets or otherwise, if certain other additional debt is incurred.  A reduction in our borrowing base could negatively impact our ability to borrow funds under the RBL Facility in the future.

13

Guarantees.  Our obligations under the RBL Facility, term loan, secured and unsecured notes are fully and unconditionally guaranteed, jointly and severally, by the Company’s present and future direct and indirect wholly-owned material domestic subsidiaries. Our foreign wholly-owned subsidiaries are not guarantors. As of September 30, 2013, foreign subsidiaries that do not guarantee the unsecured notes and are recorded as discontinued operations held approximately 1% of our consolidated assets and had no outstanding indebtedness, excluding intercompany obligations. For the quarter and nine months ended September 30, 2013, and for the quarter ended September 30, 2012 and the period from March 23 (inception) to September 30, 2012, these non-guarantor subsidiaries generated between 5% and 11% of our revenue including the impacts of financial derivative instruments. We have provided consolidating financial statements which include the separate results of our guarantor and non-guarantor subsidiaries in Note 12.

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 September 30, 2013, we were in compliance with all of our debt covenants. For a further discussion of our debt agreements and restrictive covenants, see our 2012 Annual Report on Form 10-K.

8. Commitments and Contingencies

Legal Proceedings and Other Contingencies

We and our subsidiaries and affiliates are named defendants in numerous legal proceedings that arise in the ordinary course of our business. There are also other regulatory rules and orders in various stages of adoption, review and/or implementation. 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 these 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. It is possible, however, that new information or future developments could require us to reassess our potential exposure related to these matters and adjust our accruals accordingly, and these adjustments could be material. As of September 30, 2013, we had approximately $1 million accrued for all outstanding legal proceedings and other contingent matters.

Southeast Louisiana Flood Protection Authority v. EP Energy Management, L.L.C. The levee authority for New Orleans and surrounds  have 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. 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 to seven wells from the mid-1960s 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.

Sales Tax Audits. As a result of sales and use tax audits during 2010, the state of Texas asserted additional taxes plus penalties and interest for the audit period 2001-2008 for two of our operating entities.  During the quarter ended June 30, 2013, we settled the last of these audits for approximately $3 million, including penalties and fees.  As a result of the settlement, we recorded a reduction in taxes, other than income taxes in our consolidated income statement of approximately $13 million.

Environmental Matters

We are subject to existing federal, state and local laws and regulations governing environmental quality, pollution control and 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 September 30, 2013, we had accrued less than $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.

14

Climate Change and other Emissions.  The EPA and several state environmental agencies have adopted regulations to regulate greenhouse gas (GHG) emissions. Although the EPA has adopted a “tailoring” rule to regulate GHG emissions, 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. In addition, any regulations over 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 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 we will incur capital expenditures of approximately $1 million in 2013 and 2014 related to the installation of storage tank emission controls at these existing facilities.

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 September 30, 2013, 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 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 environmental reserve 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) programs currently include a cash-based incentive program and certain equity-based programs originally established in conjunction with the Acquisition.  In April 2013, we granted additional cash-based LTI awards with a fair value of $21 million on the grant date that are being amortized on an accelerated basis over a three-year vesting period.  Each of these awards are further described in our 2012 Annual Report on Form 10-K.

Compensation expense (recorded as general and administrative expense on our income statement) related to all of our long-term incentive awards was approximately $8 million and $32 million during the quarter and nine months ended September 30, 2013, respectively, and approximately $8 million and $19 million for the quarter ended September 30, 2012, and from March 23 (inception) to September 30, 2012.  As of September 30, 2013, we had unrecognized compensation expense of $48 million.  We will recognize an additional $8 million related to our outstanding awards during the rest of 2013 and the remainder over the requisite service periods.

15

On September 18, 2013, EP Energy Corporation, our ultimate parent, issued an additional 70,000 shares of Class B common stock to EPE Employee Holdings II, LLC (EPE Holdings II).  EPE Holdings II was formed to hold such shares and serve as an entity through which our current and future employee incentive awards will be granted.  Holders of the awards will not hold actual Class B common stock or equity in EPE Holdings II, but rather will have a right to receive proceeds paid to EPE Holdings II in respect of such shares which is conditional upon certain events (e.g. certain liquidity events in which our Sponsors receive a return of at least one times their invested capital plus a stated return) that are not yet probable of occurring. As a result, no compensation expense was recognized upon the issuance of the Class B shares to EPE Holdings II, and none will occur until those events that give rise to a payout on such shares becomes probable of occurring.  At that time, the full value of the awards issued to EPE Holdings II will be recognized based on actual amounts paid on the Class B common stock.

10. Investment in Unconsolidated Affiliate

As discussed in Note 2, in September 2013, we sold our equity investment in Four Star Oil & Gas Company (Four Star), for net proceeds of $183 million and recorded an impairment of $20 million based on comparison of net proceeds received to the underlying carrying value of our investment. As of December 31, 2012, our investment in Four Star was $220 million (including approximately $125 million related to the excess of the carrying value of our investment in Four Star relative to the underlying equity in its net assets).  Our income statement reflects (i) our share of net earnings directly attributable to Four Star, (ii) impairments to our investment and (ii) prior to its sale, the amortization of the excess of the carrying value of our investment relative to the underlying equity in the net assets of the entity.

Below is summarized financial information of the operating results of our unconsolidated affiliate (in millions).

	Quarterly Periods				Year-to-Date Periods
	Successor				Successor				Predecessor
	Quarter ended September 30, 2013		Quarter ended September 30, 2012		Nine Months ended September 30,  2013		March 23 (inception) to September 30, 2012		January 1 to May 24, 2012
					(In millions )
Operating results:
Operating revenues	$	40	$	44	$	142	$	53	$	75
Operating expenses	27		36		94		48		58
Net income	8		5		30		3		11

In addition to recording Four Star operating results, we amortized the excess of our investment in Four Star over the underlying equity in its net assets using the unit-of-production method over the life of our estimate of Four Star’s oil and natural gas reserves. Amortization of our investment for the successor periods related to the quarters ended September 30, 2013 and 2012 was $2 million and $3 million, respectively, and for the nine months ended September 30, 2013, and the period of March 23 (inception) to September 30, 2012 was $8 million and $4 million, respectively. Amortization of our investment for the predecessor period from January 1 to May 24, 2012 was $12 million.

For the quarters ended September 30, 2013 and 2012, we received dividends from Four Star of approximately $7 million and $2 million, respectively, and for the nine months ended September 30, 2013, and  the period from March 23 (inception) to September 30, 2012 we received dividends from Four Star of approximately $24 million and $2 million, respectively.  Dividends received from Four Star for the predecessor period from January 1 to May 24, 2012 were $8 million.

11. Related Party Transactions

Member Distribution.  On July 23, 2013, we made a leveraged distribution of approximately $200 million to our member.

Management Fee Agreement. We are subject to a management fee agreement with certain of our Sponsors for the provision of certain management consulting and advisory services which terminate on the twelve-year anniversary of the Acquisition date (May 24, 2012) if not terminated earlier by mutual agreement of the parties, or upon a change in control or a specified initial public offering transaction. Under the agreement, we pay a non-refundable annual management fee of $25 million. We recorded management fees within general and administrative expense for the quarter and nine months ended September 30, 2013 of approximately $6 million and $19 million, respectively, and approximately $7 million and $9 million for the quarter ended September 30, 2012, and the period from March 23 (inception) to September 30, 2012.

16

Affiliate Supply Agreement.  In November 2012, we entered into a supply agreement with an Apollo affiliate through October 2014 to provide certain fracturing materials for our Eagle Ford drilling operations.  As of September 30, 2013, we recorded approximately $92 million as capital expenditures for materials provided under this agreement.

Related Party Transactions Prior to the Acquisition. Prior to the completion of the Acquisition, the predecessor entered into transactions during the ordinary course of conducting its business with affiliates of El Paso, primarily related to the sale, transportation and hedging of its oil, natural gas and NGL production. Additionally, El Paso billed the predecessor directly for certain general and administrative costs and allocated a portion of its general and administrative costs. The allocation was based on the estimated level of resources devoted to its operations and the relative size of its earnings before interest and taxes, gross property and payroll. These expenses were primarily related to management, legal, financial, tax, consultative, administrative and other services, including employee benefits, pension benefits, annual incentive bonuses, rent, insurance, and information technology. Prior to the Acquisition, El Paso also (i) billed the predecessor directly for compensation expense related to certain stock-based compensation awards granted directly to the predecessor’s employees, and allocated to the predecessor a proportionate share of El Paso’s corporate compensation expense (ii) filed consolidated U.S. federal and certain state tax returns which included the predecessor’s taxable income and (iii)  matched short-term cash surpluses and needs of our predecessor through a cash management program. All agreements ceased on the date of the Acquisition.  The following table shows revenues and charges to/from affiliates for the following predecessor period:

	January 1 to May 24, 2012
	(In millions)
Operating revenues	$	143
Operating expenses	44

12. Condensed Consolidating Financial Statements

As discussed in Note 7, our secured and unsecured notes are fully and unconditionally guaranteed, jointly and severally, by the Company’s present and future direct and indirect wholly-owned material domestic subsidiaries. Our foreign wholly-owned subsidiaries are not parties to the guarantees (the “Non-Guarantor Subsidiaries”). The following reflects condensed consolidating financial information of the issuer, guarantor subsidiaries, non-guarantor subsidiaries, eliminating entries (to combine the entities) and consolidated results as of and for the same periods as our condensed consolidated financial statements presented herein.

17

EP ENERGY LLC

CONDENSED CONSOLIDATING STATEMENT OF INCOME

FOR QUARTER ENDED SEPTEMBER 30, 2013

(In millions)

	Successor
	Issuer			Guarantor Subsidiaries			Non- Guarantor Subsidiaries		Eliminations			Consolidated
Operating revenues
Oil and condensate	$	—		$	371		$	—	$	—		$	371
Natural gas	—			78			—		—			78
NGL	—			22			—		—			22
Financial derivatives	(142		)	—			—		—			(142		)
Total operating revenues	(142		)	471			—		—			329
Operating expenses
Natural gas purchases	—			6			—		—			6
Transportation costs	—			24			—		—			24
Lease operating expense	—			41			—		—			41
General and administrative	11			38			—		—			49
Depreciation, depletion and amortization	—			172			—		—			172
Impairment charges	—			2			—		—			2
Exploration expense	—			12			—		—			12
Taxes, other than income taxes	—			25			—		—			25
Total operating expenses	11			320			—		—			331
Operating (loss) income	(153		)	151			—		—			(2		)
Loss from unconsolidated affiliate	—			(19		)	—		—			(19		)
Earnings from consolidated subsidiaries	134			—			—		(134		)	—
Loss on extinguishment of debt	(6		)	—			—		—			(6		)
Interest expense	(85		)	2			—		—			(83		)
(Loss) income before income taxes	(110		)	134			—		(134		)	(110		)
Income tax expense	—			—			—		—			—
(Loss) income from continuing operations	(110		)	134			—		(134		)	(110		)
Income from discontinued operations	458			458			—		(458		)	458
Net income	$	348		$	592		$	—	$	(592	)	$	348

18

EP ENERGY LLC

CONDENSED CONSOLIDATING STATEMENT OF INCOME

FOR QUARTER ENDED SEPTEMBER 30, 2012

(In millions)

	Successor
	Issuer			Guarantor Subsidiaries			Non- Guarantor Subsidiaries		Eliminations			Consolidated
Operating revenues
Oil and condensate	$	—		$	216		$	—	$	—		$	216
Natural gas	—			96			—		—			96
NGL	—			14			—		—			14
Financial derivatives	(115		)	(66		)	—		—			(181		)
Total operating revenues	(115		)	260			—		—			145
Operating expenses
Natural gas purchases	—			9			—		—			9
Transportation costs	—			21			—		—			21
Lease operating expense	—			28			—		—			28
General and administrative	8			67			—		—			75
Depreciation, depletion and amortization	—			81			—		—			81
Exploration expense	—			20			—		—			20
Taxes, other than income taxes	—			16			—		—			16
Total operating expenses	8			242			—		—			250
Operating (loss) income	(123		)	18			—		—			(105		)
Loss from unconsolidated affiliates	—			(2		)	—		—			(2		)
Earnings from consolidated affiliates	14			—			—		(14		)	—
Loss on extinguishment of debt	(14		)	—			—		—			(14		)
Interest expense	(82		)	(2		)	—		—			(84		)
(Loss) income before income taxes	(205		)	14			—		(14		)	(205		)
Income tax expense	—			—			—		—			—
(Loss) income from continuing operations	(205		)	14			—		(14		)	(205		)
Income from discontinued operations	9			9			3		(12		)	9
Net (loss) income	$	(196	)	$	23		$	3	$	(26	)	$	(196	)

19

EP ENERGY LLC

CONDENSED CONSOLIDATING STATEMENT OF INCOME

FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2013

(In millions)

	Successor
	Issuer			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Eliminations			Consolidated
Operating revenues
Oil and condensate	$	—		$	929		$	—		$	—		$	929
Natural gas	—			259			—			—			259
NGL	—			54			—			—			54
Financial derivatives	(106		)	(1		)	—			—			(107		)
Total operating revenues	(106		)	1,241			—			—			1,135
Operating expenses
Natural gas purchases	—			16			—			—			16
Transportation costs	—			70			—			—			70
Lease operating expense	—			119			—			—			119
General and administrative	37			125			—			—			162
Depreciation, depletion and amortization	—			443			—			—			443
Impairment charges	—			2			—			—			2
Exploration expense	—			39			—			—			39
Taxes, other than income taxes	—			63			—			—			63
Total operating expenses	37			877			—			—			914
Operating (loss) income	(143		)	364			—			—			221
Loss from unconsolidated affiliates	—			(13		)	—			—			(13		)
Earnings from consolidated subsidiaries	352			—			—			(352		)	—
Other income	—			1			—			—			1
Loss on extinguishment of debt	(9		)	—			—			—			(9		)
Interest expense	(245		)	—			—			—			(245		)
(Loss) income before income taxes	(45		)	352			—			(352		)	(45		)
Income tax expense	—			—			—			—			—
(Loss) income from continuing operations	(45		)	352			—			(352		)	(45		)
Income (loss) from discontinued operations	496			496			(6		)	(490		)	496
Net income (loss)	$	451		$	848		$	(6	)	$	(842	)	$	451

20

EP ENERGY LLC

CONDENSED CONSOLIDATING STATEMENT OF INCOME

FOR THE PERIOD FROM MARCH 23, 2012 (INCEPTION) TO SEPTEMBER 30, 2012

(In millions)

	Successor
	Issuer			Guarantor Subsidiaries			Non- Guarantor Subsidiaries		Eliminations			Consolidated
Operating revenues
Oil and condensate	$	—		$	282		$	—	$	—		$	282
Natural gas	—			134			—		—			134
NGL	—			18			—		—			18
Financial derivatives	(87		)	(37		)	—		—			(124		)
Total operating revenues	(87		)	397			—		—			310
Operating expenses
Natural gas purchases	—			13			—		—			13
Transportation costs	—			30			—		—			30
Lease operating expense	—			38			—		—			38
General and administrative	191			90			—		—			281
Depreciation, depletion and amortization	—			106			—		—			106
Impairment charges	—			1			—		—			1
Exploration expense	—			26			—		—			26
Taxes, other than income taxes	—			24			—		—			24
Total operating expenses	191			328			—		—			519
Operating (loss) income	(278		)	69			—		—			(209		)
Loss from unconsolidated affiliates	—			(3		)	—		—			(3		)
Earnings from consolidated affiliates	66			—			—		(66		)	—
Loss on debt extinguishment	(14		)	—			—		—			(14		)
Interest expense	(137		)	—			—		—			(137		)
(Loss) income before income taxes	(363		)	66			—		(66		)	(363		)
Income tax expense	—			—			—		—			—
(Loss) income from continuing operations	(363		)	66			—		(66		)	(363		)
Income from discontinued operations	17			17			10		(27		)	17
Net (loss) income	$	(346	)	$	83		$	10	$	(93	)	$	(346	)

21

EP ENERGY LLC

CONDENSED CONSOLIDATING STATEMENT OF INCOME

FOR THE PERIOD FROM JANUARY 1, 2012 TO MAY 24, 2012

(In millions)

	Predecessor
	Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Eliminations		Consolidated
Operating revenues
Oil and condensate	$	310		$	—		$	—	$	310
Natural gas	228			—			—		228
NGL	29			—			—		29
Financial derivatives	365			—			—		365
Total operating revenues	932			—			—		932
Operating expenses
Transportation costs	45			—			—		45
Lease operating expense	80			—			—		80
General and administrative	68			1			—		69
Depreciation, depletion and amortization	307			—			—		307
Ceiling test charges	—			62			—		62
Taxes, other than income taxes	31			—			—		31
Total operating expenses	531			63			—		594
Operating income (loss)	401			(63		)	—		338
Loss from unconsolidated affiliates	(5		)	—			—		(5		)
Loss from consolidated subsidiaries	(63		)	—			63		—
Other income	2			—			—		2
Interest expense	(14		)	—			—		(14		)
Income (loss) before income taxes	321			(63		)	63		321
Income tax expense	134			—			—		134
Income (loss) from continuing operations	187			(63		)	63		187
Loss from discontinued operations	(9		)	(8		)	8		(9		)
Net income (loss)	$	178		$	(71	)	$	71	$	178
Cash flow hedging activities:
Reclassification adjustment (1)	3			—			—		3
Comprehensive income (loss)	$	181		$	(71	)	$	71	$	181

(1)       Reclassification adjustment is stated net of tax. Taxes recognized for the predecessor period are $2 million.

22

EP ENERGY LLC

CONDENSED CONSOLIDATING BALANCE SHEET

AS OF SEPTEMBER 30, 2013

(In millions)

	Issuer		GuarantorSubsidiaries		Non- GuarantorSubsidiaries		Eliminations			Consolidated
ASSETS
Current assets
Cash and cash equivalents	$	43	$	—	$	18	$	—		$	61
Accounts receivable
Customer, net of allowance of less than $1	—		219		—		—			219
Other, net of allowance of $1	—		25		—		—			25
Materials and supplies	—		22		—		—			22
Derivative instruments	28		—		—		—			28
Assets of discontinued operations	—		28		105		(27		)	106
Prepaid assets	6		15		—		—			21
Total current assets	77		309		123		(27		)	482
Property, plant and equipment, at cost
Oil and natural gas properties	—		7,866		—		—			7,866
Other property, plant and equipment	—		60		—		—			60
	—		7,926		—		—			7,926
Less accumulated depreciation, depletion and amortization	—		653		—		—			653
Property, plant and equipment, net	—		7,273		—		—			7,273
Other assets
Investments in consolidated affiliates	8,002		—		—		(8,002		)	—
Derivative instruments	67		—		—		—			67
Notes receivable from consolidated affiliate	—		1,019		—		(1,019		)	—
Unamortized debt issue costs	116		—		—		—			116
Other	—		7		—		—			7
	8,185		1,026		—		(9,021		)	190
Total assets	$	8,262	$	8,608	$	123	$	(9,048	)	$	7,945

23

EP ENERGY LLC

CONDENSED CONSOLIDATING BALANCE SHEET

AS OF SEPTEMBER 30, 2013

(In millions)

	Issuer		GuarantorSubsidiaries		Non- GuarantorSubsidiaries		Eliminations			Consolidated
LIABILITIES AND EQUITY
Current liabilities
Accounts payable
Trade	$	10	$	140	$	—	$	—		$	150
Other	—		345		—		—			345
Derivative instruments	28		—		—		—			28
Accrued taxes other than income	—		33		—		—			33
Accrued interest	106		—		—		—			106
Asset retirement obligations	—		3		—		—			3
Liabilities of discontinued operations	—		4		96		—			100
Other accrued liabilities	1		28		—		—			29
Total current liabilities	145		553		96		—			794
Long-term debt	3,744		—		—		—			3,744
Notes payable to consolidated affiliate	1,019		—		—		(1,019		)	—
Other long-term liabilities
Derivative instruments	1		—		—		—			1
Asset retirement obligations	—		49		—		—			49
Other	—		4		—		—			4
Total non-current liabilities	4,764		53		—		(1,019		)	3,798
Commitments and contingencies
Member’s equity	3,353		8,002		27		(8,029		)	3,353
Total liabilities and equity	$	8,262	$	8,608	$	123	$	(9,048	)	$	7,945

24

EP ENERGY LLC

CONDENSED CONSOLIDATING BALANCE SHEET

AS OF DECEMBER 31, 2012

(In millions)

	Issuer		GuarantorSubsidiaries		Non- GuarantorSubsidiaries		Eliminations			Consolidated
ASSETS
Current assets
Cash and cash equivalents	$	—	$	49	$	14	$	—		$	63
Accounts receivable
Customer, net of allowance of less than $1	6		152		—		—			158
Other, net of allowance of $1	—		14		—		—			14
Materials and supplies	—		16		—		—			16
Derivative instruments	108		—		—		—			108
Assets of discontinued operations	—		998		39		(3		)	1,034
Prepaid assets	—		10		—		—			10
Total current assets	114		1,239		53		(3		)	1,403
Property, plant and equipment, at cost
Oil and natural gas properties	—		6,513		—		—			6,513
Other property, plant and equipment	—		52		—		—			52
	—		6,565		—		—			6,565
Less accumulated depreciation, depletion and amortization	—		214		—		—			214
Property, plant and equipment, net	—		6,351		—		—			6,351
Other assets
Investment in unconsolidated affiliate	—		220		—		—			220
Investments in consolidated affiliates	7,124		—		—		(7,124		)	—
Derivative instruments	88		—		—		—			88
Assets of discontinued operations	—		46		93		(46		)	93
Notes receivable from consolidated affiliate	45		—		—		(45		)	—
Unamortized debt issue costs	134		—		—		—			134
Other	—		4		—		—			4
	7,391		270		93		(7,215		)	539
Total assets	$	7,505	$	7,860	$	146	$	(7,218	)	$	8,293

25

EP ENERGY LLC

CONDENSED CONSOLIDATING BALANCE SHEET

AS OF DECEMBER 31, 2012

(In millions)

	Issuer		GuarantorSubsidiaries		Non- GuarantorSubsidiaries		Eliminations			Consolidated
LIABILITIES AND EQUITY
Current liabilities
Accounts payable
Trade	$	—	$	98	$	—	$	—		$	98
Other accrued liabilities	—		302		—		—			302
Derivative instruments	10		7		—		—			17
Accrued taxes other than income	—		13		—		—			13
Accrued interest	57		—		—		—			57
Accrued taxes	—		19		—		—			19
Asset retirement obligations	—		4		—		—			4
Liabilities of discontinued operations	—		156		58		(3		)	211
Other accrued liabilities	—		42		—		—			42
Total current liabilities	67		641		58		(3		)	763
Long-term debt	4,346		—		—		—			4,346
Notes payable to consolidated affiliate	—		45		—		(45		)	—
Other long-term liabilities
Derivative instruments	7		7		—		—			14
Liabilities of discontinued operations	—		—		42		—			42
Asset retirement obligations	—		40		—		—			40
Other	—		3		—		—			3
Total non-current liabilities	4,353		95		42		(45		)	4,445
Commitments and contingencies
Member’s equity	3,085		7,124		46		(7,170		)	3,085
Total liabilities and equity	$	7,505	$	7,860	$	146	$	(7,218	)	$	8,293

26

EP ENERGY LLC

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS

FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2013

(In millions)

	Successor
	Issuer			GuarantorSubsidiaries			Non- GuarantorSubsidiaries			Eliminations			Consolidated
Cash flows from operating activities
Net income (loss)	$	451		$	848		$	(6	)	$	(842	)	$	451
Adjustments to reconcile net (loss) income to net cash (used in) provided by operating activities
Depreciation, depletion and amortization	—			483			7			—			490
Gain on sale of assets	—			(455		)	—			—			(455		)
Loss from unconsolidated affiliate, net of cash distributions	—			37			—			—			37
Earnings from consolidated affiliates	(848		)	6			—			842			—
Impairment charges	—			10			18			—			28
Loss on extinguishment of debt	9			—			—			—			9
Amortization of equity compensation expense	18			—			—			—			18
Non-cash portion of exploration expense	—			35			—			—			35
Amortization of debt issuance costs	16			—			—			—			16
Equity distributions from consolidated affiliate	—			15			—			(15		)	—
Asset and liability changes
Accounts receivable	5			(27		)	5			(3		)	(20		)
Accounts payable	10			59			(4		)	3			68
Derivative instruments	98			1			—			—			99
Accrued interest	49			—			—			—			49
Other asset changes	(6		)	(7		)	1			—			(12		)
Other liability changes	—			(21		)	(2		)				(23		)
Net cash (used in) provided by operating activities	(198		)	984			19			(15		)	790
Cash flows from investing activities
Capital expenditures	(14		)	(1,406		)	—			—			(1,420		)
Net proceeds from the sale of asset and investment	—			1,439			—			—			1,439
Cash paid for acquisitions, net of cash acquired	—			(2		)	—			—			(2		)
Change in note receivable with affiliate	45			(1,019		)	—			974			—
Net cash provided by (used in) investing activities	31			(988		)	—			974			17
Cash flows from financing activities
Proceeds from long-term debt	1,310			—			—			—			1,310
Repayment of long-term debt	(1,915		)	—			—			—			(1,915		)
Dividends paid	(200		)	—			—			—			(200		)
Dividends to affiliate							(15		)	15			—
Change in note payable with affiliate	1,019			(45		)	—			(974		)	—
Debt issuance costs	(4		)	—			—			—			(4		)
Net cash (used in) provided by financing activities	210			(45		)	(15		)	(959		)	(809		)
Change in cash and cash equivalents	43			(49		)	4			—			(2		)
Cash and cash equivalents
Beginning of period	—			49			14			—			63
End of period	$	43		$	—		18			$			$	61

27

EP ENERGY LLC

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS

FOR THE PERIOD FROM MARCH 23, 2012 (INCEPTION) TO SEPTEMBER 30, 2012

(In millions)

	Successor
	Issuer			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Eliminations			Consolidated
Cash flows from operating activities
Net (loss) income	$	(346	)	$	83		$	10		$	(93	)	$	(346	)
Adjustments to reconcile net (loss) income to net cash from operating activities
Depreciation, depletion and amortization	—			138			3			—			141
Loss from unconsolidated affiliates, adjusted for cash distributions	—			5			—			—			5
Earnings from consolidated affiliates	(83		)	(10		)	—			93			—
Impairment charges	—			1			—			—			1
Loss on extinguishment of debt	14			—			—			—			14
Amortization of equity compensation expense	9			—			—			—			9
Non-cash portion of exploration expense	—			14			—			—			14
Amortization of debt issuance costs	8			—			—			—			8
Other non-cash income items	—			—			2			—			2
Asset and liability changes
Accounts receivable	(2		)	(28		)	(2		)	—			(32		)
Accounts payable	1			5			9			—			15
Derivatives	124			144			—			—			268
Accrued Interest	113			—			—			—			113
Other asset changes	(6		)	4			(2		)	—			(4		)
Other liability changes	—			46			1			—			47
Net cash (used in) provided by operating activities	(168		)	402			21			—			255
Cash flows from investing activities
Capital expenditures	(6		)	(467		)	(2		)	—			(475		)
Net proceeds from the sale of assets	—			110			—			—			110
Cash paid for acquisitions, net of cash acquired	(7,213		)	—			—			87			(7,126		)
Net cash (used in) provided by investing activities	(7,219		)	(357		)	(2		)	87			(7,491		)
Cash flows from financing activities
Proceeds from long term debt	4,823			—			—			—			4,823
Repayment of long term debt	(608		)	(1		)	—			—			(609		)
Contributed member equity	3,323			—			—			—			3,323
Debt issuance costs	(149		)	—			—			—			(149		)
Net cash (used in) provided by financing activities	7,389			(1		)	—			—			7,388
Change in cash and cash equivalents	2			44			19			87			152
Cash and cash equivalents
Beginning of period	—			75			12			(87		)	—
End of period	$	2		$	119		$	31		$	—		$	152

28

EP ENERGY LLC

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS

FOR THE PERIOD FROM JANUARY 1, 2012 TO MAY 24, 2012

(In millions)

	Predecessor
	Guarantor Subsidiaries			Non- GuarantorSubsidiaries			Eliminations			Consolidated
Cash flows from operating activities
Net income (loss)	$	178		$	(71	)	$	71		$	178
Adjustments to reconcile net income (loss) to net cash provided by operating activities
Depreciation, depletion and amortization	307			12			—			319
Deferred income tax expense	199			—			—			199
Loss from unconsolidated affiliates, net of cash distributions	12			—			—			12
Earnings from consolidated affiliates	71			—			(71		)	—
Ceiling test charges	—			62			—			62
Amortization of debt issuance costs	7			—			—			7
Asset and liability changes
Accounts receivable	132			2			(2		)	132
Accounts payable	(54		)	(4		)	2			(56		)
Derivatives	(201		)	—			—			(201		)
Accrued interest	(1		)	—			—			(1		)
Other asset changes	(7		)	—			—			(7		)
Other liability changes	(63		)	(1		)	—			(64		)
Net cash provided by operating activities	580			—			—			580
Cash flows from investing activities
Capital expenditures	(628		)	(8		)	—			(636		)
Net proceeds from the sale of assets	9			—			—			9
Change in note receivable with affiliates	(1		)	—			1			—
Cash paid for acquisitions, net of cash acquired	(1		)	—			—			(1		)
Net cash (used in) provided by investing activities	(621		)	(8		)	1			(628		)
Cash flows from financing activities
Proceeds from long-term debt	215			—			—			215
Repayment of long-term debt	(1,065		)	—			—			(1,065		)
Contribution from parent	960			—			—			960
Change in note payable with affiliate	—			1			(1		)	—
Net cash (used in) provided by financing activities	110			1			(1		)	110
Change in cash and cash equivalents	69			(7		)	—			62
Cash and cash equivalents
Beginning of period	6			19			—			25
End of period	$	75		$	12		$	—		$	87

29

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 2012 Annual Report on Form 10-K. Actual results may differ materially from those contained in any forward-looking statements. Additionally, the financial results for the successor periods include the application of the acquisition method of accounting and the application of the successful efforts method of accounting for oil and natural gas properties.  All periods included in these interim financial statements present our Brazil operations as discontinued operations.  The successor periods also present certain domestic natural gas assets sold, including the CBM, south Texas and Arklatex assets, as discontinued operations. Predecessor periods do not present the domestic assets as discontinued operations due to the application of the full cost method of accounting prior to the Acquisition.  As a result of these differences in presentation, trends and results in future periods may be different than those that existed prior to the Acquisition. Unless otherwise indicated or the context otherwise requires, references in this MD&A section to “we”, “our”, “us” and “the Company” refer to both EP Energy LLC and EP Energy Global LLC (the predecessor for accounting purposes), 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 oil and natural gas properties in the United States.  We are focused on creating shareholder value through the development of our low-risk, repeatable drilling inventory located in our four core 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).

During the third quarter of 2013, we sold certain of our natural gas properties, including CBM properties located in the Raton, Black Warrior, and Arkoma basins, the majority of our Arklatex conventional natural gas properties and our properties in south Texas. The total consideration from these transactions was approximately $1.3 billion. In July 2013, we entered into a Quota Purchase Agreement to sell all of our Brazil operations.  This transaction represents the sale of all our remaining international assets and is expected to close by the end of the first quarter of 2014, subject to Brazilian regulatory approval and certain other customary closing conditions.  In addition, in September 2013, we sold our interests in Four Star for approximately $183 million. Each of these transactions is discussed further in Results of Operations below and in Item 1. Financial Statements, Note 2 and/or Note 10.

We operate primarily through four core areas: Eagle Ford Shale, Wolfcamp Shale, Altamont  and Haynesville Shale. Below is a description of each of our core plays:

·Eagle Ford Shale. The Eagle Ford Shale is an oil-based program which provides the highest economic returns in our portfolio.

·Wolfcamp Shale. In our Wolfcamp Shale program, we are focused on optimizing our drilling, completion and artificial lift systems in this oil-based 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.

·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 acquisition and 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 our core operating areas, by balancing our exposure to regions, basins and commodities, by helping us to achieve risk-adjusted returns competitive with those available within our existing drilling programs and by increasing our reserves.

30

Factors Influencing Our Profitability.  Our profitability is dependent on the prices we receive for our oil and natural gas, the costs to explore, develop, and produce our oil and natural gas, and the volumes we are able to produce, among other factors. Our long-term profitability will be influenced primarily by:

·growing our proved reserve base and production volumes through the successful execution of our drilling programs or through acquisitions;

·finding and producing oil and natural gas at reasonable costs;

·managing cash costs; and

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

In addition to these factors, our future profitability and performance will be affected by our ability to execute our strategy, 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 international regulatory issues 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, financial position and cash flows 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.  During the nine months ended September 30, 2013, approximately 94 percent of our liquids production and 90 percent of our natural gas production were hedged and settled at average floor prices of $99.98 per barrel and $3.53 per MMBtu, respectively. The following table reflects the contracted volumes and prices we will receive under derivative contracts we held as of September 30, 2013.

	2013			2014			2015			2016
	Volumes(1)	Average Price(1)		Volumes(1)	Average Price(1)		Volumes(1)	Average Price(1)		Volumes(1)	Average Price(1)
Oil
Fixed Price Swaps	4,373	$	100.08	15,987	$	98.10	21,014	$	90.08	4,484	$	85.46
Ceilings	644	$	97.86	1,126	$	100.00	1,095	$	100.00	—	$	—
Three Way Collars Ceiling	—	$	—	2,920	$	103.76	—	$	—	—	$	—
Three Way Collars Floors(2)(3)	—	$	—	2,920	$	95.00	—	$	—	—	$	—
Basis Swaps(4)	1,012	$	Various	5,840	$	Various	3,650	$	Various	1,830	$	Various
Natural Gas
Fixed Price Swaps	20	$	3.25	63	$	4.02	44	$	4.28	—	$	—
Ceilings	—	$	—	13	$	4.02	—	$	—	—	$	—

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

(2)On 1,564 MBbls, if market prices settle at or below $71.47 in 2013, we will receive a “locked-in” cash settlement of the market price plus $24.27 per Bbl.

(3)If market prices settle at or below $75.00, we will receive a “locked-in” cash settlement of the market price plus $20.00 per Bbl.

(4)We use various types of oil basis swaps to lock-in certain crude oil differentials.

Summary of Liquidity and Capital Resources.  As of September 30, 2013, we had available liquidity, including existing cash, of approximately $2.55 billion. We believe we have sufficient liquidity for the remainder of 2013 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.  Additionally, the earliest maturity date of our debt obligations is in 2017. See “Liquidity and Capital Resources” for more information.

31

Capital Expenditures.  Our capital expenditures for the nine months ended September 30, 2013 and rig count as of September 30, 2013 were:

	Capital Expenditures (In millions)		Rig Count
Eagle Ford	$	865	6
Wolfcamp	377		3
Altamont	145		2
Haynesville	2		—
Other	14		—
Total capital expenditures(1)	$	1,403	11

(1)Excludes capital expenditures of $10 million from our domestic assets, sold in the third quarter of 2013.

Production Volumes and Drilling Summary

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

	2013	2012
United States (MBoe/d)
Eagle Ford	36	18
Wolfcamp	5	2
Altamont	11	10
Haynesville	29	51
Other domestic	5	8
Divested assets(1)	—	26
Total Consolidated	86	115
Unconsolidated affiliate (MBoe/d)(2)	8	9
Total Combined (MBoe/d)	94	124
Oil and condensate (MBbls/d)
Consolidated volumes	35	22
Divested assets(1)	—	1
Unconsolidated affiliate volumes(2)	1	1
Total Combined	36	24
Natural Gas (MMcf/d)
Consolidated volumes	264	384
Divested assets(1)	—	144
Unconsolidated affiliate volumes(2)	37	43
Total Combined	301	571
NGL (MBbls/d)
Consolidated volumes	7	3
Divested assets(1)	—	1
Unconsolidated affiliate volumes(2)	1	1
Total Combined (MBbls/d)	8	5

(1)Predecessor periods prior to May 24, 2012 include volumes from our CBM, south Texas, and the majority of ourArklatex assets, which were sold in 2013, and our Gulf of Mexico assets, which were sold in 2012. For periods after May 24, 2012, our CBM, south Texas and Arklatex assets are treated as discontinued operations and accordingly volumes were excluded from all financial and non-financial metrics.  In addition our Brazilian operations are treated as discontinued operations in all periods,  and accordingly, volumes are excluded from all financial and non-financial metrics for both predecessor and successor periods.

(2)In September 2013, we sold our equity investment in Four Star.

32

·Eagle Ford Shale—Our Eagle Ford Shale equivalent volumes increased 18 MBoe/d (100 percent) for the nine months ended September 30, 2013 compared to the same period in 2012 due to the success of our drilling program in the area. Eagle Ford oil production increased by 11 MBbls/d or 89 percent compared with the nine months ended September 30, 2012.  Combined Eagle Ford oil and NGL production increased in the third quarter of 2013 to approximately 33 MBbls/d compared with approximately 28 MBbls/d during the second quarter of 2013. During the nine months ended September 30, 2013, we drilled 100 additional operated wells in our Eagle Ford play, and we had a total of 235 net operated wells as of September 30, 2013. 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 NGL production in the area.

·Wolfcamp Shale—Our Wolfcamp Shale equivalent volumes increased 3 MBoe/d (150 percent) for the nine months ended September 30, 2013 compared to the same period in 2012 as we continue to progress the development of the program.   During the first nine months of 2013, we drilled 48 additional operated wells, for a total of 79 net operated wells as of September 30, 2013.

·Altamont—Our Altamont equivalent volumes increased 1 MBoe/d (10 percent) for the nine months ended September 30, 2013 compared to the nine months ended September 30, 2012. Altamont produced an average of 8 MBbls/d of oil during the nine months ended September 30, 2013, and we drilled an additional 20 operated oil wells for a total of 319 net operated wells at September 30, 2013.

·Haynesville Shale—Our Haynesville Shale equivalent volumes decreased 132 MMcf/d (43 percent) for the nine months ended September 30, 2013 compared to the nine months ended September 30, 2012, due to natural declines as we suspended our drilling program at the end of the first quarter of 2012 due to low natural gas prices.  As of September 30, 2013, we had 99 net operated wells in the Haynesville Shale, and our total production for the nine months ended September 30, 2013 was approximately 175 MMcf/d.

·Divested assets—Our divested assets were reclassified as discontinued operations for the nine-month period ended September 30, 2013 and thus volumes related to the assets are not reflected in the successor periods of the table above.  Equivalent volumes of divested assets in predecessor periods of 2012 relate to volumes for our divested CBM, south Texas, Arklatex and Gulf of Mexico assets.

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Results of Operations

Our financial results in the tables below reflect the financial results for the quarter and nine months ended September 30, 2013 and of each of the separate successor and predecessor periods in 2012.  Beginning with the Acquisition in May 2012, our successor period financial results reflect the application of the acquisition method of accounting, the application of the successful efforts method of accounting for oil and natural gas properties, and the presentation of certain domestic natural gas assets divested in 2013 and the pending sale of our Brazilian operations as discontinued operations. For periods prior to the Acquisition, we have not reflected these divested domestic natural gas assets as discontinued since they did not qualify as such for accounting purposes under the full cost accounting method applied by the predecessor during those periods. We have reflected our Brazilian operations as discontinued operations in all periods.  As a result, trends and results in future periods are different than those that existed prior to the Acquisition. Our financial results for each quarter and nine month periods in 2013 and 2012 are presented below.

	Quarterly Periods
	2013			2012
	Successor
	Quarter ended September 30			Quarter ended September 30
Operating revenues:
Oil and condensate	$	371		$	216
Natural gas	78			96
NGL	22			14
Total physical sales	471			326
Financial derivatives	(142		)	(181		)
Total operating revenues	329			145
Operating expenses:
Natural gas purchases	6			9
Transportation costs	24			21
Lease operating expense	41			28
General and administrative	49			75
Depreciation, depletion and amortization	172			81
Impairment charges	2			—
Exploration expense	12			20
Taxes, other than income taxes	25			16
Total operating expenses	331			250
Operating loss	(2		)	(105		)
Loss from unconsolidated affiliates	(19		)	(2		)
Loss on extinguishment of debt	(6		)	(14		)
Interest expense	(83		)	(84		)
Loss from continuing operations	(110		)	(205		)
Income from discontinued operations	458			9
Net income (loss)	$	348		$	(196	)

34

	Year-to-Date Periods
	2013			2012
	Successor						Predecessor
	Nine months ended September 30			March 23 (inception) to September 30			January 1 to May 24
Operating revenues:
Oil and condensate	$	929		$	282		$	310
Natural gas	259			134			228
NGL	54			18			29
Total physical sales	1,242			434			567
Financial derivatives	(107		)	(124		)	365
Total operating revenues	1,135			310			932
Operating expenses:
Natural gas purchases	16			13			—
Transportation costs	70			30			45
Lease operating expense	119			38			80
General and administrative	162			281			69
Depreciation, depletion and amortization	443			106			307
Impairment/Ceiling test charges	2			1			62
Exploration expense	39			26			—
Taxes, other than income taxes	63			24			31
Total operating expenses	914			519			594
Operating income (loss)	221			(209		)	338
Loss from unconsolidated affiliates	(13		)	(3		)	(5		)
Other income	1			—			2
Loss on extinguishment of debt	(9		)	(14		)	—
Interest expense	(245		)	(137		)	(14		)
(Loss) income from continuing operations before income tax	(45		)	(363		)	321
Income tax expense	—			—			134
(Loss) income from continuing operations	(45		)	(363		)	187
Income (loss) from discontinued operations	496			17			(9		)
Net income (loss)	$	451		$	(346	)	$	178

Prior to the Acquisition in 2012, the successor had no independent oil and gas operations.  Accordingly there were no operational exploration and production activities that changed as a result of the acquisition of the predecessor. Consequently, in certain period-to-period explanations that follow we have provided supplemental information that compares results for the nine months ended September 30, 2013 with results for the successor period from March 23 to September 30, 2012 and for the predecessor period from January 1 to May 24, 2012 on a combined basis and excluding divested assets (such combined period is referred to as the “combined nine months ended September 30, 2012”).  We have provided this additional analysis for comparability of results and to aid in the analysis and understanding of our operating performance period over period.  Any non-GAAP analysis is provided as supplemental financial information to our GAAP results and is not intended to be a substitute for our reported separate successor and predecessor period GAAP results.

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Operating Revenues

The table below provides our operating revenues, volumes and prices per unit for the quarter and nine month periods ended September 30, 2013, and for each of the successor and predecessor periods in 2012. We present (i) average realized prices based on physical sales of oil and condensate, natural gas and NGL as well as (ii) average realized prices inclusive of the impacts of financial derivative settlements and premiums which reflect cash received and/or paid during the respective period.

	Quarterly Periods
	2013			2012
	Successor
	Quarter ended September 30			Quarter ended September 30
Operating revenues(1):
Oil and condensate	$	371		$	216
Natural gas	78			96
NGL	22			14
Total physical sales	471			326
Financial derivatives	(142		)	(181		)
Total operating revenues	$	329		$	145
Volumes(1):
Oil and condensate
Consolidated volumes (MBbls)	3,682			2,378
Unconsolidated affiliate volumes (MBbls)(2)	62			65
Natural gas
Consolidated volumes (MMcf)	22,320			33,663
Unconsolidated affiliate volumes (MMcf)(2)	2,684			3,845
NGL
Consolidated volumes (MBbls)	708			403
Unconsolidated affiliate volumes (MBbls)(2)	98			121
Equivalent volumes
Consolidated MBoe	8,110			8,391
Unconsolidated affiliate MBoe(2)	607			828
Total combined MBoe	8,717			9,219
Consolidated MBoe/d	88			91
Unconsolidated affiliate MBoe/d(2)	7			9
Total Combined MBoe/d	95			100
Consolidated prices per unit(3):
Oil and condensate
Average realized price on physical sales ($/Bbl)	$	100.84		$	90.44
Average realized price, including financial derivatives ($/Bbl)(4)	$	95.09		$	96.46
Natural gas
Average realized price on physical sales ($/Mcf)	$	3.22		$	2.60
Average realized price, including financial derivatives ($/Mcf)(4)	$	3.00		$	5.12
NGL
Average realized price on physical sales ($/Bbl)	$	31.39		$	34.78

(1)Operating revenues and volumes in the successor periods do not include amounts associated with domestic natural gas assets sold and all periods do not include Brazilian operations held for sale at September 30, 2013, as such are included as discontinued operations.

(2)In September 2013, we sold our equity investment in Four Star .

(3)Natural gas prices for the quarters ended September 30, 2013 and 2012 are calculated including a reduction of $6 million and $9 million, respectively, for natural gas purchases associated with managing our physical gas sales.

(4)The quarters ended September 30, 2013 and 2012 include $5 million of cash paid and $85 million of cash received for the settlement of natural gas financial derivatives.  The quarters ended September 30, 2013 and 2012, include $21 million of cash paid and $18 million of cash received for the settlement of crude oil derivative contracts respectively.  The quarters ended September 30, 2013 and 2012 include approximately $1 million of cash premiums received and approximately $4 million of cash premiums paid, respectively.

36

	Year-to-Date Periods
	2013			2012
	Successor			Successor			Predecessor
	Nine months ended September 30			March 23 (inception) to September 30			January 1 to May 24
Operating revenues(1):
Oil and condensate	$	929		$	282		$	310
Natural gas	259			134			228
NGL	54			18			29
Total physical sales	1,242			434			567
Financial derivatives	(107		)	(124		)	365
Total operating revenues	$	1,135		$	310		$	932
Volumes(1):
Oil and condensate
Consolidated volumes (MBbls)	9,561			3,199			3,105
Unconsolidated affiliate volumes (MBbls)(2)	198			93			115
Natural gas
Consolidated volumes (MMcf)	72,182			49,776			94,847
Unconsolidated affiliate volumes (MMcf)(2)	10,001			5,384			6,310
NGL
Consolidated volumes (MBbls)	1,806			550			673
Unconsolidated affiliate volumes (MBbls)(2)	328			169			190
Equivalent volumes
Consolidated MBoe	23,398			12,045			19,586
Unconsolidated affiliate MBoe(2)	2,192			1,159			1,357
Total combined MBoe	25,590			13,204			20,943
Consolidated MBoe/d	86
Unconsolidated affiliate MBoe/d(2)	8
Total Combined MBoe/d	94
Consolidated prices per unit(3):
Oil and condensate
Average realized price on physical sales ($/Bbl)	$	97.13		$	88.01		$	99.76
Average realized price, including financial derivatives ($/Bbl)(4)	$	98.96		$	94.69		$	99.61
Natural gas
Average realized price on physical sales ($/Mcf)	$	3.36		$	2.44		$	2.40
Average realized price, including financial derivatives ($/Mcf)(4)	$	3.08		$	4.84		$	4.15
NGL
Average realized price on physical sales ($/Bbl)	$	29.74		$	33.21		$	42.94

(1)Operating revenues and volumes in the successor periods do not include amounts associated with domestic natural gas assets sold and all periods do not include Brazilian operations held for sale at September 30, 2013, as such amounts are included as discontinued operations.

(2)In September 2013, we sold our equity investment in Four Star .

(3)Natural gas prices for the nine months ended September 30, 2013 and from March 23 (inception) to September 30, 2012 are calculated including a reduction of $16 million and $13 million, respectively, for natural gas purchases associated with managing our physical sales.

(4)The successor periods for the nine months ended September 30, 2013 and from March 23 (inception) to September 30, 2012 include $20 million of cash paid and $119 million of cash received for the settlement of natural gas financial derivatives.  The predecessor period from January 1 to May 24, 2012 includes $165 million of cash received for the settlement of natural gas financial derivatives.  The successor periods for the nine months ended September 30, 2013 and from March (inception) to September 30, 2012 include $10 million and $25 million of cash receipts for the settlement of crude oil derivative contracts.  The nine months ended September 30, 2013 and the period from March 23 (inception) to September 30, 2012, includes approximately $9 million of cash premiums received and approximately $4 million of cash premiums paid, respectively

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Physical sales.  Physical sales represent accrual-based commodity sales transactions with customers. For both the quarter and year to date periods in 2013, increases in oil sales were due primarily to oil volume growth from our Eagle Ford drilling program and increases in natural gas prices partially offset by a reduction in natural gas volumes.

Oil and condensate sales for the quarter and nine months ended September 30, 2013 compared to the quarter and combined (successor/predecessor) nine months ended September 30, 2012 increased by $155 million (72 percent) and $337 million (57 percent), due primarily to oil and volume growth from our Eagle Ford drilling program.  In 2013, Eagle Ford oil and condensate production increased by 10 MBbls/d or 67 percent compared with the quarter ended September 30, 2012 and by 11 MBbls/d or 89 percent compared with the combined (successor/predecessor) nine months ended September 30, 2012.

Natural gas sales for the quarterly periods ended September 30, 2013 and 2012 were $78 million and $96 million. For the nine months ended September 30, 2013 for the successor period from March 23 (inception) to September 30, 2012, natural gas sales were $259 million and $134 million, respectively. For the predecessor period from January 1 to May 24, 2012 were $228 million (including approximately $88 million of natural gas sales related to divested assets).  Natural gas sales decreased for the quarter ended September 30, 2013 compared with the quarter ended September 30, 2012 primarily due to the decrease in volumes due to natural production declines in the Haynesville Shale.   Natural gas sales (excluding amounts related to divested assets) increased for the nine months ended September 30, 2013 compared with the combined (successor/predecessor) nine month period ended September 30, 2012, due to higher natural gas prices partially offset by the decrease in volumes in Haynesville. During the first quarter of 2012, we suspended our drilling program in the Haynesville Shale due to low natural gas prices.

NGL sales increased for the quarter and nine months ended September 30, 2013 compared with the quarter and the combined (successor/predecessor) nine month period ended September 30, 2012.   Average realized prices for the quarter and nine months ended September 30, 2013 decreased compared to 2012, however, this was more than offset by an increase in 2013 in NGL volumes over 2012 primarily as a result of our Eagle Ford drilling program.  Eagle Ford NGL volumes increased by 4 MBbls/d and 3 MBbls/d or approximately 112 percent and 146 percent for the quarter and nine months ended September 30, 2013, respectively, compared with the quarter and nine months ended September 30, 2012.

As of September 30, 2013, the NYMEX spot price of a barrel of oil was $102.33 versus the NYMEX spot price of natural gas of $3.56, or a ratio of 29 to 1. We 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 revenue will largely be impacted by our ability to grow our oil volumes and by commodity 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 September 30, 2013, we recorded $142 million of derivative losses compared to a derivative loss of $181 million during the quarter ended September 30, 2012. During the nine months ended September 30, 2013, we recorded $107 million of derivative losses compared to a derivative gain of $241 million during the combined (successor/predecessor) nine months ended September 30, 2012.

Operating Expenses

Transportation costs.  Transportation costs for the quarters ended September 30, 2013 and 2012 were $24 million and $21 million. For the nine month period ended September 30, 2013 and for the successor period from March 23 (inception) to September 30, 2012, transportation costs were $70 million and $30 million, respectively, and for the predecessor period from January 1 to May 24, 2012 were $45 million (including $18 million of transportation costs related to divested assets).  Total transportation costs (excluding amounts related to the divested assets) for the quarter and nine months ended September 30, 2013 increased as compared to the same periods in 2012 due to oil transportation costs associated with our Eagle Ford play as a result of our production growth in that area.

Lease Operating Expense.  Lease operating expense for the quarters ended September 30, 2013 and 2012 were $41 million and $28 million, respectively.  For the nine month period ended September 30, 2013 and the successor period from March 23 (inception) to September 30, 2012, lease operating expenses were $119 million and $38 million, respectively, and for the predecessor period from January 1 to May 24, 2012 were $80 million (including approximately $31 million related to divested assets).  Lease operating expenses increased in 2013 over 2012 due to increased equipment and chemical costs in our Eagle Ford play and higher maintenance, repair and power costs.

General and administrative expenses.  General and administrative expenses for the quarter and nine months ended September 30, 2013 decreased $26 million and $188 million compared to the quarter and the combined (successor/predecessor) nine month period ended September 30, 2012. The decrease for the quarter was primarily due to transition and restructuring costs of $24 million recorded in the third quarter of 2012. The decrease for the nine months was primarily due to transition and restructuring costs of $207 million recorded in 2012, of which $183 million were recorded during the second quarter as a result of the Acquisition, partly offset by an increase of $10 million in management consulting and advisory

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service charges reflected for the nine months ended September 30, 2013 compared to the successor period from March 23 (inception) to September 30, 2012. Prior to the Acquisition, El Paso allocated general and administrative costs to us based on the estimated level of resources devoted to our operations and the relative size of our earnings before interest and taxes, gross property and payroll.

Depreciation, depletion and amortization expense.  Our depreciation, depletion and amortization costs increased in 2013 compared with 2012 due to the ongoing development of higher cost oil programs (e.g. Eagle Ford and Wolfcamp) as well as the step up in the book basis of our oil and natural gas assets as a result of the Acquisition. Our average depreciation, depletion and amortization costs per unit for the quarters and nine months ended September 30 were:

	Quarterly Periods				Year-to-Date Periods
	2013		2012		2013		2012
	Successor		Successor		Successor		Successor		Predecessor
	Quarter ended September 30		Quarter ended September 30		Nine months ended September 30		March 23 (inception) to September 30		January 1 to May 24
Depreciation, depletion and amortization ($/Boe)(1)	$	21.15	$	9.71	$	18.92	$	8.82	$	15.66

(1)           Includes $0.11 per Boe for the quarter ended September 30, 2013 and $0.12 per Boe for the quarter ended September 30, 2012 related to accretion expense on asset retirement obligations.  Includes $0.11 per Boe for the nine months ended September 30, 2013, $0.15 per Boe for the successor period from March 23 (inception) to September 30, 2012 and $0.23 for the predecessor period from January 1 to May 24, 2012 related to accretion expense on asset retirement obligations.

Impairment/Ceiling test charges.  We apply the successful efforts method of accounting and evaluate capitalized costs related to proved properties at least annually or upon a triggering event to determine if impairment of such properties is necessary.  Forward commodity prices can play a significant role in determining impairments. Considering the significant amount of fair value allocated to our oil and natural gas properties in conjunction with the Acquisition, sustained lower oil and natural gas prices from present levels could result in an impairment of the carrying value of our proved properties in the future.

The predecessor used the full cost method of accounting.  Under this method of accounting, the predecessor conducted quarterly ceiling tests of capitalized costs in each of the full cost pools. During the predecessor period from January 1, 2012 to May 24, 2012, we recorded non-cash charges of approximately $62 million as a result of our decision to end exploration activities in Egypt. In June of 2012, we sold all our interests in Egypt.

Exploration expense.  For the quarter and nine months ended September 30, 2013, we recorded $12 million and $39 million of exploration expense compared to $20 million and $26 million for the quarter and for the successor period from March 23 (inception) to September 30, 2012.  Exploration expense is the result of applying the successful efforts method of accounting following the Acquisition. Prior to the Acquisition, exploration costs were capitalized under full cost accounting. Included in exploration expense for the quarter and nine months ended September 30, 2013 is $10 million and $33 million of amortization of unproved property costs.  The quarter ended September 30, 2012 and the period from March 23 (inception) to September 30, 2012 include $14 million in both periods of amortization of unproved property costs.

Taxes, other than income taxes.  Taxes, other than income taxes for the quarters ended September 30, 2013 and 2012 were $25 million and $16 million, respectively. For the nine months ended September 30, 2013 and for the successor period from March 23 (inception) to September 30, 2012, taxes, other than income taxes, were $63 million and $24 million, and for the predecessor period from January 1 to May 24, 2012 were $31 million (including approximately $9 million of taxes, other than income taxes related to divested assets).  Production taxes increased in 2013 compared to the quarter and the combined (successor/predecessor) periods in 2012 due to higher production volumes. Additionally, year-to-date production taxes in 2013 reflect a reduction in sales and use tax of $13 million recorded in the second quarter of 2013 associated with settling a Texas sales and use tax audit for $3 million, including penalties and fees.

39

Cash Operating Costs and Adjusted Cash Operating Costs.  We monitor cash operating costs required to produce our oil and natural gas. Cash operating costs are 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 ceiling test charges and other expenses. Adjusted cash operating costs are a non-GAAP measure and is defined as cash operating costs less transition and restructuring costs, advisory fees paid to Sponsors and the non-cash portion of compensation expense. Cash operating costs and adjusted cash operating costs per unit are a valuable measure of operating performance and efficiency; however, these measures may not be comparable to similarly titled measures used by other companies. The tables below represent a reconciliation of our cash operating costs and adjusted cash operating costs to operating expenses for the quarterly and year-to-date periods ended September 30:

	Quarterly Periods
	2013						2012
	Successor						Successor
	Quarter ended September 30						Quarter ended September 30
	Total			Per Unit (1)			Total			Per Unit (1)
	(In millions, except per unit costs)
Total operating expenses	$	331		$	40.93		$	250		$	29.84
Depreciation, depletion and amortization	(172		)	(21.15		)	(81		)	(9.71		)
Transportation costs	(24		)	(2.97		)	(21		)	(2.46		)
Exploration expense	(12		)	(1.51		)	(20		)	(2.42		)
Natural gas purchases	(6		)	(0.80		)	(9		)	(1.05		)
Impairment charges	(2		)	(0.24		)	—			—
Total cash operating costs	115			14.26			119			14.20
Transition/restructuring costs and non-cash compensation expense(2)	(14		)	(1.81		)	(39		)	(4.65		)
Total adjusted cash operating costs and adjusted per-unit cash costs(2)	$	101		$	12.45		$	80		$	9.55
Total equivalent volumes (MBoe)(3)	8,110						8,391

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	Year-to-Date Periods
	2013						2012
	Successor						Successor						Predecessor
	Nine months ended September 30						March 23 (inception) to September 30						January 1 to May 24
	Total			Per Unit (1)			Total			Per Unit (1)			Total			Per Unit (1)
	(In millions, except per unit costs)
Total continuing operating expenses	$	914		$	39.08		$	519		$	43.11		$	594		$	30.32
Depreciation, depletion and amortization	(443		)	(18.92		)	(106		)	(8.82		)	(307		)	(15.66		)
Transportation costs	(70		)	(2.98		)	(30		)	(2.46		)	(45		)	(2.32		)
Exploration expense	(39		)	(1.68		)	(26		)	(2.13		)	—			—
Natural gas purchases	(16		)	(0.71		)	(13		)	(1.06		)	—			—
Impairment/Ceiling test charges	(2		)	(0.08		)	(1		)	(0.09		)	(62		)	(3.15		)
Total continuing cash operating costs	344			14.71			343			28.55			180			9.19
Transition/restructuring costs and non-cash compensation expense(2)	(48		)	(2.04		)	(231		)	(19.16		)	(11		)	(0.58		)
Total adjusted cash operating costs and adjusted per-unit cash costs(2)	$	296		$	12.67		$	112		$	9.39		$	169		$	8.61
Total equivalent volumes (MBoe)(3)	23,398						12,045						19,586

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

(2)Includes $6 million of advisory fees paid to Sponsors and $8 million of non-cash compensation expense for the quarter ended September 30, 2013 and $25 million of transition and severance costs, $6 million of advisory fees paid to Sponsors and $8 million of non-cash compensation expense for the quarter ended September 30, 2012. The nine months ended September 30, 2013 include $7 million of transition and severance costs, $19 million of advisory fees paid to Sponsors, and $22 million of non-cash compensation expense. The period from March 23 (inception) to September 30, 2012 includes $203 million of transition and severance costs, $9 million of advisory fees paid to Sponsors and $19 million of non-cash compensation expense. The period from January 1 to May 24, 2012 includes $5 million of severance costs and $6 million of non-cash compensation expense.

(3)Excludes volumes and costs associated with Four Star.

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

	Quarterly Periods						Year-to-Date Periods
	2013			2012			2013			2012
	Successor			Successor			Successor			Successor			Predecessor
	Quarter ended September 30			Quarter ended September 30			Nine months ended September 30			March 23 (inception) to September 30			January 1 to May 24
Average cash operating costs ($/Boe)
Lease operating expenses	$	5.12		$	3.30		$	5.11		$	3.20		$	4.07
Production taxes(1)	2.92			2.07			2.98			2.03			1.79
General and administrative expenses	6.04			8.89			6.92			23.32			3.53
Taxes, other than production and income taxes	0.18			(0.06		)	(0.30		)	—			(0.20		)
Total cash operating costs	$	14.26		$	14.20		$	14.71		$	28.55		$	9.19
Transition/restructuring costs and non-cash compensation expense	$	(1.81	)	$	(4.65	)	$	(2.04	)	$	(19.16	)	$	(0.58	)
Total adjusted cash operating costs	$	12.45		$	9.55		$	12.67		$	9.39		$	8.61

(1)Production taxes include ad valorem and severance taxes which increased during the quarter and nine months ended September 30, 2013 primarily due to higher ad valorem taxes associated with our oil producing areas.

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Other Income Statement Items.

Loss from unconsolidated affiliates.  For the quarter and nine months ended September 30, 2013 we recorded losses on our equity investees as a result of an impairment recorded upon our decision to sell our investment in Four Star.  The impairment of $20 million was based on comparison of $183 million in net proceeds received for the sale of Four Star in September 2013 to the underlying carrying value of the investment.

Loss on extinguishment of debt.  For the quarter ended September 30, 2013, we recorded $6 million in losses of extinguishment of debt for the portion of deferred financing costs written off in conjunction with the repayment of approximately $250 million under each of our $750 million and $400 million term loans.  For the nine months ended September 30, 2013, we recorded $9 million in losses of extinguishment of debt for the portion of deferred financing costs written off in conjunction with (i) the repayment of approximately $250 million under each of our $750 million and $400 million term loans, (ii) our $750 million term loan re-pricing in May 2013 and (iii) the semi-annual redeterminations of our RBL in March 2013.  For the quarter and nine months ended September 30, 2012, we recorded $14 million in loss of extinguishment of debt for the pro-rata portion of deferred financing costs written off, debt discount and call premiums paid in related to our $750 million term loan re-pricing.

Interest expense.  Interest expense for the quarter ended September 30, 2013 remained flat compared with the same period in 2012. Interest expense for the nine months ended September 30, 2013 compared to the same period in 2012 increased due to the issuance of approximately $4.25 billion of debt in conjunction with the Acquisition in May 2012. Prior to the Acquisition and related financing transactions, interest expense primarily related to borrowings under the predecessor’s $1 billion credit facility in place at that time.  In August 2013, we repaid $785 million of amounts outstanding under our RBL Facility using proceeds from recently completed asset divestitures and repaid approximately $500 million under our term loans.

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

Overview.  Our primary sources of liquidity are cash generated by our operations and borrowings under the RBL Facility. Our primary uses of cash are capital expenditures, debt service requirements and working capital requirements. In August 2013, we completed our semi-annual redetermination maintaining the borrowing base of our RBL Facility at $2.5 billion. As of September 30, 2013, our available liquidity was approximately $2.55 billion, including approximately $2.49 billion of additional borrowing capacity available under the RBL Facility and cash on hand.

During June 2013, we entered into three separate purchase and sale agreements for the sale of CBM properties (Raton, Arkoma and Black Warrior basins), the majority of our Arklatex natural gas properties and our natural gas properties in south Texas. In July and August we completed these sales receiving total consideration of approximately $1.3 billion.  Additionally, in September 2013, we sold our approximate 49% equity interest in Four Star for approximately $183 million. We will experience lower cash flow from operations than originally planned as a result of these sales, but have used the proceeds, among other items, to pay down debt and invest incremental capital in our core oil programs to generate high return oil production growth.

As of September 30, 2013, our long-term debt was approximately $3.7 billion, comprised of $3.1 billion in senior notes due in 2019, 2020 and 2022 and $0.6 billion in senior secured term loans with maturity dates in 2018 and 2019. While our debt and interest expense is significantly higher than in predecessor periods due to debt incurred with the Acquisition, we have repaid approximately $785 million of amounts outstanding under our RBL Facility with proceeds from our asset divestitures in July and August 2013.  We also repaid approximately $500 million under our term loans.  Where favorable debt markets allow, we also evaluate opportunities to reduce our interest cost.  In May 2013, we repriced our $750 million term loan due 2018 which reduced the specified margin over LIBOR from 4.00% to 2.75%, and reduced the minimum LIBOR floor from 1.00 % to 0.75% over the remaining life of the term loan.  In July 2013, we made a leveraged distribution of $200 million to our member, which we funded with borrowings under the RBL Facility. For additional details on our long-term debt, see Part I Item 1, Note 7.

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 2013 capital program current obligations and projected working capital requirements for the foreseeable future.  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, depends on prevailing economic conditions many of which are beyond our control.  We have attempted to

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mitigate certain of these risks.  For example, we enter into oil and 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 (i) in allowing us to realize prices on our commodity sales that are roughly at or above prevailing market prices for oil and natural gas and (ii) 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 2013, we received $9 million in premiums on such transactions, substantially all of which will settle during the remainder of 2013. We could be required to take additional future actions if necessary to address further changes in the financial or commodity markets.

Overview of Cash Flow Activities.  For the nine months ended September 30, our cash flows from operations including continuing and discontinued activities are summarized as follows (in millions):

	Successor						Predecessor
	Nine Months ended September 30, 2013			March 23 (Inception) to September 30, 2012			January 1 toMay 24, 2012
Cash Flow from Operations
Operating activities
Net income (loss)	$	451		$	(346	)	$	178
Impairment/Ceiling test charges	28			1			62
Other income adjustments	150			193			537
Change in other assets and liabilities	161			407			(197		)
Total cash flow from operations	$	790		$	255		$	580
Other Cash Inflows
Investing activities
Net proceeds from the sale of assets and investment	1,439			110			9
Financing activities
Proceeds from long-term debt	1,310			4,823			215
Contributions	—			3,323			960
	1,310			8,146			1,175
Total cash inflows	$	2,749		$	8,256		$	1,184
Cash Outflows
Investing activities
Capital expenditures	$	1,420		$	475		$	636
Cash paid for acquisitions	2			7,126			1
	$	1,422		$	7,601		$	637
Financing activities
Repayment of long-term debt	1,915			609			1,065
Dividends paid to parent	200			—			—
Debt issuance costs	4			149			—
	2,119			758			1,065
Total cash outflows	$	3,541		$	8,359		$	1,702
Net change in cash and cash equivalents	$	(2	)	$	152		$	62

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Item 3. Qualitative and Quantitative Disclosures About Market Risk

This information updates, and should be read in conjunction with the information disclosed in our 2012 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 2012 Annual Report on Form 10-K, except as presented below:

Commodity Price Risk

The table below presents the hypothetical sensitivity of our commodity-based price risk management activities to changes in fair values arising from immediate selected potential changes in oil and natural gas prices, discount rates and credit rates at September 30, 2013:

			Oil and Natural Gas Derivative Instruments
			10 Percent Increase						10 Percent Decrease
	Fair Value		Fair Value			Change			Fair Value		Change
	(in millions)
Price impact(1)	$	62	$	(443	)	$	(505	)	$	557	$	495

			Oil and Natural Gas Derivative Instruments
			1 Percent Increase					1 Percent Decrease
	Fair Value		Fair Value		Change			Fair Value		Change
	(in millions)
Discount rate(2)	$	62	$	60	$	(2	)	$	64	$	2
Credit rate(3)	$	62	$	62	$	—		$	63	$	1

(1)	Presents the hypothetical sensitivity of our commodity-based derivative instruments to changes in fair values arising from changes in oil and natural gas 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 September 30, 2013, we carried out an evaluation under the supervision and with the participation of our management, including our Chief Executive Officer (CEO) and our Chief Financial Officer (CFO), as to the effectiveness, design and operation of our disclosure controls and procedures. This evaluation considered the various processes carried out under the direction of our disclosure committee in an effort to ensure that information required to be disclosed in the U.S. Securities and Exchange Commission reports we file or submit under the Securities Exchange Act of 1934, as amended (Exchange Act), is accurate, complete and timely. Our management, including our CEO and our CFO, does not expect that our disclosure controls and procedures or our internal controls will prevent and/or detect all errors and all fraud. A control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Further, the design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, within our company have been detected. Our disclosure controls and procedures are designed to provide reasonable assurance of achieving their objectives and our CEO and CFO concluded that our disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) were effective as of September 30, 2013.

Changes in Internal Control over Financial Reporting

There were no changes in EP Energy LLC’s internal control over financial reporting during the first nine months of 2013 that materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

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PART II — OTHER INFORMATION

Item 1. Legal Proceedings

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 2012 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

Disclosure Pursuant to Section 219 of the Iran Threat Reduction and Syria Human Rights Act

Apollo Global Management, LLC (“Apollo”) has provided notice to us that, as of October 24, 2013, certain investment funds managed by affiliates of Apollo beneficially owned approximately 22% of the limited liability company interests of CEVA Holdings, LLC (“CEVA”).  Under the limited liability company agreement governing CEVA, certain investment funds managed by affiliates of Apollo hold a majority of the voting power of CEVA and have the right to elect a majority of the board of CEVA.  CEVA may be deemed to be under common control with us, but this statement is not meant to be an admission that common control exists.  As a result, it appears that we are required to provide disclosures as set forth below pursuant to Section 219 of the Iran Threat Reduction and Syria Human Rights Act of 2012 (“ITRA”) and Section 13(r) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”).

Apollo has informed us that CEVA has provided it with the information below relevant to Section 13(r) of the Exchange Act.  The disclosure below does not relate to any activities conducted by us and does not involve us or our management. The disclosure relates solely to activities conducted by CEVA and its consolidated subsidiaries.  We have not independently verified or participated in the preparation of the disclosure below.

“Through an internal review of its global operations, CEVA has identified the following transactions in an Initial Notice of Voluntary Self-Disclosure that CEVA filed with the U.S. Treasury Department Office of Foreign Assets Control (“OFAC”) on October 28, 2013.  CEVA’s review is ongoing.  CEVA will file a further report with OFAC after completing its review.

The internal review indicates that, in December 2012, CEVA Freight Italy Srl (“CEVA Italy”) provided customs brokerage and freight forwarding services for the export to Iran of two measurement instruments to the Iranian Offshore Engineering Construction Company, a joint venture between two entities that are identified on OFAC’s list of Specially Designated Nationals (“SDN”).  The revenues and net profits for these services were approximately $1,260.64 USD and $151.30 USD, respectively.  In February 2013, CEVA Freight Holdings (Malaysia) SDN BHD (“CEVA Malaysia”) provided customs brokerage for export and local haulage services for a shipment of polyethylene resin to Iran shipped on a vessel owned and/or operated by HDS Lines, also an SDN.  The revenues and net profits for these services were approximately $779.54 USD and $311.13 USD, respectively.  In September 2013, CEVA Malaysia provided customs brokerage services for the import into Malaysia of fruit juice from Alifard Co. in Iran via HDS Lines.  The revenues and net profits for these services were approximately $227.41 USD and $89.29 USD, respectively.

These transactions violate the terms of internal CEVA compliance policies, which prohibit transactions involving Iran.  Upon discovering these transactions, CEVA promptly launched an internal investigation, and is taking action to block and prevent such transactions in the future.  CEVA intends to cooperate with OFAC in its review of this matter.”

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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.

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SIGNATURES

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

	EP ENERGY LLC
Date: November 7, 2013	/s/ Dane E. Whitehead
	Dane E. Whitehead
	Executive Vice President and Chief Financial Officer
	(Principal Financial Officer)
Date: November 7, 2013	/s/ Francis C. Olmsted III
	Francis C. Olmsted III
	Vice President and Controller
	(Principal Accounting Officer)

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EP ENERGY LLC

EXHIBIT INDEX

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

ExhibitNumber	Description
10.1+	Management Incentive Plan Agreement, dated as of August 30, 2013, between EP Energy Corporation and EPE Employee Holdings, LLC (Exhibit 10.31 to Amendment No. 2 to EP Energy Corporation’s Registration Statement on Form S-1, filed with the SEC on November 1, 2013). †
10.2+	Form of Notice to MIPs Holders regarding Corporate Reorganization (Exhibit 10.33 to EP Energy Corporation’s Registration Statement on Form S-1, filed with the SEC on September 4, 2013).
10.3+	Third Amended and Restated Limited Liability Company Agreement of EPE Employee Holdings, LLC dated as of August 30, 2013 (Exhibit 10.34 to Amendment No. 2 to EP Energy Corporation’s Registration Statement on Form S-1, filed with the SEC on November 1, 2013). †
10.4+	Third Amended and Restated Limited Liability Company Agreement of EPE Management Investors, LLC dated as of August 30, 2013 (Exhibit 10.35 to Amendment No. 2 to EP Energy Corporation’s Registration Statement on Form S-1, filed with the SEC on November 1, 2013). †
10.5+	Subscription Agreement, dated as of August 30, 2013, between EP Energy Corporation and EPE Management Investors, LLC (Exhibit 10.36 to EP Energy Corporation’s Registration Statement on Form S-1, filed with the SEC on September 4, 2013).
10.6+	Form of EP Energy Employee Holdings II, LLC Class B Incentive Pool Program Award Agreement (Exhibit 10.37 to Amendment No. 1 to EP Energy Corporation’s Registration Statement on Form S-1, filed with the SEC on October 11, 2013).
*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.

*     Filed herewith.

+     Management contract or compensatory plan, contract or agreement.

†     Confidential treatment has been requested with respect to certain portions of this exhibit. Omitted portions have been filed separately with the SEC.