EP Energy 10-Q 2013 Q1 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 March 31, 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	24
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	34
Item 4.	Controls and Procedures	35
	PART II — OTHER INFORMATION
Item 1.	Legal Proceedings	35
Item 1A.	Risk Factors	35
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	35
Item 3.	Defaults Upon Senior Securities	35
Item 4.	Mine Safety Disclosures	35
Item 5.	Other Information	35
Item 6.	Exhibits	36
Signatures		37

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 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 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.

1

PART I — FINANCIAL INFORMATION

Item 1. Financial Statements

EP ENERGY LLC
CONDENSED CONSOLIDATED STATEMENTS OF INCOME

(In millions)

(Unaudited)

	Successor			Predecessor
	Quarter ended March 31,			Quarter ended  March 31,
	2013			2012
Operating Revenues
Oil and condensate	$	280		$	209
Natural gas	159			182
NGL	19			17
Financial derivatives	(131		)	76
Total operating revenues	327			484
Operating expenses
Transportation costs	29			25
Lease operating expense	64			62
General and administrative	63			44
Depreciation, depletion and amortization	149			201
Ceiling test charges	—			62
Exploration expense	14			—
Taxes, other than income taxes	31			28
Total operating expenses	350			422
Operating (loss) income	(23		)	62
Earnings (loss) from unconsolidated affiliates	2			(3		)
Other income	1			1
Loss on extinguishment of debt	(1		)	—
Interest expense	(84		)	(4		)
(Loss) income before income taxes	(105		)	56
Income tax expense	1			41
Net (loss) income	$	(106	)	$	15

See accompanying notes.

2

EP ENERGY LLC
CONDENSED CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME

(In millions)

(Unaudited)

	Successor			Predecessor
	Quarter ended March 31,			Quarter ended  March 31,
	2013			2012
Net (loss) income	$	(106	)	$	15
Cash flow hedging activities:
Reclassification adjustment(1)	—			2
Comprehensive (loss) income	$	(106	)	$	17

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

See accompanying notes.

3

EP ENERGY LLC

CONDENSED CONSOLIDATED BALANCE SHEETS

(In millions)

(Unaudited)

	March 31, 2013		December 31, 2012
ASSETS
Current assets
Cash and cash equivalents	$	71	$	63
Accounts receivable
Customer, net of allowance of less than $1 in 2013 and 2012	248		226
Other, net of allowance of $1 for 2013 and 2012	16		21
Materials and supplies	23		22
Derivative instruments	30		108
Prepaid assets	39		20
Other	1		4
Total current assets	428		464
Property, plant and equipment, at cost
Oil and natural gas properties	7,952		7,533
Other property, plant and equipment	109		103
	8,061		7,636
Less accumulated depreciation, depletion and amortization	424		266
Total property, plant and equipment, net	7,637		7,370
Other assets
Investments in unconsolidated affiliates	220		226
Derivative instruments	67		88
Deferred income taxes	6		6
Unamortized debt issue cost	129		134
Other	12		5
	434		459
Total assets	$	8,499	$	8,293

See accompanying notes.

4

EP ENERGY LLC

CONDENSED CONSOLIDATED BALANCE SHEETS

(In millions)

(Unaudited)

	March 31, 2013		December 31, 2012
LIABILITIES AND EQUITY
Current liabilities
Accounts payable
Trade	$	128	$	126
Other	359		358
Derivative instruments	70		17
Accrued taxes other than income	30		23
Accrued interest	108		57
Accrued taxes	17		19
Asset retirement obligations	10		10
Other accrued liabilities	19		48
Total current liabilities	741		658
Long-term debt	4,556		4,346
Other long-term liabilities
Derivative instruments	21		14
Asset retirement obligations	183		180
Other	12		10
Total non-current liabilities	4,772		4,550
Commitments and contingencies (Note 8)
Member’s equity	2,986		3,085
Total liabilities and equity	$	8,499	$	8,293

See accompanying notes.

5

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

	Successor			Predecessor
	Quarter ended March 31,			Quarter ended March 31,
	2013			2012
Cash flows from operating activities
Net (loss) income	$	(106	)	$	15
Adjustments to reconcile net (loss) income to net cash from operating activities
Depreciation, depletion and amortization	149			201
Deferred income tax expense	—			41
(Earnings) loss from unconsolidated affiliates, adjusted for cash distributions	6			11
Ceiling test charges	—			62
Loss on extinguishment of debt	1			—
Amortization of equity compensation expense	7			—
Non-cash portion of exploration expense	12			—
Amortization of debt issuance cost	5			—
Asset and liability changes
Accounts receivable	(18		)	25
Accounts payable	16			(19		)
Derivative instruments	159			6
Accrued interest	52			—
Other asset changes	(24		)	(3		)
Other liability changes	(25		)	(2		)
Net cash provided by operating activities	234			337
Cash flows from investing activities
Capital expenditures	(444		)	(410		)
Net proceeds from the sale of assets	10			5
Cash paid for acquisitions, net of cash acquired	—			(1		)
Net cash used in investing activities	(434		)	(406		)
Cash flows from financing activities
Proceeds from long term debt	390			175
Repayment of long term debt	(180		)	(65		)
Debt issuance costs	(2		)	—
Net cash provided by financing activities	208			110
Change in cash and cash equivalents	8			41
Cash and cash equivalents
Beginning of period	63			25
End of period	$	71		$	66

See accompanying notes

6

EP ENERGY LLC

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY

(In millions)

(Unaudited)

	Total Member’s Equity
Balance at December 31, 2012	$	3,085
Equity compensation expense	7
Net loss	(106		)
Balance at March 31, 2013	$	2,986

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) following 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. These entities constituted the oil and natural gas operations of El Paso prior to the Acquisition. Hereinafter, we refer to the transactions above as the Acquisition and the acquired entities 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 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 financial statements as of March 31, 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 balance sheet filed in our 2012 Annual Report on Form 10-K.  In our opinion, all adjustments which are of a normal, recurring nature to fairly present these interim period results are reflected. 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.  The predecessor period reflects reclassifications to conform to EP Energy LLC’s financial statement presentation.

Significant Accounting Policies

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 March 31, 2013.

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 sale, a portion of the proceeds were also used to repay approximately $960 million outstanding under 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 presented as of March 31, 2013, reflects our 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

8

The unaudited pro forma information below for the quarter ended March 31, 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  March 31,
	2012
	(In millions)
Operating Revenues	$	484
Net Income	60

Divestitures. During the quarter ended March 31, 2013, we received approximately $10 million for the sale of domestic oil and natural gas properties.  No gain or loss was recorded on this sale.

3. Ceiling Test Charges

Prior to the Acquisition, 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 ended March 31, 2012, the predecessor recorded a non-cash ceiling test charge of approximately $62 million as a result of the decision to exit exploration and development 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.  For the quarter ended March 31, 2013, the effective tax rate is less than one percent, significantly lower than the statutory rate primarily due to the conversion in 2012 to a limited liability company treated as a partnership for federal and state income tax purposes. We continue to be subject to foreign income taxes on our Brazil operations. Prior to the Acquisition, the predecessor was party to a tax accrual policy with El Paso whereby they filed U.S. and certain state returns on the predecessor’s behalf. For the predecessor period ended March 31, 2012, the effective tax rate was 73 percent, significantly higher than the statutory rate primarily due to the impact of a ceiling test charge that did not have a corresponding tax benefit.

5. Financial Instruments

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

	March 31, 2013				December 31, 2012
	CarryingAmount		FairValue		CarryingAmount		FairValue
	(In millions)
Long-term debt	$	4,556	$	4,992	$	4,346	$	4,690
Derivative instruments	$	6	$	6	$	165	$	165

As of March 31, 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 (see Note 7) with various terms. We estimated the fair value of debt (representing a Level 2 fair value measurement) primarily based on quoted market prices for the same or similar issuances, including consideration of our credit risk related to 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 March 31, 2013 and December 31, 2012, we had total derivative contracts related to 34,075 MBbl and 34,232 MBbl of oil and 281 TBtu and 276 TBtu of natural gas, respectively. None of these contracts are designated as accounting hedges.

9

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 ended March 31, 2013 we recorded $1 million 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 March 31, 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 other levels.

Financial Statement Presentation.  The following table presents the fair value associated with derivative financial instruments as of March 31, 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
	March 31, 2013			December 31, 2012
	(In millions)
Assets
Oil and natural gas derivative instruments	$	165		$	231
Interest rate derivative instruments	—			4
Impact of master netting arrangements	(68		)	(39		)
Total derivative assets(1)	97			196
Liabilities
Oil and natural gas derivative instruments	(157		)	(64		)
Interest rate derivative instruments	(2		)	(6		)
Impact of master netting arrangements	68			39
Total derivative liabilities(1)	(91		)	(31		)
Total	$	6		$	165

(1)   As of March 31, 2013 total derivative instruments include $30 million in current assets, $67 million in non-current assets, $70 million in current liabilities and $21 million in non-current liabilities on our balance sheet.  As of December 31, 2012 total derivative instruments include $108 million in current assets, $88 million in non-current assets, $17 million in current liabilities and $14 million in non-current liabilities on our balance sheet.

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):

	Successor			Predecessor
	Quarter ended March 31,			Quarter ended March 31,
	2013			2012
Realized and unrealized (losses) gains	$	(131	)	$	76
Accumulated other comprehensive income	—			(3		)

10

6.  Property, Plant, and Equipment

Unproved oil and natural gas properties.  As of December 31, 2012 and March 31, 2013, we had $2.3 billion and $2.0 billion of unproved oil and natural gas properties on our balance sheet primarily a result of the allocation of the purchase price in conjunction with the Acquisition. The reduction is largely attributable to transferring approximately $0.28 billion from unproved properties to proved properties.  As of March 31, 2013 we recorded $12 million of amortization of unproved leasehold costs in exploration expense in our income statement.  Suspended well costs were not material as of March 31, 2013.

Impairments 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 a triggering event to determine if impairment of such properties is necessary.  During the first quarter of 2013, no impairments of our oil and natural gas properties were recorded.  Forward commodity prices can play a significant role in determining impairments. Due to the current forecast of future natural gas prices and 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.

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 balance sheet in other current and non-current liabilities.  Changes in the net liability from December 31, 2012 through March 31, 2013 were as follows:

	2013
	(In millions)
Net asset retirement liability at January 1	$	190
Liabilities settled	(1		)
Property sales	(1		)
Accretion expense	3
Liabilities incurred	2
Net asset retirement liability at March 31	$	193

Capitalized Interest.  Interest expense is reflected in our financial statements net of capitalized interest. Capitalized interest for the successor period ended March 31, 2013 was $5 million. Capitalized interest for the predecessor period ended March 31, 2012 was $3 million.

7. Long Term Debt

Listed below are our debt obligations as of March 31:

	Interest Rate	March 31, 2013
		(In millions)
$2.5 billion RBL credit facility - due May 24, 2017	Variable	$	315
$750 million term loan - due April 24, 2018 (1) (3)	Variable	742
$400 million senior secured term loan - due April 30, 2019 (2) (3)	Variable	399
$750 million senior secured note - due May 1, 2019 (3)	6.875%	750
$2.0 billion senior unsecured note - due May 1, 2020	9.375%	2,000
$350 million senior unsecured note - due September 1, 2022	7.75%	350
Total		$	4,556

(1)	The Term Loan was issued at 99 percent of par and carries a specified margin over the LIBOR of 4.00%, with a minimum LIBOR floor of 1.00%. As of March 31, 2013 the effective interest rate of the note was 5.00%. In May 2013, we entered into an agreement to reprice our term loan which will carry a specified margin over the LIBOR of 2.75%, with a minimum LIBOR floor of 0.75% over the remaining life of the term loan.
(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 first quarter of 2013, we amortized $5 million of deferred financing costs in interest expense.  As of March 31, 2013 we have $129 million remaining in deferred financing costs.

11

$2.5 Billion Reserve-based Loan (RBL). After completing our borrowing base redetermination in March 2013, we increased our $2 billion RBL credit facility to a $2.5 billion facility.  Under this RBL facility, we can borrow funds or issue letters of credit (LCs) and as of March 31, 2013, we had a $2.5 billion RBL borrowing base, $315 million of outstanding borrowings, and approximately $9 million of letters of credit issued, leaving $2.18 billion of remaining capacity. During the quarter ended March 31, 2013, we borrowed an additional $210 million under the RBL Facility.  As of May 8, 2013, we had $515 million of outstanding borrowings under our RBL Facility.

Our credit 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 from such facilities in the future.  For a further discussion of our credit facility see our 2012 Annual Report on Form 10-K.

Guarantees.  Our obligations under the RBL, 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 March 31, 2013, foreign subsidiaries that do not guarantee the unsecured notes held approximately 2% of our consolidated assets and had no outstanding indebtedness, excluding intercompany obligations. For the quarter ended March 31, 2013 these non-guarantor subsidiaries generated approximately 8% 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 March 31, 2013, we were in compliance with all of our debt covenants. For a further discussion of our credit facilities 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 March 31, 2013, we had approximately $18 million accrued for all outstanding legal proceedings and other contingent matters, including a reserve related to an audit of sales and use taxes in the State of Texas.

Brazil Labor Claim.  In Brazil, one of our subsidiaries as well as a formerly affiliated party have been named in a lawsuit by a former contractor of the former affiliated party claiming entitlement to certain employee benefits under Brazilian law.  The case is currently pending before the 42nd Labor Court of the State of Rio de Janeiro. We are currently unable to estimate a range of reasonably possible loss, if any, primarily due to the early stages of the proceedings and the novelty of the legal claims being presented.

Sales Tax Audits. As a result of sales and use tax audits during 2010, the state of Texas has asserted additional taxes plus penalties and interest for the audit period 2001-2008 for two of our operating entities.  We are indemnified by KMI if and to the extent the ultimate outcomes exceed the reserves.  During 2012 we settled one of our Texas sales and use tax audits for $3 million, including fees. We are currently contesting the remaining assessment and the ultimate outcome is still uncertain. We believe amounts reserved are adequate.

12

Environmental Matters

We are subject to existing federal, state and local laws and regulations governing environmental air, land and water quality.  The environmental laws and regulations to which we are subject also require us to remove or remedy the effect on the environment of the disposal or release of specified substances at current and former operating sites. As of March 31, 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.

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 regulating 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. In August 2010, the EPA finalized a rule that mandates emission reductions of hazardous air pollutants from reciprocating internal combustion engines that requires us to install emission controls on engines across our operations.  Certain amendments to this rule were finalized in January 2013. Engines subject to the regulations must comply by October 2013. We currently estimate to incur capital expenditures in 2013 to complete the required modifications and testing of less than $1 million.

In August 2012, EPA finalized New Source Performance Standard regulations to reduce various air pollutants from the oil and natural gas industry. These regulations will limit emissions from the hydraulic fracturing of certain natural gas wells and equipment including compressors, storage vessels and natural gas processing plants. EPA has recently proposed amendments to this rule, in part phasing in emission controls for storage vessels past current deadlines. We do not anticipate a material impact associated with compliance to these new requirements.

In the State of Utah we are currently obtaining or amending air quality permits for a number of small oil and natural gas production facilities. As part of this permitting process we anticipate the installation of tank emission controls that will require approximately $2 million capital expenditures starting in 2013 and extending through 2014.

Hydraulic Fracturing Regulations. We use hydraulic fracturing extensively in our operations. Various regulations have been adopted and proposed at the federal, state and local levels to regulate hydraulic fracturing operations. These regulations range from banning or substantially limiting hydraulic fracturing operations, requiring disclosure of the hydraulic fracturing fluids and requiring additional permits for the use, recycling and disposal of water used in such operations. In addition, various agencies, including the EPA, the Department of Interior and Department of Energy are reviewing changes in their regulations to address the environmental impacts of hydraulic fracturing operations. Until such regulations are implemented, it is uncertain what impact they might have on our operations.

Comprehensive Environmental Response, Compensation and Liability Act (CERCLA) Matters. As part of our environmental remediation projects, we have received notice that we could be designated, or have been asked for information to determine whether we could be designated as a Potentially Responsible Party (PRP) with respect to the Casmalia Remediation site located in California under the CERCLA or state equivalents. As of March 31, 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.

13

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 include a cash-based long term incentive program and certain long-term equity based programs established in conjunction with the Acquisition including Class A “matching units”, a “guaranteed cash bonus”, and management incentive units each of which are further described in our 2012 Annual Report on Form 10-K.  During the quarter ended March 31, 2013, we recorded approximately $13 million in expense related to all of these long-term incentive awards.  As of March 31, 2013, we had unrecognized compensation expense of $52 million related to our cash based long-term incentive awards, Class A “matching units”, and management incentive units.  We will recognize an additional $20 million related to these outstanding awards during the rest of 2013 and the remainder over the requisite service periods.  During April 2013 we granted additional cash-based LTI awards with a fair value of $21 million on the grant date that will be amortized on an accelerated basis over a three-year vesting period.

10. Investments in Unconsolidated Affiliates

We hold investments in two unconsolidated affiliates, Four Star Oil & Gas Company (Four Star) and Black Warrior Transmission Corporation, which we account for using the equity method of accounting. Our income statement reflects (i) our share of net earnings directly attributable to these unconsolidated affiliates, and (ii) other adjustments, such as the amortization of the excess of the carrying value of our investment relative to the underlying equity in the net assets of the entity. As of March 31, 2013 and December 31, 2012, our investment in unconsolidated affiliates was $220 million and $226 million, respectively. Included in these amounts was approximately $122 million and $125 million, respectively, related to the excess of the carrying value of our investment in Four Star relative to the underlying equity in its net assets.

Below is summarized financial information of the operating results of our unconsolidated affiliates.

	Successor		Predecessor
	Quarter ended March 31,		Quarter ended March 31,
	2013		2012
	(In millions)		(In millions)
Operating results:
Operating revenues	$	50	$	49
Operating expenses	34		37
Net income	9		7

We amortize 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 which are predominantly natural gas reserves. Amortization of our investment for the successor period related to the quarter ended March 31, 2013 was $3 million. Amortization for the predecessor period related to the quarter ended March 31, 2012 was $8 million.  Four Star’s underlying reserves and production are predominantly natural gas. Changes in natural gas prices impact the fair value of our investment in Four Star, and sustained declines in natural gas prices could cause the fair value of our investment to decline which could require us to record an impairment of the carrying value of our investment in the future if that loss is determined to be other than temporary.

We received dividends from Four Star for the successor period ended March 31, 2013 and for the predecessor period ended March 31, 2012 of approximately $8 million, respectively.

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11. Related Party Transactions

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 terminates 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 specified initial public offering transaction. Under the agreement, we pay a non-refundable annual management fee of $25 million. For the quarter ended March 31, 2013, we recognized approximately $6 million in general and administrative expense related to management fees.

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 March 31, 2013, we recorded approximately $21 million as capital expenditures for amounts 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 its cash management program.  Other than continuing transition services agreements with KMI, all these agreements ceased on the date of the Acquisition.  The following table shows revenues and charges to/from affiliates for the following predecessor period:

	Predecessor
	Quarter ended March 31,
	2012
	(In millions)
Operating revenues	$	113
Operating expenses	28

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 in our condensed consolidated financial statements presented herein.

15

EP ENERGY LLC

CONDENSED CONSOLIDATING STATEMENT OF INCOME

FOR QUARTER ENDED MARCH 31, 2013

(In millions)

	Successor
	Issuer			Guarantor Subsidiaries		Non- Guarantor Subsidiaries		Eliminations			Consolidated
Operating Revenues
Oil and condensate	$	—		$	271	$	9	$	—		$	280
Natural gas	—			141		18		—			159
NGL	—			19		—		—			19
Financial derivatives	(131		)	—		—		—			(131		)
Total operating revenues	(131		)	431		27		—			327
Operating Expenses
Transportation costs	—			29		—		—			29
Lease operating expense	—			55		9		—			64
General and administrative	13			48		2		—			63
Depreciation, depletion and amortization	—			146		3		—			149
Exploration expense	—			14		—		—			14
Taxes, other than income taxes	—			28		3		—			31
Total operating expenses	13			320		17		—			350
Operating (loss) income	(144		)	111		10		—			(23		)
Earnings from unconsolidated affiliates	—			2		—		—			2
Other income	—			1		—		—			1
Loss on extinguishment of debt	(1		)	—		—		—			(1		)
Interest expense	(84		)	—		—		—			(84		)
(Loss) income before income taxes	(229		)	114		10		—			(105		)
Income tax expense	—			—		1		—			1
(Loss) income before earnings from consolidated subsidiaries	(229		)	114		9		—			(106		)
Earnings from consolidated subsidiaries	123			9		—		(132		)	—
Net (loss) income	$	(106	)	$	123	$	9	$	(132	)	$	(106	)

16

EP ENERGY LLC

CONDENSED CONSOLIDATING STATEMENT OF INCOME

FOR QUARTER ENDED MARCH 31, 2012

(In millions)

	Predecessor
	Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Eliminations		Consolidated
Operating Revenues
Oil and condensate	$	198		$	11		$	—	$	209
Natural gas	160			22			—		182
NGL	17			—			—		17
Financial derivatives	76			—			—		76
Total operating revenues	451			33			—		484
Operating Expenses
Transportation costs	25			—			—		25
Lease operating expense	51			11			—		62
General and administrative	40			4			—		44
Depreciation, depletion and amortization	193			8			—		201
Ceiling test charge	—			62			—		62
Taxes, other than income taxes	24			4			—		28
Total operating expenses	333			89			—		422
Operating (loss) income	118			(56		)	—		62
Loss from unconsolidated affiliates	(3		)	—			—		(3		)
Other income	—			1			—		1
Interest expense
Third party	(5		)	1			—		(4		)
Affiliated	1			(1		)	—		—
Income (loss) before income taxes	111			(55		)	—		56
Income tax expense	40			1			—		41
Income (loss) before earnings from consolidated subsidiaries	71			(56		)	—		15
Earnings from consolidated subsidiaries	(56		)	—			56		—
Net income	$	15		$	(56	)	$	56	$	15
Cash flow hedging activities:
Reclassification adjustments (1)	2			—			—		2
Comprehensive income	$	17		$	(56	)	$	56	$	17

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

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EP ENERGY LLC

CONDENSED CONSOLIDATING BALANCE SHEET

AS OF MARCH 31, 2013

(In millions)

	Issuer		GuarantorSubsidiaries		Non- GuarantorSubsidiaries		Eliminations			Consolidated
ASSETS
Current assets
Cash and cash equivalents	$	15	$	49	$	7	$	—		$	71
Accounts receivable
Customer, net of allowance of less than $1	9		214		25		—			248
Other, net of allowance of $1	—		16		—		—			16
Materials and supplies	—		23		—		—			23
Derivative instruments	30		—		—		—			30
Prepaid assets	19		12		8		—			39
Other	—		—		1		—			1
Total current assets	73		314		41		—			428
Property, plant and equipment, at cost
Oil and natural gas properties	—		7,860		92		—			7,952
Other property, plant and equipment	—		108		1		—			109
	—		7,968		93		—			8,061
Less accumulated depreciation, depletion and amortization	—		415		9		—			424
Total property, plant and equipment, net	—		7,553		84		—			7,637
Other assets
Investments in unconsolidated affiliates	—		220		—		—			220
Investments in consolidated affiliates	7,267		42		—		(7,309		)	—
Derivative instruments	67		—		—		—			67
Notes receivable from consolidated affiliate	206		—		—		(206		)	—
Deferred income taxes	—		—		6		—			6
Unamortized debt issue cost	129		—		—		—			129
Other	—		7		5		—			12
	7,669		269		11		(7,515		)	434
Total assets	$	7,742	$	8,136	$	136	$	(7,515	)	$	8,499

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EP ENERGY LLC

CONDENSED CONSOLIDATING BALANCE SHEET

AS OF MARCH 31, 2013

(In millions)

	Issuer		GuarantorSubsidiaries		Non- GuarantorSubsidiaries		Eliminations			Consolidated
LIABILITIES AND EQUITY
Current liabilities
Accounts payable
Trade	$	1	$	127	$	—	$	—		$	128
Other	—		317		42		—			359
Derivative instruments	70		—		—		—			70
Accrued taxes other than income	—		23		7		—			30
Accrued interest	108		—		—		—			108
Accrued taxes	—		17		—		—			17
Asset retirement obligations	—		10		—		—			10
Other accrued liabilities	—		16		3		—			19
Total current liabilities	179		510		52		—			741
Long-term debt	4,556		—		—		—			4,556
Notes payable to unconsolidated affiliate	—		206		—		(206		)	—
Other long-term liabilities
Derivative instruments	21		—		—		—			21
Asset retirement obligations	—		147		36		—			183
Other	—		6		6		—			12
Total non-current liabilities	4,577		359		42		(206		)	4,772
Commitments and contingencies
Member’s equity	2,986		7,267		42		(7,309		)	2,986
Total liabilities and equity	$	7,742	$	8,136	$	136	$	(7,515	)	$	8,499

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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		194		26		—			226
Affiliates	—		3		—		(3		)	—
Other, net of allowance of $1	—		20		1		—			21
Materials and supplies	—		22		—		—			22
Derivative instruments	108		—		—		—			108
Prepaid assets	—		12		8		—			20
Other	—		—		4		—			4
Total current assets	114		300		53		(3		)	464
Property, plant and equipment, at cost
Oil and natural gas properties	—		7,441		92		—			7,533
Other property, plant and equipment	—		102		1		—			103
	—		7,543		93		—			7,636
Less accumulated depreciation, depletion and amortization	—		260		6		—			266
Total property, plant and equipment, net	—		7,283		87		—			7,370
Other assets
Investments in unconsolidated affiliates	—		226		—		—			226
Investments in consolidated affiliates	7,124		46		—		(7,170		)	—
Derivative instruments	88		—		—		—			88
Notes receivable from consolidated affiliate	45		—		—		(45		)	—
Deferred income taxes	—		—		6		—			6
Unamortized debt issue cost	134		—		—		—			134
Other	—		5		—		—			5
	7,391		277		6		(7,215		)	459
Total assets	$	7,505	$	7,860	$	146	$	(7,218	)	$	8,293

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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	$	—	$	126	$	—	$	—		$	126
Affiliates	—		—		3		(3		)	—
Other accrued liabilities	—		314		44		—			358
Derivative instruments	10		7		—		—			17
Accrued taxes other than income	—		15		8		—			23
Accrued interest	57		—		—		—			57
Accrued taxes	—		19		—		—			19
Asset retirement obligations	—		10		—		—			10
Other accrued liabilities	—		45		3		—			48
Total current liabilities	67		536		58		(3		)	658
Long-term debt	4,346		—		—		—			4,346
Notes payable to consolidated affiliate	—		45		—		(45		)	—
Other long-term liabilities
Derivative instruments	7		7		—		—			14
Asset retirement obligations	—		144		36		—			180
Other	—		4		6		—			10
Total non-current liabilities	4,353		200		42		(45		)	4,550
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

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EP ENERGY LLC

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS

FOR THE QUARTER ENDED MARCH 31, 2013

(In millions)

	Successor
	Issuer			GuarantorSubsidiaries			Non- GuarantorSubsidiaries			Eliminations			Consolidated
Cash flows from operating activities
Net (loss) income	$	(106	)	$	123		$	9		$	(132	)	$	(106	)
Adjustments to reconcile net (loss) income to net cash from operating activities
Depreciation, depletion and amortization	—			146			3			—			149
Earnings from unconsolidated affiliates, adjusted for cash distributions	—			6			—			—			6
Earnings from consolidated affiliates	(123		)	(9		)	—			132			—
Loss on extinguishment of debt	1			—			—			—			1
Amortization of equity compensation expense	7			—			—			—			7
Non-cash portion of exploration expense	—			12			—			—			12
Amortization of debt issuance cost	5			—			—			—			5
Equity distributions from consolidated affiliate	—			15			—			(15		)	—
Asset and liability changes
Accounts receivable	(4		)	(13		)	2			(3		)	(18		)
Accounts payable	1			15			(3		)	3			16
Derivative instruments	158			1			—			—			159
Accrued interest	52			—			—			—			52
Other asset changes	(18		)	(5		)	(1		)	—			(24		)
Other liability changes	—			(24		)	(1		)	—			(25		)
Net cash (used in) provided by operating activities	(27		)	267			9			(15		)	234
Cash flows from investing activities
Capital expenditures	(5		)	(438		)	(1		)	—			(444		)
Net proceeds from the sale of assets	—			10			—			—			10
Change in note receivable with affiliate	(161		)	—			—			161			—
Net cash (used in) provided by investing activities	(166		)	(428		)	(1		)	161			(434		)
Cash flows from financing activities
Proceeds from long term debt	390			—			—			—			390
Repayment of long term debt	(180		)	—			—			—			(180		)
Dividends to affiliate	—			—			(15		)	15			—
Change in note payable with affiliate	—			161			—			(161		)	—
Debt issuance costs	(2		)	—			—			—			(2		)
Net cash (used in) provided by financing activities	208			161			(15		)	(146		)	208
Change in cash and cash equivalents	15			—			(7		)	—			8
Cash and cash equivalents
Beginning of period	—			49			14			—			63
End of period	$	15		$	49		$	7		$	—		$	71

22

EP ENERGY LLC

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS

FOR THE QUARTER ENDED MARCH 31, 2012

(In millions)

	Predecessor
	GuarantorSubsidiaries			Non- GuarantorSubsidiaries			Eliminations			Consolidated
Cash flows from operating activities
Net income (loss)	$	15		$	(56	)	$	56		$	15
Adjustments to reconcile net (loss) income to net cash from operating activities
Depreciation, depletion and amortization	193			8			—			201
Deferred income tax expense	41			—			—			41
Loss from unconsolidated affiliates, adjusted for cash distributions	11			—			—			11
Earnings from consolidated affiliates	56			—			(56		)	—
Ceiling test charges	—			62			—			62
(Loss) gain on long lived assets	(1		)	1			—			—
Asset and liability changes
Accounts receivable	37			(12		)	—			25
Accounts payable	(19		)	—			—			(19		)
Derivative instruments	6			—			—			6
Other asset changes	(3		)	—			—			(3		)
Other liability changes	(2		)	—			—			(2		)
Net cash provided by operating activities	334			3			—			337
Cash flows from investing activities
Capital expenditures	(404		)	(6		)	—			(410		)
Net proceeds from the sale of assets	5			—			—			5
Cash paid for acquisitions, net of cash acquired	(1		)	—			—			(1		)
Change in note receivable with affiliate	(2		)	—			2			—
Net cash (used in) provided by investing activities	(402		)	(6		)	2			(406		)
Cash flows from financing activities
Proceeds from long term debt	175			—			—			175
Repayment of long term debt	(65		)	—			—			(65		)
Change in note payable with affiliate	—			2			(2		)	—
Net cash provided by (used in) financing activities	110			2			(2		)	110
Change in cash and cash equivalents	42			(1		)	—			41
Cash and cash equivalents
Beginning of period	6			19			—			25
End of period	$	48		$	18		$	—		$	66

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Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

Our Management’s Discussion and Analysis of Financial Condition and Results of Operations (“MD&A”) should be read in conjunction with the financial statements and the accompanying notes presented in Item 1 of Part I of this Quarterly Report on Form 10-Q. This discussion contains forward-looking statements and involves numerous risks and uncertainties, including, but not limited to, those described in the “Risk Factors” section of our 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 period  includes the application of the acquisition method of accounting and the application of the successful efforts method of accounting for oil and natural gas properties. As a result, trends and results in future periods may be different than those that existed prior to the Acquisition and under the full cost method of accounting. 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 (the Issuer) and EP Energy Global LLC (the “Predecessor” for accounting purposes), and each of its consolidated subsidiaries.

Our Business

Overview.  We are an independent oil and natural gas producer engaged in the exploration for and the acquisition, development and production of oil, natural gas and NGL primarily in the United States.  We have a large and diverse base of producing assets that provides cash flow to fund the development of our key programs, which at this time are primarily oil-focused. We allocate capital based on financial returns and value creation of the various assets in our portfolio.  Over the last several years, we have high-graded our future drilling inventory and reduced our development costs by establishing large acreage positions in areas with repeatable drilling opportunities and more favorable return characteristics. As a result, we have a strategic presence in well-known oil resource areas including the Eagle Ford Shale, the Wolfcamp Shale and the Altamont Field. Our diverse producing natural gas assets also include our Haynesville Shale position, substantially all of which is held by production, which gives us a significant presence in unconventional natural gas. We also have acreage in the South Louisiana Wilcox area, CBM assets in the Raton Basin of northern New Mexico and Southern Colorado, the Black Warrior Basin in Alabama and Arkoma in Oklahoma and a small international presence in Brazil.

We operate primarily through three domestic divisions: Eagle Ford, Southern and Central. Our Eagle Ford division operations are in south Texas.  The Southern division is located along the Gulf Coast as well as the south and west areas of Texas, including the Wolfcamp Shale.  Our Central division includes operations in east Texas, Louisiana, Alabama, eastern Oklahoma, in the Uintah Basin in Utah and the Raton Basin located in New Mexico and Colorado.

In our effort to increase the value of our portfolio, generate higher oil production growth, expand unit margin and financial returns, we have initiated a marketing process that may result in the sale of a number of our natural gas properties, including our CBM properties (Raton, Arkoma and Black Warrior Basin), the majority of our Arklatex natural gas properties and our natural gas properties in south Texas. Should we successfully complete these sales, our remaining portfolio and key oil programs will primarily consist of the Eagle Ford Shale in south Texas, the Wolfcamp Shale in the Permian Basin of west Texas, the Altamont Field in Utah, our South Louisiana Wilcox acreage and our key natural gas program will consist of Haynesville Shale acreage in northwest Louisiana and east Texas.

Below is a description and/or update of each of our key programs:

·Eagle Ford Shale. The Eagle Ford Shale provides the highest economic returns in our portfolio. We currently are running six rigs.

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

·Altamont Field.  In the Altamont Field, we are gaining operational efficiencies as we develop the field. We currently are running two rigs. Most of our acreage in this area is held by production.

·Haynesville Shale.  The Haynesville Shale remains a key 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.

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We evaluate acquisition and growth opportunities that are aligned with our core competencies and areas of competitive advantage. Strategic acquisitions can provide us with opportunities to achieve our long-term goals by leveraging existing expertise in our key operating areas, balancing our exposure to regions, basins and commodities, helping us to achieve risk-adjusted returns competitive with those available within our existing drilling programs and by increasing our reserves.

Factors Influencing Our Profitability.  The profitability of our exploration and production operations is dependent on the prices for oil and natural gas, the costs to explore, develop, and produce 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 oil and natural gas proved reserve base and production volumes through the successful execution of our drilling programs or through strategic 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, the impact of potential divestitures and the use of proceeds therefrom, the impacts of volatility in the financial and commodity markets, industry-wide changes in the cost of drilling and oilfield services which impact our daily production, operating and capital costs and our debt level and related interest costs. Additionally, we may be impacted by hurricanes and other 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 quarter ended March 31, 2013, approximately 96 percent of our liquids production and 86 percent of our natural gas production were hedged and settled at average floor prices of $99.52 per barrel and $3.55 per MMBtu, respectively. The following table reflects the contracted volumes and the minimum, maximum and average prices we will receive under derivative contracts we held as of March 31, 2013.

	2013			2014			2015
	Volumes(1)	Average Price(1)		Volumes(1)	Average Price(1)		Volumes(1)	Average Price(1)
Oil
Fixed Price Swaps(2)	12,494	$	100.16	9,746	$	98.13	5,501	$	95.42
Ceilings	1,224	$	98.13	1,095	$	100.00	1,095	$	100.00
Three Way Collars Ceiling(2)	—	$	—	2,920	$	103.76	—	—
Three Way Collars Floors(2)	—	$	—	2,920	$	95.00	—	—
Basis Swaps(3)	3,857	$	Various	4,380	$	Various	3,650	Various
Natural Gas
Fixed Price Swaps	127	$	3.59	105	$	4.03	33	$	4.23
Ceilings	3	$	3.65	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)	In March 2013, we unwound 2013 crude oil collars on 4,675 MBbls at an average ceiling price of $106.08 and an average floor price of $92.72 and replaced them with crude oil swaps on 4,675 MBbls at an average price of $95.74. On these 4,675 MBbls, if market prices settle at or below $71.47, we will receive a “locked-in” cash settlement of the market price plus $24.27 per Bbl. For our 2014 three-way collars-floors, 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.
(3)	We use various types of oil basis swaps to lock-in certain crude oil differentials.

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Summary of Liquidity and Capital Resources.  As of March 31, 2013, we have available liquidity, including existing cash, of $2.25 billion.  During March 2013, our RBL Facility borrowing base increased from $1.8 billion to $2.5 billion as a result of a semi-annual redetermination based on the value of our oil and natural gas reserves. We believe we have sufficient liquidity for 2013 from our cash flows from operations, combined with availability under the 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.

Capital Expenditures.  Our capital expenditures for the quarter ended March 31, 2013 and rig count by key program as of March 31, 2013 were:

	Capital Expenditures (In millions)		Rig Count
Eagle Ford	$	271	6
Wolfcamp	104		3
Altamont	49		3
Haynesville	1		—
Other, including International	8		—
Total capital expenditures	$	433	12

Outlook for 2013. For the full year 2013, excluding the impact of potential divestitures, we expect the following:

·Capital expenditures, excluding acquisitions, of approximately $1.7 - $1.8 billion, focused entirely on high return oil programs.

·Average daily production volumes for the year of approximately 125 MBoe/d to 135 MBoe/d.

·Per unit adjusted cash operating costs for the year of approximately $11.50 to $13.25 per Boe, before transportation costs of $2.85 to $ 3.15 per Boe.

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Production Volumes and Drilling Summary

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

	2013	2012
United States (MBoe/d)
Eagle Ford	31	14
Southern(1)	12	21
Central	77	101
International (MBoe/d)
Brazil	5	6
Total Consolidated	125	142
Unconsolidated affiliate (MBoe/d)	9	9
Total Combined (MBoe/d)	134	151
Oil and condensate (MBbls/d)
Consolidated volumes	32	22
Unconsolidated affiliate volumes	1	1
Total Combined	33	23
Natural Gas (MMcf/d)
Consolidated volumes	520	688
Unconsolidated affiliate volumes	41	43
Total Combined	561	731
NGL (MBbls/d)
Consolidated volumes	7	5
Unconsolidated affiliate volumes	1	1
Total Combined (MBbls/d)	8	6

(1)      2012 production includes 8 MBoe/d from the Gulf of Mexico assets sold in July of 2012.

·Eagle Ford division—Our 2013 Eagle Ford division equivalent volumes increased 17 MBoe/d for the quarter ended March 31, 2013 compared to the quarter ended March 31, 2012 due to the success of our drilling program in the area. Eagle Ford oil production increased by 11 MBbls/d or 108 percent compared with the quarter ended March 31, 2012.  Combined Eagle Ford oil and NGL production increased in the first quarter of 2013 to approximately 25 MBbls/d compared with approximately 22 MBbls/d for the quarter ended December 31, 2012. During the quarter ended March 31, 2013, we drilled 30 additional wells in our Eagle Ford area and had a total of 167 net operated wells as of March 31, 2013. With a majority of our acreage located in the oil and liquids rich area of the Eagle Ford Shale, we continue to grow our oil and NGL production in the area.

·Southern division—Our 2013 Southern division volumes decreased 9 MBoe/d or 41 percent for the quarter ended March 31, 2013 compared to the quarter ended March 31, 2012 primarily due to the sale of our Gulf of Mexico assets in July 2012.  Production volumes from the Gulf of Mexico assets were 8 MBoe/d for the first quarter of 2012. We continue to progress the development of our Wolfcamp Shale drilling program where we drilled six additional wells during the first quarter of 2013, for a total of 37 net operated wells as of March 31, 2013.

·Central division—Our 2013 Central division volumes decreased 24 MBoe/d or 24 percent for the quarter ended March 31, 2013 compared to the quarter ended March 31, 2012. The production decrease in the Central division is related to declines in our natural gas focused Central division properties. The Altamont Field produced an average of 8 MBbls/d of oil during the quarter ended March 31, 2013, and we drilled an additional seven operated oil wells at Altamont for a total of 314 net operated wells. As of March 31, 2013 we had 100 net operated wells in the Haynesville Shale, and our total production for the quarter ended March 31, 2013 was approximately 204 MMcf/d.  At the end of the first quarter of 2012, we suspended our drilling program in the Haynesville Shale due to low natural gas prices.

·International—The 2013 production volumes related to our Brazil operations were 5 MBoe/d. We are still awaiting a response on our appeal filed in 2011 for our environmental permit request concerning the Pinauna Field which was denied by the Brazilian environmental regulatory agency in 2011.

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Results of Operations

The information in the table below provides GAAP financial results for each of the successor and predecessor periods presented (in millions).

	Successor			Predecessor
	Quarter ended  March 31,			Quarter ended March 31,
	2013			2012
Operating revenues:
Oil and condensate	$	280		$	209
Natural gas	159			182
NGL	19			17
Total physical sales	458			408
Financial derivatives	(131		)	76
Total operating revenues	327			484
Operating expenses
Transportation costs	29			25
Lease operating expense	64			62
General and administrative	63			44
Depreciation, depletion and amortization	149			201
Ceiling test charges	—			62
Exploration expense	14			—
Taxes, other than income taxes	31			28
Total operating expenses	350			422
Operating (loss) income	(23		)	62
Earnings (loss) from unconsolidated affiliates	2			(3		)
Other income	1			1
Loss on extinguishment of debt	(1		)	—
Interest expense	(84		)	(4		)
(Loss) income before income taxes	(105		)	56
Income tax expense	1			41
Net (loss) income	$	(106	)	$	15

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Operating Revenues.

The table below provides our period-over-period operating revenues, volumes and prices per unit. 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. Our average realized prices, including financial derivative settlements and premiums, reflect cash received and/or paid during the period on settled financial derivatives based on the period the contracted settlements were originally scheduled to occur:

	Successor			Predecessor
	Quarter endedMarch 31,			Quarter ended March 31,
	2013			2012		% Change
	(In millions, except for percentages)
Operating revenues
Oil and condensate	$	280		$	209	34	%
Natural gas	159			182		(13	)%
NGL	19			17		12	%
Total physical sales	458			408		12	%
Financial derivatives	(131		)	76		(272	)%
Total operating revenues	$	327		$	484	(32	)%
Volumes:
Oil and condensate
Consolidated volumes (MBbls)	2,907			2,052		42	%
Unconsolidated affiliate volumes (MBbls)	68			77		(12	)%
Natural gas
Consolidated volumes (MMcf)	46,781			62,629		(25	)%
Unconsolidated affiliate volumes (MMcf)	3,679			3,947		(7	)%
NGL
Consolidated volumes (MBbls)	598			420		42	%
Unconsolidated affiliate volumes (MBbls)	112			123		(9	)%
Equivalent volumes
Consolidated MBoe	11,301			12,911		(12	)%
Unconsolidated affiliate MBoe	794			858		(7	)%
Total combined MBoe	12,095			13,769		(12	)%
Consolidated MBoe/d	125			142		(12	)%
Unconsolidated affiliate MBoe/d	9			9		—	%
Total Combined MBoe/d	134			151		(11	)%
Consolidated prices per unit:
Oil and condensate
Average realized price on physical sales ($/Bbl)	$	96.43		$	101.81	(5	)%
Average realized price, including financial derivatives($/Bbl)(1)	$	103.20		$	100.16	3	%
Natural gas
Average realized price on physical sales ($/Mcf)	$	3.40		$	2.90	17	%
Average realized price, including financial derivatives($/Mcf)(1)	$	3.57		$	4.27	(16	)%
NGL
Average realized price on physical sales ($/Bbl)	$	31.78		$	40.96	(22	)%

(1)The quarter ended March 31, 2013 includes cash settlements received of approximately $13 million and cash premiums received of approximately $7 million, related to crude oil derivative contracts, as well as cash settlements received of approximately $7 million and cash premiums received of approximately $1 million related to natural gas derivative contracts. The quarter ended March 31, 2012 includes cash settlements paid of approximately $4 million related to oil derivative contracts, as well as cash settlements received of approximately $86 million related to natural gas derivative contracts.

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Physical sales.  Physical sales represent accrual-based commodity sales transactions with customers. For the quarter ended March 31, 2013, physical sales increased by $50 million or 12 percent compared to the quarter ended March 31, 2012. The table below displays the price and volume variances on our physical sales when comparing the quarter ended March 31, 2013 to the quarter ended March 31, 2012.

	Physical Sales
	Oil and condensate			Natural gas			NGL			Total
March 31, 2012 sales	$	209		$	182		$	17		$	408
Change due to prices	(16		)	23			(5		)	2
Change due to volumes	87			(46		)	7			48
March 31, 2013 sales	$	280		$	159		$	19		$	458

Oil and condensate sales increased by $71 million or 34 percent for the quarter ended March 31, 2013 compared to 2012 due primarily to oil volume growth from our Eagle Ford drilling program where production increased by 11 MBbls/d or 108 percent compared with the quarter ended March 31, 2012. Natural gas sales decreased by $23 million or 13 percent for the quarter ended March 31, 2013 compared with the same period in 2012 due primarily to natural production declines and an impact of 8 MBoe/d from the divestiture of our Gulf of Mexico assets in mid-2012. NGL sales increased by $2 million or 12 percent for the quarter ended March 31, 2013 compared with the same period in 2012 primarily attributable to our Eagle Ford drilling program where NGL volumes increased by 3 MBbls/d or approximately 190 percent compared with the quarter ended March 31, 2012.

As of March 31, 2013, the NYMEX spot price of a barrel of oil was $97.23 versus the spot NYMEX price of natural gas of $4.02, or a ratio of 24 to 1. We will continue to target increases in our oil volumes in 2013 due to the value of oil in relation to the value of natural gas, 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 with sustained current prices of oil.

Realized and unrealized gains or losses on financial derivatives.  We record realized and unrealized gains or losses due to changes in the fair value of our derivative contracts based on forward commodity prices relative to the prices in the underlying contracts. During the first quarter of 2013, we recorded $131 million of derivative losses compared to gains of $76 million in 2012. In 2013, unrealized losses were $159 million and realized gains were $28 million compared to $6 million of unrealized losses and $82 million of realized gains in 2012.

Operating Expenses

Summary.  The table below displays the components of our operating expenses, our average cash operating costs per barrel of equivalent unit and adjusted cash operating costs per barrel of equivalent unit, each of which are discussed further below:

	Successor		Predecessor
	Quarter ended  March 31,		Quarter ended  March 31,
	2013		2012
	(In millions)
Transportation costs	$	29	$	25
Lease operating expense	64		62
General and administrative	63		44
Depreciation, depletion and amortization	149		201
Ceiling test charges	—		62
Exploration expense	14		—
Taxes, other than income taxes	31		28
Total operating expenses	$	350	$	422
Cash operating costs per unit ($/Boe)(1)	$	14.03	$	10.42
Adjusted cash operating costs per unit ($/Boe)(1)	$	12.09	$	10.16

(1)See Cash Operating Costs and Adjusted Cash Operating Costs for a reconciliation to operating expenses.

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Transportation costs.  Transportation costs for the quarter ended March 31, 2013 increased $4 million compared to the same period in 2012 mainly due to oil transportation costs associated with our Eagle Ford division in response to growth in that area. Our average transportation costs per unit for the quarters ended March 31 were:

	2013		2012
Average transportation costs
Oil and condensate ($/Bbl)	$	1.93	$	1.11
Natural gas ($/Mcf)	$	0.44	$	0.33
NGL ($/Bbl)	$	4.62	$	5.47

General and administrative expenses.  General and administrative expenses for the quarter ended March 31, 2013 increased $19 million compared to the quarter ended March 31, 2012. The increase is primarily due to a $10 million increase in compensation expense associated with the long-term incentive programs put in place in conjunction with the Acquisition, transition and restructuring costs of $3 million incurred in the first quarter of 2013, and advisory fees of $6 million incurred in the first quarter of 2013 pursuant to our private equity sponsor management agreement.  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.  For the quarter ended March 31, 2013 depreciation, depletion and amortization expense decreased $52 million compared to the quarter ended March 31, 2012 due to an average lower depletion rate following the application of the successful efforts method of accounting for oil and natural gas properties and lower total equivalent production volumes. Due to the ongoing development of higher cost liquids programs, we expect our depletion rate will increase in future periods compared to our current levels. Our average depreciation, depletion and amortization costs per unit for the quarters ended March 31 were:

	2013		2012
Depreciation, depletion and amortization ($/Boe)(1)	$	13.21	$	15.55

(1)Includes $0.28 per Boe and $0.25 per Boe for the quarters ended March 31, 2013 and 2012 related to accretion expense on asset retirement obligations.

Exploration expense.  For the quarter ended March 31, 2013 we recorded $14 million of exploration expense as a 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 is $12 million of amortization of unproved property costs.

Ceiling test charges.  Prior to the Acquisition, 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 first quarter of 2012 we recorded a non-cash ceiling test charge 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.

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 a triggering event to determine if impairment of such properties is necessary.  During the first quarter of 2013, no impairments to our oil and natural gas properties were recorded.  Forward commodity prices can play a significant role in determining impairments. Due to the current forecast of future natural gas prices and 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.

Taxes, other than income taxes.  Taxes, other than income taxes, for the quarter ended March 31, 2013 increased $3 million compared to March 31, 2012 primarily due to higher ad valorem taxes associated with property values from activity in our oil producing areas.

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Cash Operating Costs and Adjusted Cash Operating Costs.  We monitor cash operating costs required to produce our oil and natural gas. Cash operating costs is a non-GAAP measure calculated on a per Boe basis and includes total operating expenses less depreciation, depletion and amortization expense, transportation costs, exploration expense, impairments and ceiling test charges and other expenses. Adjusted cash operating costs is a non-GAAP measure and is defined as cash operating costs less transition and restructuring costs and non-cash 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 table below represents a reconciliation of our cash operating costs and adjusted cash operating costs to operating expenses for the quarters ended March 31:

	Successor						Predecessor
	Quarters ended March 31,
	2013						2012
	Total			Per Unit (1)			Total			Per Unit (1)
	(In millions, except per unit costs)
Total operating expenses	$	350		$	30.96		$	422		$	32.71
Depreciation, depletion and amortization	(149		)	(13.21		)	(201		)	(15.55		)
Transportation costs	(29		)	(2.55		)	(25		)	(1.98		)
Exploration expense	(14		)	(1.21		)	—			—
Ceiling test charges	—			—			(62		)	(4.76		)
Other	1			0.04			—			—
Total cash operating costs and per-unit cash costs	159			14.03			134			10.42
Transition/restructuring costs and non-cash compensation expense (2)	(22		)	(1.94		)	(3		)	(0.26		)
Total adjusted cash operating costs and adjusted per-unit cash costs(2)	$	137		$	12.09		$	131		$	10.16
Total equivalent volumes (MBoe)(3)	11,301						12,911

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

(2)    Includes transition and severance costs of $3 million, $6 million of advisory fees paid to Sponsors, and $13 million of non-cash compensation expense for the quarter ended March 31, 2013.  For the quarter ended March 31, 2012 we incurred $3 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:

	Quarters Ended March 31,
	2013			2012
Cash operating costs ($/Boe)
Average lease operating expenses	$	5.68		$	4.83
Average production taxes(1)	2.56			1.92
Average general and administrative expenses	5.57			3.42
Average taxes, other than production and income taxes	0.22			0.25
Total cash operating costs	$	14.03		$	10.42
Transition/restructuring costs and non-cash compensation expense	$	(1.94	)	$	(0.26	)
Total adjusted cash operating costs	$	12.09		$	10.16

(1)       Production taxes include ad valorem and severance taxes which increased in first quarter 2013  primarily due to higher ad valorem taxes associated with our oil producing areas.

Other Income Statement Items.

Interest expense. Interest expense for the quarter ended March 31, 2013 increased $80 million compared to March 31, 2012 primarily due to the issuance of approximately $4.25 billion of debt related to the Acquisition in 2012.

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Commitments and Contingencies

For a further discussion of our commitments and contingencies, see 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 working capital requirements, debt service requirements and capital expenditures. In March 2013, we completed our first semi-annual redetermination increasing the borrowing base of our RBL from $1.8 billion to $2.5 billion. As of March 31, 2013, our available liquidity was approximately $2.25 billion, including approximately $2.18 billion of additional borrowing capacity available under the RBL Facility.

As of March 31, 2013, our long-term debt is approximately $4.56 billion, comprised of $3.1 billion in senior notes due in 2019, 2020 and 2022, $1.15 billion in senior secured term loans with maturity dates in 2018 and 2019, and $315 million outstanding under the RBL Facility expiring in 2017.  Based on our debt levels, we are, and will continue to be, highly leveraged and therefore expect that our interest costs will continue to be higher compared to what we have experienced prior to the Acquisition. We evaluate opportunities where favorable debt markets allow for us to reduce our interest cost.  In May 2013, we anticipate closing the repricing of our $750 million term loan due 2018 which will reduce the specified margin over LIBOR from 4.00% to 2.75%, and reduce the minimum LIBOR floor of from 1.00 % to 0.75% over the remaining life of the term loan. For additional details on our long-term debt, see Part I Item 1, Note 7.

In April 2013, we initiated a marketing process that may result in the sale of a number of our natural gas properties, including our CBM properties (Raton, Arkoma and Black Warrior Basin), the majority of our Arklatex natural gas properties and our natural gas properties in south Texas. Should these sales be completed, we expect to experience lower cash flow from operations in 2013 than originally planned but expect to use the proceeds from the sales, among other potential uses, to enhance our balance sheet and/or invest in our key oil programs to generate higher oil production growth and expand financial returns.

We believe we have sufficient liquidity for 2013 from our cash flows from operations, combined with availability under the RBL Facility and available cash to fund our current obligations, projected working capital requirements and 2013 capital plan of approximately $1.7 - $1.8 billion.  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.  To the extent possible, we have attempted to mitigate certain of these risks (e.g. by entering into oil and natural gas derivative contracts to reduce the financial impact of downward commodity price movements on a substantial portion of our anticipated production), but 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 quarters ended March 31, our cash flows from operations are summarized as follows (in millions):

	Successor			Predecessor
	Quarter ended March 31,			Quarter ended March 31,
	2013			2012
Cash Flow from Operations
Operating activities
Net (loss) income	$	(106	)	$	15
Ceiling test charges	—			62
Other income adjustments	180			253
Change in other assets and liabilities	160			7
Total cash flow from operations	$	234		$	337
Other Cash Inflows
Investing activities
Net proceeds from the sale of assets	10			5
Financing activities
Proceeds from long term debt	390			175
Total cash inflows	$	400		$	180
Cash Outflows
Investing activities
Capital expenditures	$	(444	)	$	(410	)
Cash paid for acquisitions	—			(1		)
	$	(444	)	$	(411	)
Financing activities
Repayment of long term debt	(180		)	(65		)
Debt issuance costs	(2		)	—
	(182		)	(65		)
Total cash outflows	$	(626	)	$	(476	)
Net change in cash and cash equivalents	$	8		$	41

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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 March 31, 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)	$	8	$	(401	)	$	(409	)	$	405	$	397

			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)	$	8	$	7	$	(1	)	$	9	$	1
Credit rate(3)	$	8	$	8	$	—		$	8	$	—

(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.

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Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

As of March 31, 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 March 31, 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 quarter of 2013 that materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

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

None.

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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: May 9, 2013	/s/Dane E. Whitehead
	Dane E. Whitehead
	Executive Vice President and Chief Financial Officer
	(Principal Financial Officer)
Date: May 9, 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	Second Amendment, dated as of March 27, 2013, to the Credit Agreement, dated as of May 24, 2012, among EPE Holdings LLC, EP Energy LLC, the lenders party thereto and JPMorgan Chase Bank, N.A., as administrative agent and collateral agent.
*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.

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