UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K

(Mark One)

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

For the fiscal year ended December 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	(I.R.S. Employer
Incorporation or Organization)	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

Securities registered pursuant to Section 12(b) of the Act:  None

Securities registered pursuant to Section 12(g) of the Act:  None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.  Yes o No x.

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.  Yes x No o.

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 if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. x

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. (Check one):

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

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

EP ENERGY LLC MEETS THE CONDITIONS OF GENERAL INSTRUCTION I(1)(a) AND (b) TO FORM 10-K AND IS THEREFORE FILING THIS REPORT WITH A REDUCED DISCLOSURE FORMAT AS PERMITTED BY SUCH INSTRUCTION.

Documents Incorporated by Reference:  None

EP ENERGY LLC

TABLE OF CONTENTS

Caption	Page
PART I
Item 1. Business	1
Item 1A. Risk Factors	3
Item 1B. Unresolved Staff Comments	22
Item 2. Properties	22
Item 3. Legal Proceedings	22
Item 4. Mine Safety Disclosures	22
PART II
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	23
Item 6. Selected Financial Data	23
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations	25
Item 7A. Quantitative and Qualitative Disclosures About Market Risk	45
Item 8. Financial Statements and Supplementary Data	47
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	98
Item 9A. Controls and Procedures	98
Item 9B. Other Information	98
PART III
Item 10. Directors, Executive Officers and Corporate Governance	*
Item 11. Executive Compensation	*
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	*
Item 13. Certain Relationships and Related Transactions, and Director Independence	*
Item 14. Principal Accountant Fees and Services	99
PART IV
Item 15. Exhibits and Financial Statement Schedules	100
Signatures	101

*We have not included a response to this item in this document since no response is required pursuant to the reduced disclosure format permitted by General Instruction I to Form 10-K.

i

Below is a list of terms that are common to our industry and used throughout this document:

/d	=	per day
Bbl	=	Barrel
Bcf	=	billion cubic feet
Bcfe	=	billion cubic feet of natural gas equivalents
Boe	=	barrel of oil equivalent
CBM	=	coal bed methane
Gal	=	gallons
LNG	=	liquified natural gas
MBoe	=	thousand barrels of oil equivalent
MBbls	=	thousand barrels
Mcf	=	thousand cubic feet
Mcfe	=	thousand cubic feet of natural gas equivalents
MMGal	=	million gallons
MMBtu	=	million British thermal units
MMBoe	=	million barrels of oil equivalent
MMBbls	=	million barrels
MMcf	=	million cubic feet
MMcfe	=	million cubic feet of natural gas equivalents
NGLs	=	natural gas liquids
TBtu	=	trillion British thermal units

When we refer to oil and natural gas in “equivalents,” we are doing so to compare quantities of oil with quantities of natural gas or to express these different commodities in a common unit. In calculating equivalents, we use a generally recognized standard in which one Bbl of oil and/or NGLs is equal to six Mcf of natural gas. Also, when we refer to cubic feet measurements, all measurements are at a pressure of 14.73 pounds per square inch.

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

ii

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

This report contains forward-looking statements that involve risks and uncertainties, many of which are beyond our control. These forward-looking statements are based on assumptions or beliefs that we believe to be reasonable; however, assumed facts almost always vary from the actual results and such variances can be material. Where we express an expectation or belief as to future results, that expectation or belief is expressed in good faith and is believed to have a reasonable basis. We cannot assure you, however, that the stated expectation or belief will occur. The words “believe,” “expect,” “estimate,” “anticipate,” “intend” and “should” and similar expressions will generally identify forward-looking statements. All of our forward-looking statements are expressly qualified by these and the other cautionary statements in this Annual Report, including those set forth in Item 1A, Risk Factors. Important factors that could cause our actual results to differ materially from the expectations reflected in our forward-looking statements include, among others:

·the supply and demand for oil, natural gas and NGLs;

·our ability to meet production volume targets;

·the uncertainty of estimating proved reserves and unproved resources;

·the future level of service and capital costs;

·the availability and cost of financing to fund future exploration and production operations;

·the success of drilling programs with regard to proved undeveloped reserves and unproved resources;

·our ability to comply with the covenants in various financing documents;

·our ability to obtain necessary governmental approvals for proposed exploration and production projects and to successfully construct and operate such projects;

·actions by credit rating agencies;

·credit and performance risk of our lenders, trading counterparties, customers, vendors and suppliers;

·changes in commodity prices and basis differentials for oil and natural gas;

·general economic and weather conditions in geographic regions or markets we serve, or where operations are located, including the risk of a global recession and negative impact on demand for oil and/or natural gas;

·the uncertainties associated with governmental regulation, including any potential changes in federal and state tax laws and regulations;

·political and currency risks associated with our international operations;

·competition; and

·the other factors described under Item 1A, “Risk Factors,” on pages 3 through 21 of this Annual Report on Form 10-K, and any updates to those factors set forth in our subsequent Quarterly Reports on Form 10-Q or Current Report on Form 8-K.

In light of these risks, uncertainties and assumptions, the events anticipated by these forward-looking statements may not occur, and, if any of such events do occur, we may not have anticipated the timing of their occurrence or the extent of their impact on our actual results.  Accordingly, you should not place any undue reliance on any of these forward-looking statements.  These forward-looking statements speak only as of the date made, and we undertake no obligation, other than as required by applicable law, to update or revise its forward-looking statements, whether as a result of new information, subsequent events, anticipated or unanticipated circumstances or otherwise.

EXPLANATORY NOTE

EP Energy LLC is a wholly-owned subsidiary of EP Energy Corporation (NYSE: EPE), which is a reporting company under the Securities and Exchange Act of 1934, as amended, Pursuant to General Instruction I of Form 10-K, EP Energy LLC has elected to furnish abbreviated disclosure in this Annual Report as set forth in such Instruction.

iii

PART I

ITEM 1.BUSINESS

EP Energy LLC (EP Energy) is a Delaware limited liability company formed on March 23, 2012.  On May 24, 2012, Apollo Global Management LLC (together with its subsidiaries, Apollo) and other private equity investors (collectively, the Sponsors) acquired EP Energy Global LLC (formerly known as EP Energy Corporation and then EP Energy, L.L.C. after its conversion into a Delaware limited liability company) and its subsidiaries for approximately $7.2 billion in cash as contemplated by the merger agreement among El Paso Corporation (El Paso) and Kinder Morgan, Inc. (KMI).  Hereinafter, the acquisition of EP Energy Global LLC is referred to as the “Acquisition” with EP Energy LLC referred to as the successor and the acquired entities referred to as the predecessor for financial accounting and reporting purposes.

We are engaged in the acquisition and development of unconventional onshore oil and natural gas properties in the United States.  We operate through a large and diverse base of producing assets located predominantly in four core areas: the Eagle Ford Shale (South Texas), the Wolfcamp Shale (Permian Basin in West Texas), the Altamont field in the Uinta Basin in northeastern Utah and the Haynesville Shale (North Louisiana). We also operate in other non-core areas primarily in Texas and Louisiana.  In our core areas, we have identified approximately 5,170 drilling locations (including 968 drilling locations to which we have attributed proved undeveloped reserves as of December 31, 2013), of which approximately 97% are oil wells. At current activity levels, this represents approximately 23 years of drilling inventory. As of December 31, 2013, we had proved reserves of 547.5 MMBoe (54% oil and 67% liquids) and for the three months ended December 31, 2013, we had average net daily production of 87,304 Boe/d (49% oil and 58% liquids).

Each of our core areas is characterized by a favorable operating environment, a long-lived reserve base and high drilling success rates. We have established significant contiguous leasehold positions in each area, representing approximately 440,000 net (613,000 gross) acres in total. Beginning in 2012, our capital programs have focused predominantly on the Eagle Ford Shale, the Wolfcamp Shale and Altamont, three of the premier unconventional oil plays in the United States, resulting in oil reserve and continuing production growth of 15% and 55%, respectively, from December 31, 2012 to December 31, 2013.

During 2013, we divested non-core domestic natural gas assets and an equity investment for a total consideration of approximately $1.5 billion. We also entered into a Quota Purchase Agreement relating to the sale of our Brazil operations, which is expected to close in 2014.  All periods present our Brazil operations as discontinued operations, and accordingly its operations are excluded from the discussion in this section.  Periods after the Acquisition in May 2012, referred to as successor periods also present domestic natural gas assets sold, including the CBM and South Texas assets and the majority of our Arklatex assets, as discontinued operations, and accordingly those operations are excluded from the discussion in this section.  The predecessor periods present our domestic natural gas assets sold in 2013 and our Gulf of Mexico assets sold in 2012 as divested assets.

As a result of these asset sales, we are a higher-growth, 100% onshore U.S., oil-weighted company with a large inventory of high-return, low-risk drilling locations. We intend to continue developing our oil-weighted assets, which offer the best rates of return in our portfolio in the current commodity price environment. In addition, our Haynesville Shale position is 100% held-by-production, which gives us the flexibility to allocate capital to this natural gas-weighted asset in the future.

The following table provides a summary of our oil, natural gas and NGLs reserves and production data as of December 31, 2013 for each of our continuing areas of operation.

	Estimated Proved Reserves								Average
							Proved		Net Daily
	Oil (MMBbls)	NGLs (MMBbls)	Natural Gas (Bcf)	Total (MMBoe)	Liquids (%)		Developed (%)		Production (MBoe/d)
Core Areas
Eagle Ford Shale	173.6	54.9	376.6	291.2	78	%	24	%	36.6
Wolfcamp Shale	45.9	19.8	115.0	84.9	77	%	25	%	5.5
Altamont	72.0	—	149.6	96.9	74	%	39	%	11.9
Haynesville Shale	—	—	353.6	59.0	0	%	68	%	27.1
Total Core Areas	291.5	74.7	994.8	532.0	69	%	32	%	81.1
Other(1)	1.9	1.0	75.7	15.5	19	%	81	%	5.0
Total	293.4	75.7	1,070.5	547.5	67	%	33	%	86.1

(1)                   Comprised of South Louisiana Wilcox and Arklatex Tight Gas assets.

1

Approximately 165 MMBoe, or 30%, of our total proved reserves are proved developed producing assets, which generated an average production of 86,108 Boe/d in 2013 from approximately 1,405 wells. As of December 31, 2013, we had approximately 293 MMBbls of proved oil reserves, 76 MMBbls of proved NGLs reserves and 1,071 Bcf of proved natural gas reserves in the United States, representing 54%, 13% and 33%, respectively, of our total proved reserves. For the year ended December 31, 2013, 51% of our oil production and 80% of our revenues (excluding realized and unrealized gains on financial derivatives) were related to oil and NGLs versus 31% and 66% in 2012, respectively and over that same period and on that same basis, our continuing oil production has grown by approximately 55%.  As a result of our development program and our divestitures of natural gas assets in 2013, the oil-weighting of our reserves is 54% as of December 31, 2013 as compared to 42% as of December 31, 2012 without giving effect to the divestitures of certain natural gas assets in 2013. In 2014, we anticipate that substantially all of our 2014 capital expenditures will be allocated to our core oil programs.

We operate over 87% of our producing wells and have operational control over approximately 95% of our core area drilling inventory as of December 31, 2013. This control provides us with flexibility around the amount and timing of capital spending and has allowed us to continually improve our capital and operating efficiencies. We also employ a centralized operational structure to accelerate our internal knowledge transfer around the execution of our drilling and completion programs and to continually enhance our field operations and base production performance. In 2013, we drilled 231 wells with a success rate of 99%, adding approximately 147 MMBoe of proved reserves (79% of which were liquids), excluding divested assets. Our reserve replacement cost as of December 31, 2013 was $12.62 per Boe. See Part II, Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Reserve Replacement Ratio/Reserve Replacement Costs” for further discussion of these metrics.

2

Available Information

Our website is http://www.epenergy.com. We make available, free of charge on or through our website, our annual, quarterly and current reports, and any amendments to those reports, as soon as is reasonably possible after these reports are filed with the Securities and Exchange Commission (SEC). Information about each of the members of the board of directors of our parent, EP Energy Corporation, as well as a copy of our Code of Conduct are also available, free of charge, through our website. Information contained on our website is not part of this report.

ITEM 1A. RISK FACTORS

Risks Related to Our Business and Industry

The supply and demand for oil, natural gas and NGLs could be negatively impacted by many factors outside of our control, which could have a material adverse effect on our business, results of operations and financial condition.

Our success depends on the domestic and worldwide supply and demand for oil, natural gas and NGLs which will depend on many factors outside of our control including:

·adverse changes in global, geopolitical and economic conditions, including changes that negatively impact general demand for oil and its refined products; power generation and industrial loads for natural gas; and petrochemical, refining and heating demand for NGLs;

·the relative growth of natural gas-fired power generation, including the speed and level of existing coal-fired generation that is replaced by natural gas-fired generation, which could be offset by the growth of various renewable energy sources;

·adverse changes in domestic regulations that could impact the supply or demand for oil, natural gas and NGLs, including potential restrictive regulations associated with hydraulic fracturing operations;

·adoption of various energy efficiency and conservation measures;

·increased prices of oil, natural gas or NGLs that could negatively impact the demand for these products;

·perceptions of customers on the availability and price volatility of our products, particularly customers’ perceptions on the volatility of natural gas and oil prices over the longer-term;

·adverse changes in geopolitical factors, including the ability of the Organization of Petroleum Exporting Countries (OPEC) to agree upon and maintain certain production levels, political unrest and changes in foreign governments in energy producing regions of the world and unexpected wars, terrorist activities and other acts of aggression;

·technological advancements that may drive further increases in production from oil and natural gas shales;

·the need of many producers to drill to maintain leasehold positions regardless of current commodity prices;

·the oversupply of NGLs that may be caused by the wider spread between oil and natural gas prices;

·competition from imported and potentially exported liquefied natural gas (LNG), Canadian supplies and alternate fuels;

·increased costs to explore for, develop and produce oil, natural gas or NGLs, including increases in oil field service costs; and

·the impact of weather on demand for oil, natural gas and/or NGLs.

3

The prices for oil, natural gas and NGLs are highly volatile and could be negatively impacted by many factors outside of our control, which could have a material adverse effect on our business, results of operations, cash flows and financial condition.

Our success depends upon the prices we receive for our oil, natural gas and NGLs. These commodity prices historically have been highly volatile and are likely to continue to be volatile in the future, especially given current global geopolitical and economic conditions. There is a risk that commodity prices could remain depressed for sustained periods, especially natural gas prices.  Except to the extent of our risk mitigation and hedging strategies, we can be impacted by short-term changes in commodity prices. We would also be negatively impacted in the long-term by any sustained depression in prices for oil, natural gas or NGLs, including reductions in our drilling opportunities. The prices for oil, natural gas and NGLs are subject to a variety of additional factors that are outside of our control, which include, among others:

·changes in regional, domestic and international supply of, and demand for, oil, natural gas and NGLs;

·natural gas inventory levels in the United States;

·political and economic conditions domestically and in other oil and natural gas producing countries, including, among others, countries in the Middle East, Africa and South America;

·actions of OPEC and other state-controlled oil companies relating to oil price and production controls;

·volatile trading patterns in capital and commodity-futures markets;

·changes in the costs of exploring for, developing, producing, transporting, processing and marketing oil, natural gas and NGLs;

·weather conditions;

·technological advances affecting energy consumption and energy supply;

·domestic and foreign governmental regulations and taxes, including administrative and/or agency actions;

·availability, proximity and cost of commodity processing, gathering and transportation and refining capacity;

·the price and availability of supplies of alternative energy sources;

·the effect of LNG deliveries to or the ability to export LNG from the United States;

·the strengthening and weakening of the U.S. dollar relative to other currencies; and

·variations between product prices at sales points and applicable index prices.

In addition to negatively impacting our cash flows, prolonged or substantial declines in commodity prices could negatively impact our proved oil and natural gas reserves and impact the amount of oil and natural gas that we can produce economically in the future. A decrease in production could result in a shortfall in our expected cash flows and require us to reduce our capital spending or borrow funds to cover any such shortfall. Prices also affect our cash flow available for capital expenditures and our ability to access funds under our reserve-based revolving credit facility (the RBL Facility) and through the capital markets. The amount available for borrowing under the RBL Facility is subject to a borrowing base, which is determined by our lenders taking into account our proved reserves, and is subject to periodic redeterminations based on pricing models determined by the lenders at such time. Declines in oil, natural gas and NGLs prices may adversely impact the value of our proved reserves and, in turn, the bank pricing used by our lenders to determine our borrowing base. Any of these factors could negatively impact our liquidity, our ability to replace our production and our future rate of growth. On the other hand, increases in these commodity prices may be offset by increases in drilling costs, production taxes and lease operating costs that typically result from any increase in such commodity prices. Any of these outcomes could have a material adverse effect on our business, results of operations and financial condition.

4

The success of our business depends upon our ability to find and replace reserves that we produce.

Similar to our competitors, we have a reserve base that is depleted as it is produced. Unless we successfully replace the reserves that we produce, our reserves will decline, which will eventually result in a decrease in oil and natural gas production and lower revenues and cash flows from operations. We historically have replaced reserves through both drilling and acquisitions. The business of exploring for, developing or acquiring reserves requires substantial capital expenditures. If we do not continue to make significant capital expenditures (for any reason, including our access to capital resources becoming limited) or if our exploration, development and acquisition activities are unsuccessful, we may not be able to replace the reserves that we produce, which would negatively impact us. As a result, our future oil and natural gas reserves and production, and therefore our cash flow and results of operations, are highly dependent upon our success in efficiently developing and exploiting our current properties and economically finding or acquiring additional recoverable reserves. We may not be able to develop, find or acquire additional reserves to replace our current and future production at acceptable costs or at all. If we are unable to replace our current and future production, the value of our reserves will decrease, and our business, results of operations and financial condition would be materially adversely affected.

Our oil and natural gas drilling and producing operations involve many risks, and our production forecasts may differ from actual results.

Our success will depend on our drilling results. Our drilling operations are subject to the risk that (i) we may not encounter commercially productive reservoirs or (ii) if we encounter commercially productive reservoirs, we either may not fully recover our investments or our rates of return will be less than expected. Our past performance should not be considered indicative of future drilling performance. For example, we have acquired acreage positions in domestic oil and natural gas shale areas for which we plan to incur substantial capital expenditures over the next several years. It remains uncertain whether we will be successful in developing the reserves in these regions. Our success in such areas will depend in part on our ability to successfully transfer our experiences from existing areas into these new shale plays. As a result, there remains uncertainty on the results of our drilling programs, including our ability to realize proved reserves or to earn acceptable rates of return on our drilling programs. From time to time, we provide forecasts of expected quantities of future production. These forecasts are based on a number of estimates, including expectations of production from existing wells and the outcome of future drilling activity. Our forecasts could be different from actual results and such differences could be material.

Our decisions to purchase, explore, develop or otherwise exploit prospects or properties will depend in part on the evaluation of data obtained through geophysical and geological analyses, production data and engineering studies, the results of which are often inconclusive or subject to varying interpretations. In addition, the results of our exploratory drilling in new or emerging areas are more uncertain than drilling results in areas that are developed and have established production. Our cost of drilling, completing, equipping and operating wells is often uncertain before drilling commences. Overruns in budgeted expenditures are common risks that can make a particular project uneconomical or less economic than forecasted. Further, many factors may increase the cost of, or curtail, delay or cancel drilling operations, including the following:

·unexpected drilling conditions;

·delays imposed by or resulting from compliance with regulatory and contractual requirements;

·unexpected pressure or irregularities in geological formations;

·equipment failures or accidents;

·fracture stimulation accidents or failures;

·adverse weather conditions;

·declines in oil and natural gas prices;

·surface access restrictions with respect to drilling or laying pipelines;

·shortages (or increases in costs) of water used in hydraulic fracturing, especially in arid regions or regions that have been experiencing severe drought conditions;

5

·shortages or delays in the availability of, increases in the cost of, or increased competition for, drilling rigs and crews, fracture stimulation crews, equipment, pipe, chemicals and supplies and transportation, gathering, processing, treating or other midstream services; and

·limitations or reductions in the market for oil and natural gas.

Additionally, the occurrence of certain of these events, particularly equipment failures or accidents, could impact third parties, including persons living in proximity to our operations, our employees and employees of our contractors, leading to possible injuries or death or significant property damage. As a result, we face the possibility of liabilities from these events that could materially adversely affect our business, results of operations and financial condition.

In addition, uncertainties associated with enhanced recovery methods may not allow for the extraction of oil and natural gas in a manner or to the extent that we anticipate and we may be unable to realize an acceptable return on our investments in certain of our projects. The additional production and reserves, if any, attributable to the use of enhanced recovery methods are inherently difficult to predict.

Our use of derivative financial instruments could result in financial losses or could reduce our income.

We use fixed price financial options and swaps to mitigate our commodity price, basis and interest rate exposures. However, we do not typically hedge all of these exposures, and typically do not hedge any of these exposures beyond several years. As a result, we have substantial commodity price and basis exposure since our business has multi-year drilling programs for our proved reserves and unproved resources.

The derivative contracts we enter into to mitigate commodity price risk are not designated as accounting hedges and are therefore marked to market. As a result, we still experience volatility in our revenues and net income as a result of changes in commodity prices, counterparty non-performance risks, correlation factors and changes in the liquidity of the market. Furthermore, the valuation of these financial instruments involves estimates that are based on assumptions that could prove to be incorrect and result in financial losses. Although we have internal controls in place that impose restrictions on the use of derivative instruments, there is a risk that such controls will not be complied with or will not be effective, and we could incur substantial losses on our derivative transactions. The use of derivatives, to the extent they require collateral posting with our counterparties, could impact our working capital and liquidity when commodity prices or interest rates change.

To the extent we enter into derivative contracts to manage our commodity price, basis and interest rate exposures, we may forego the benefits we could otherwise experience if such prices and rates were to change favorably and we could experience losses to the extent that these prices and rates were to increase above the fixed price.  In addition, these hedging arrangements also expose us to the risk of financial loss in the following circumstances, among others:

·when production is less than expected or less than we have hedged;

·when the counterparty to the hedging instrument defaults on its contractual obligations;

·when there is an increase in the differential between the underlying price in the hedging instrument and actual prices received; and

·when there are issues with respect to legal enforceability of such instruments.

Our derivative counterparties are typically large financial institutions. The risk that a counterparty may default on its obligations is heightened by the recent financial sector crisis and losses incurred by many banks and other financial institutions, including our counterparties or their affiliates. These losses may affect the ability of the counterparties to meet their obligations to us on hedge transactions, which would reduce our revenue from hedges at a time when we are also receiving a lower price for our oil and natural gas sales. As a result, our business, results of operations and financial condition could be materially adversely affected.

6

The derivatives reform legislation adopted by the U.S. Congress could have a negative impact on our ability to hedge risks associated with our business.

In 2010, Congress adopted the Dodd-Frank Wall Street Reform and Consumer Protection Act (the Dodd-Frank Act), which, among other matters, provides for federal oversight of the over-the-counter derivatives market and entities that participate in that market. The Dodd-Frank Act mandates that the Commodity Futures Trading Commission (CFTC), adopt rules and regulations implementing the Dodd-Frank Act and further defining certain terms used in the Dodd-Frank Act. The Dodd-Frank Act also requires the CFTC and the prudential banking regulators to establish margin requirements for uncleared swaps. Although there is an exception from swap clearing and trade execution requirements for commercial end-users that meet certain conditions (the End-User Exception), certain market participants, including most if not all of our counterparties, will also be required to clear many of their swap transactions with entities that do not satisfy the End-User Exception and will have to transact many of their swaps on swap execution facilities or designated contract markets, rather than over-the-counter on a bilateral basis. These requirements may increase the cost to our counterparties of hedging the swap positions they enter into with us, and thus may increase the cost to us of entering into our hedges. The changes in the regulation of swaps may result in certain market participants deciding to curtail or cease their derivatives activities. While many regulations have been promulgated and are already in effect, the rulemaking and implementation process is ongoing, and the ultimate effect of the adopted rules and regulations and any future rules and regulations on our business remains uncertain.

We qualify as a “non-financial entity” for purposes of the End-User Exception and satisfy the other requirements of the End-User Exception and intend to utilize the End-User Exception. As a result, our swaps will not be subject to mandatory clearing; therefore, we do not expect to clear our swaps and our swap transactions will not be subject to the margin requirements imposed by derivatives clearing organizations. Because the margin regulations for uncleared swaps have not been adopted, we do not yet know whether our counterparties will be required to collect liquid margin from us for those swaps.

A rule adopted under the Dodd-Frank Act imposing position limits in respect of transactions involving certain commodities, including oil and natural gas was vacated and remanded to the CFTC for further proceedings by order of the United States District Court for the District of Columbia, U.S. District Judge Robert L. Wilkins on September 28, 2012. The CFTC appealed this decision and on November 5, 2013, filed a consensual motion to dismiss its appeal.  The same day, the CFTC proposed a new position limits rule which would limit trading in New York Mercantile Exchange (NYMEX) contracts for Henry Hub Natural Gas, Light Sweet Crude Oil, New York Harbor Ultra-Low Sulfur No. 2 Diesel and Reformulated Blendstock for Oxygen Blending Gasoline and other futures and swap contracts that are economically equivalent to such NYMEX contracts.  Comments on the proposed rule were due on February 10, 2014. We cannot predict whether or when the proposed rule will be adopted or the effect of the proposed rule on our business. The Dodd-Frank Act and the rules promulgated thereunder could significantly increase the cost of derivative contracts (including through requirements to post collateral), materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks we encounter, reduce our ability to monetize or restructure our existing derivative contracts, and increase our exposure to less creditworthy counterparties. Finally, the Dodd-Frank Act was intended, in part, to reduce the volatility of oil and natural gas prices, which some legislators attributed to speculative trading in derivatives and commodity contracts related to oil and natural gas. Our revenues could therefore be adversely affected if a consequence of the Dodd-Frank Act and regulations is to lower commodity prices. Any of these consequences could have a material and adverse effect on our business, financial condition and results of operations.

We require substantial capital expenditures to conduct our operations, engage in acquisition activities and replace our production, and we may be unable to obtain needed financing on satisfactory terms necessary to execute our operating strategy.

We require substantial capital expenditures to conduct our exploration, development and production operations, engage in acquisition activities and increase our proved reserves and production. We have established a capital budget for 2014 of approximately $2.0 billion and we intend to rely on cash flow from operating activities, available cash and borrowings under the RBL Facility as our primary sources of liquidity. We also may engage in asset sale transactions such as the pending and recently completed divestitures to, among other things, fund capital expenditures when market conditions permit us to complete transactions on terms we find acceptable. There can be no assurance that such sources will be sufficient to fund our exploration, development and acquisition activities. If our revenues and cash flows decrease in the future as a result of a decline in commodity prices or a reduction in production levels, however, and we are unable to obtain additional equity or debt financing in the capital markets or access alternative sources of funds, we may be required to reduce the level of our capital expenditures and may lack the capital necessary to increase or even maintain our reserves and production levels.

Our future revenues, cash flows and spending levels are subject to a number of factors, including commodity prices, the level of production from existing wells and our success in developing and producing new wells. Further, our ability to access funds under the RBL Facility is based on a borrowing base, which is subject to periodic redeterminations based on our proved reserves and prices

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that will be determined by our lenders using the bank pricing prevailing at such time. If the prices for oil and natural gas decline, if we have a downward revision in estimates of our proved reserves, or if we sell additional oil and natural gas reserves, our borrowing base may be reduced.

Our ability to access the capital markets and complete future asset monetization transactions is also dependent upon oil, natural gas and NGLs prices, in addition to a number of other factors, some of which are outside our control. These factors include, among others, domestic and global economic conditions and conditions in the domestic and global financial markets.

Due to these factors, we cannot be certain that funding, if needed, will be available to the extent required, or on acceptable terms. If we are unable to access funding when needed on acceptable terms, we may not be able to fully implement our business plans, take advantage of business opportunities, respond to competitive pressures or refinance our debt obligations as they come due, any of which could have a material adverse effect on our business, financial condition, cash flows and results of operations.

Estimating our reserves involves uncertainty, our actual reserves will likely vary from our estimates, and negative revisions to our reserve estimates in the future could result in decreased earnings and/or losses and impairments.

All estimates of proved reserves are determined according to the rules prescribed by the SEC. Our reserve information is prepared internally and is audited by an independent petroleum engineering consultant. There are numerous uncertainties involved in estimating proved reserves, which may result in our estimates varying considerably from actual results. Estimating quantities of proved reserves is complex and involves significant interpretation and assumptions with respect to available geological, geophysical and engineering data, including data from nearby producing areas. It also requires us to estimate future economic factors, such as commodity prices, production costs, plugging and abandonment costs, severance, ad valorem and excise taxes, capital expenditures, workover and remedial costs, and the assumed effect of governmental regulation. Due to a lack of substantial production data, there are greater uncertainties in estimating proved undeveloped reserves and proved developed non-producing reserves. There is also greater uncertainty of estimating proved developed reserves that are early in their production life. As a result, our reserve estimates are inherently imprecise. Furthermore, estimates are subject to revision based upon a number of factors, including many factors beyond our control such as reservoir performance, prices (including commodity prices and the cost of oilfield services), economic conditions and government restrictions and regulations. In addition, results of drilling, testing and production subsequent to the date of an estimate may justify revision of that estimate. Therefore, our reserve information represents an estimate and is often different from the quantities of oil and natural gas that are ultimately recovered or proven recoverable.

The SEC rules require the use of a 10% discount factor for estimating the value of our future net cash flows from reserves and the use of a 12-month average price. This discount factor may not necessarily represent the most appropriate discount factor, given our costs of capital, actual interest rates and risks faced by our exploration and production business, and the average price will not generally represent the market prices for oil and natural gas over time. Any significant change in commodity prices could cause the estimated quantities and net present value of our reserves to differ and these differences could be material. You should not assume that the present values referred to in this prospectus represent the current market value of our estimated oil and natural gas reserves. Finally, the timing of the production and the expenses related to the development and production of oil and natural gas properties will affect both the timing of actual future net cash flows from our proved reserves and their present value.

We account for our activities under the successful efforts method of accounting. Changes in the present value of these reserves could result in a write-down in the carrying value of our oil and natural gas properties, which could be substantial and could have a material adverse effect on our net income and member’s equity. Changes in the present value of these reserves could also result in increasing our depreciation, depletion and amortization rates, which could decrease earnings.

A portion of our proved reserves are undeveloped. Recovery of undeveloped reserves requires significant capital expenditures and successful drilling operations. In addition, because our proved reserve base consists primarily of unconventional resources, the costs of finding, developing and producing those reserves may require capital expenditures that are greater than more conventional resource plays. Our estimates of proved reserves assume that we can and will make these expenditures and conduct these operations successfully. However, future events, including commodity price changes and our ability to access capital markets, may cause these assumptions to change.

Our business is subject to competition from third parties, which could negatively impact our ability to succeed.

The oil, natural gas and NGLs businesses are highly competitive. We compete with third parties in the search for and acquisition of leases, properties and reserves, as well as the equipment, materials and services required to explore for and produce our reserves. There has been intense competition for the acquisition of leasehold positions, particularly in many of the oil and natural gas shale plays. Our ability to acquire additional properties and to discover reserves in the future will be dependent upon our ability to

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evaluate and select suitable properties and to consummate transactions in a highly competitive environment. In addition, because we have fewer financial and human resources than many companies in our industry, we may be at a disadvantage in bidding for exploratory prospects and producing oil properties. Similarly, we compete with many third parties in the sale of oil, natural gas and NGLs to customers, some of which have substantially larger market positions, marketing staff and financial resources than us. Our competitors include major and independent oil and natural gas companies, as well as financial services companies and investors, many of which have financial and other resources that are substantially greater than those available to us. Many of these companies not only explore for and produce oil and natural gas, but also carry on refining operations and market petroleum and other products on a regional, national or worldwide basis. These companies may be able to pay more for productive oil and natural gas properties and exploratory prospects or define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit. In addition, these companies may have a greater ability to continue exploration activities during periods of low oil and natural gas market prices.

Furthermore, there is significant competition between the oil and natural gas industry and other industries producing energy and fuel, which may be substantially affected by various forms of energy legislation and/or regulation considered from time to time by the U.S. government. It is not possible to predict the nature of any such legislation or regulation that may ultimately be adopted or its effects upon our future operations. Such laws and regulations may substantially increase the costs of exploring for, developing or producing oil and natural gas and may prevent or delay the commencement or continuation of a given operation. Our larger competitors may be able to absorb the burden of existing, and any changes to, federal, state and local laws and regulations more easily than we can, which could negatively impact our competitive position.

Our industry is cyclical, and historically there have been shortages of drilling rigs, equipment, supplies or qualified personnel. During these periods, the cost of rigs, equipment, supplies and personnel are substantially greater and their availability may be limited. These services may not be available on commercially reasonable terms or at all. We cannot predict whether these conditions will exist in the future and, if so, what their timing and duration will be. The high cost or unavailability of drilling rigs, equipment, supplies, personnel and other oil field services could significantly decrease our profit margins, cash flows and operating results and could restrict our ability to drill the wells and conduct the operations that we currently have planned and budgeted or that we may plan in the future. Any of these outcomes could have a material adverse effect on our business, results of operations and financial condition.

Our business is subject to operational hazards and uninsured risks that could have a material adverse effect on our business, results of operations and financial condition.

Our oil and natural gas exploration and production activities are subject to all of the inherent risks associated with drilling for and producing natural gas and oil, including the possibility of:

·Adverse weather conditions, natural disasters, and/or other climate related matters—including extreme cold or heat, lightning and flooding, fires, earthquakes, hurricanes, tornadoes and other natural disasters. Although the potential effects of climate change on our operations (such as hurricanes, flooding, etc.) are uncertain at this time, changes in climate patterns as a result of global emissions of greenhouse gas (GHG) could also have a negative impact upon our operations in the future, particularly with regard to any of our facilities that are located in or near coastal regions;

·Acts of aggression on critical energy infrastructure—including terrorist activity or “cyber security” events. We are subject to the ongoing risk that one of these incidents may occur which could significantly impact our business operations and/or financial results. Should one of these events occur in the future, it could impact our ability to operate our drilling and exploration processes, our operations could be disrupted, and/or property could be damaged resulting in substantial loss of revenues, increased costs to respond or other financial loss, damage to reputation, increased regulation and litigation and/or inaccurate information reported from our exploration and production operations to our financial applications, to our customers and to regulatory entities; and

·Other hazards—including the collision of third-party equipment with our infrastructure; explosions, equipment malfunctions, mechanical and process safety failures, well blowouts, formations with abnormal pressures and collapses of wellbore casing or other tubulars; events causing our facilities to operate below expected levels of capacity or efficiency; uncontrollable flows of natural gas, oil, brine or well fluids, release of pollution or contaminants (including hydrocarbons) into the environment (including discharges of toxic gases or substances) and other environmental hazards.

Each of these risks could result in (i) damage to and destruction of our facilities; (ii) damage to and destruction of property, natural resources and equipment; (iii) injury or loss of life; (iv) business interruptions while damaged energy infrastructure is repaired or replaced; (v) pollution and other environmental damage; (vi) regulatory investigations and penalties; and (vii) repair and

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remediation costs. Any of these results could cause us to suffer substantial losses. Our offshore operations in Brazil, which are in the process of being divested, may encounter additional marine perils, including adverse weather conditions, damage from collisions with vessels, and governmental regulations (including interruption or termination of drilling rights by governmental authorities based on environmental, safety and other considerations).

While we maintain insurance against some of these risks in amounts that we believe are reasonable, our insurance coverages have material deductibles, self-insurance levels and limits on our maximum recovery and do not cover all risks. For example, from time to time, we may not carry, or may be unable to obtain, on terms that we find acceptable and/or reasonable, insurance coverage for certain exposures, including, but not limited to certain environmental exposures (including potential environmental fines and penalties), business interruption and, named windstorm/hurricane exposures and, in limited circumstances, certain political risk exposures. The premiums and deductibles we pay for certain insurance policies are also subject to the risk of substantial increases over time that could negatively impact our financial results. In addition, we may not be able to renew existing insurance policies or procure desirable insurance on commercially reasonable terms. There is also a risk that our insurers may default on their insurance coverage obligations or that amounts for which we are insured, or that the proceeds of such insurance, will not compensate us fully for our losses. Any of these outcomes could have a material adverse effect on our business, results of operations and financial condition.

Some of our operations are subject to joint ventures or operations by third parties, which could negatively impact our control over these operations and have a material adverse effect on our business, results of operations, financial condition and prospects.

A small portion of our operations and interests are operated by third-party working interest owners.  In such cases, (i) we have limited ability to influence or control the day-to-day operation of such properties, including compliance with environmental, safety and other regulations, (ii) we cannot control the amount of capital expenditures that we are required to fund with respect to properties, (iii) we are dependent on third parties to fund their required share of capital expenditures and (iv) we may have restrictions or limitations on our ability to sell our interests in these jointly owned assets.

The failure of an operator of our properties to adequately perform operations or an operator’s breach of applicable agreements could reduce our production and revenue. As a result, the success and timing of our drilling and development activities on properties operated by others depends upon a number of factors outside of our control, including the operator’s timing and amount of capital expenditures, expertise and financial resources, inclusion of other participants in drilling wells and use of technology.

We currently sell most of our oil production to a limited number of significant purchasers. The loss of one or more of these purchasers, if not replaced, could reduce our revenues and have a material adverse effect on our financial condition or results of operations.

For the year ended December 31, 2013, three purchasers accounted for approximately 80% of our oil revenues. We depend upon a limited number of significant purchasers for the sale of most of our production. The loss of any of these customers, should we be unable to replace them, could adversely affect our revenues and have a material adverse effect on our financial condition and results of operations. We cannot assure you that any of our customers will continue to do business with us or that we will continue to have access to suitably liquid markets for our future production.

We are subject to a complex set of laws and regulations that regulate the energy industry for which we have to incur substantial compliance and remediation costs.

Our operations, and the energy industry in general, are subject to a complex set of federal, state and local laws and regulations over the following activities, among others:

·the location of wells;

·methods of drilling and completing wells;

·allowable production from wells;

·unitization or pooling of oil and gas properties;

·spill prevention plans;

·limitations on venting or flaring of natural gas;

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·disposal of fluids used and wastes generated in connection with operations;

·access to, and surface use and restoration of, well properties;

·plugging and abandoning of wells, even if we no longer own and/or operate such wells;

·air quality, noise levels and related permits;

·gathering, transportation and marketing of oil and natural gas (including NGLs);

·taxation; and

·competitive bidding rules on federal and state lands.

Generally, the regulations have become more stringent and have imposed more limitations on our operations and, as a result, have caused us to incur more costs to comply. Many required approvals are subject to considerable discretion by the regulatory agencies with respect to the timing and scope of approvals and permits issued. If permits are not issued, or if unfavorable restrictions or conditions are imposed on our drilling activities, we may not be able to conduct our operations as planned or at all. Delays in obtaining regulatory approvals or permits, the failure to obtain a drilling permit for a well, or the receipt of a permit with excessive conditions or costs could have a material negative impact on our operations and financial results. We may also incur substantial costs in order to maintain compliance with these existing laws and regulations, including costs to comply with new and more extensive reporting and disclosure requirements. Failure to comply with such requirements may result in the suspension or termination of operations and may subject us to criminal as well as civil and administrative penalties. We are exposed to fines and penalties to the extent that we fail to comply with the applicable laws and regulations, as well as the potential for limitations to be imposed on our operations. In addition, our costs of compliance may increase if existing laws and regulations are revised or reinterpreted, or if new laws and regulations become applicable to our operations. Such costs could have a material adverse effect on our business, financial condition and results of operations.

Also, some of our assets are located and operate on federal, state, local or tribal lands and are typically regulated by one or more federal, state or local agencies. For example, we have drilling and production operations that are located on federal lands, which are regulated by the U.S. Department of the Interior (DOI), particularly by the Bureau of Land Management (BLM). We also have operations on Native American tribal lands, which are regulated by the DOI, particularly by the Bureau of Indian Affairs (BIA), as well as local tribal authorities. Operations on these properties are often subject to additional regulations and compliance obligations, which can delay our access to such lands and impose additional compliance costs. There are also various laws and regulations that regulate various market practices in the industry, including antitrust laws and laws that prohibit fraud and manipulation in the markets in which we operate. The authority of the Federal Trade Commission and the CFTC to impose penalties for violations of laws or regulations has generally increased over the last few years.

We are exposed to the credit risk of our counterparties, contractors and suppliers.

We have significant credit exposure related to our sales of physical commodities, payments to contractors and suppliers and hedging activities.  If our counterparties fail to make payments/or perform within the time required under our contracts, our results of operations and financial condition could be materially adversely affected.  Although we maintain strict credit policies and procedures, they may not be adequate to fully eliminate the credit risk associated with our counterparties, contractors and suppliers.

We are exposed to the performance risk of our key contractors and suppliers.

As an owner of drilling and production facilities with significant capital expenditures in our business, we rely on contractors for certain construction, drilling and completion operations and we rely on suppliers for key materials, supplies and services, including steel mills, pipe and tubular manufacturers and oil field service providers. We also rely upon the services of other third parties to explore or analyze our prospects to determine a method in which the prospects may be developed in a cost-effective manner. There is a risk that such contractors and suppliers may experience credit and performance issues that could adversely impact their ability to perform their contractual obligations with us, including their performance and warranty obligations. This could result in delays or defaults in performing such contractual obligations and increased costs to seek replacement contractors, each of which could negatively impact us.

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The Sponsors and other legacy investors own a majority  of the equity interests in our parent company and may have conflicts of interest with us and or the public investors.

Investment funds affiliated with, and one or more co-investment vehicles controlled by, our Sponsors and other legacy investors collectively own a majority of our equity interests and such persons or their designees hold substantially all of the seats on the board of directors of our parent, EP Energy Corporation. As a result, the Sponsors and such other investors have control over our decisions to enter into certain corporate transactions and have the ability to prevent any transaction that typically would require the approval of stockholders, regardless of whether holders of our notes believe that any such transactions are in their own best interests. For example, the Sponsors and other legacy investors could collectively cause us to make acquisitions that increase the amount of our indebtedness or to sell assets, or could cause us to issue additional equity or declare dividends or other distributions to our equity holders. So long as investment funds affiliated with the Sponsors and other such investors continue to indirectly own a majority of the outstanding shares of our equity interests or otherwise control a majority of the board of directors of our parent, these investors will continue to be able to strongly influence or effectively control our decisions. The indentures governing the notes and the credit agreements governing the RBL Facility and our senior secured term loan permit us, under certain circumstances, to pay advisory and other fees, pay dividends and make other restricted payments to the Sponsors and other investors, and the Sponsors and such other investors or their respective affiliates may have an interest in our doing so.

Additionally, the Sponsors and other legacy investors are in the business of making investments in companies and may from time to time acquire and hold interests in businesses that compete directly or indirectly with us or that supply us with goods and services. These persons may also pursue acquisition opportunities that may be complementary to (or competitive with) our business, and as a result those acquisition opportunities may not be available to us. In addition, the Sponsors’ and other investors’ interests in other portfolio companies could impact our ability to pursue acquisition opportunities.

The loss of the services of key personnel could have a material adverse effect on our business.

Our executive officers and other members of our senior management have been a critical element of our success. These individuals have substantial experience and expertise in our business and have made significant contributions to its growth and success. We do not have key man or similar life insurance covering our executive officers and other members of senior management. We have entered into employment agreements with each of our executive officers, including Brent J. Smolik, our President and Chief Executive Officer, and Dane E. Whitehead, our Executive Vice President and Chief Financial Officer, but these agreements do not guarantee that these executives will remain with us. The unexpected loss of services of one or more of our executive officers or members of senior management could have a material adverse effect on our business.

Our business requires the retention and recruitment of a skilled workforce and the loss of employees and skilled labor shortages could result in the inability to implement our business plans and could negatively impact our profitability.

Our business requires the retention and recruitment of a skilled workforce including engineers, technical personnel, geoscientists, project managers, land personnel and other professionals. We compete with other companies in the energy industry for this skilled workforce. We have developed company-wide compensation and benefit programs that are designed to be competitive among our industry peers and that reflect market-based metrics as well as incentives to create alignment with the Sponsors and other investors, but there is a risk that these programs and those in the future will not be successful in retaining and recruiting these professionals or that we could experience increased costs. If we are unable to (i) retain our current employees, (ii) successfully complete our knowledge transfer and/or (iii) recruit new employees of comparable knowledge and experience, our business, results of operations and financial condition could be negatively impacted. In addition, we could experience increased costs to retain and recruit these professionals.

We may be affected by skilled labor shortages, which we have from time-to-time experienced, especially in North American regions where there are large unconventional shale resource plays. These shortages could negatively impact the productivity and profitability of certain projects. Our inability to bid on new and attractive projects, or maintain productivity and profitability on existing projects due to the limited supply of skilled workers and/or increased labor costs could have a material adverse effect on our business, results of operation and financial condition.

Part of our strategy involves drilling in existing or emerging shale plays using some of the latest available horizontal drilling and completion techniques, the results of which are subject to drilling and completion technique risks, and drilling results may not meet our expectations for reserves or production.

Many of our operations involve utilizing the latest horizontal drilling and completion techniques in order to maximize cumulative recoveries and therefore optimize our returns. Drilling risks that we face while include, but are not limited to, landing our

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well bore in the desired drilling zone, staying in the desired drilling zone while drilling horizontally through the formation, running our casing the entire length of the well bore and being able to run tools and other equipment consistently through the horizontal well bore. Risks that we face while completing our wells include, but are not limited to, being able to fracture stimulate the planned number of stages, being able to run tools the entire length of the well bore during completion operations and successfully cleaning out the well bore after completion of the final fracture stimulation stage.

Ultimately, the success of these drilling and completion techniques can only be evaluated over time as more wells are drilled and production profiles are established over a sufficiently longer period. If our drilling results are less than anticipated, the return on our investment for a particular project may not be as attractive as we anticipated and we could incur material write-downs of unevaluated properties and the value of our undeveloped acreage could decline in the future.

Drilling locations that we decide to drill may not yield oil, natural gas or NGLs in commercially viable quantities.

We describe potential drilling locations and our plans to explore those potential drilling locations in this 10-K. These potential drilling locations are in various stages of evaluation, ranging from a location which is ready to drill to a location that will require substantial additional interpretation. There is no way to predict in advance of drilling and testing whether any particular location will yield oil, natural gas or NGLs in sufficient quantities to recover drilling or completion costs or to be economically viable. The use of technologies and the study of producing fields in the same area will not enable us to know conclusively, prior to drilling, whether oil, natural gas or NGLs will be present or, if present, whether oil, natural gas or NGLs will be present in sufficient quantities to be economically viable. Even if sufficient amounts of oil, natural gas or NGLs exist, we may damage the potentially productive hydrocarbon-bearing formation or experience mechanical difficulties while drilling or completing the well, resulting in a reduction in production from the well or abandonment of the well. We cannot assure you that the analogies we draw from available data from other wells, more fully explored locations or producing fields will be applicable to our other identified drilling locations. Further, initial production rates reported by us or other operators may not be indicative of future or long-term production rates.  The cost of drilling, completing and operating any well is often uncertain, and new wells may not be productive.

Our drilling locations are scheduled to be drilled over several years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling.

Our management has identified and scheduled potential drilling locations as an estimate of our future multi-year drilling activities on our existing acreage. All of our potential drilling locations, particularly our potential drilling locations for oil, represent a significant part of our growth strategy. Our ability to drill and develop these locations is subject to a number of uncertainties, including the availability of capital, seasonal conditions, regulatory approvals, oil, natural gas and NGLs prices, costs and drilling results. Because of these uncertainties, we do not know if the drilling locations we have identified will ever be drilled or if we will be able to produce oil, natural gas or NGLs from these or any other potential drilling locations. Pursuant to existing SEC rules and guidance, subject to limited exceptions, proved undeveloped reserves may only be booked if they relate to wells scheduled to be drilled within five years of the date of booking. These rules and guidance may limit our potential to book additional proved undeveloped reserves as we pursue our drilling program.

New technologies may cause our current exploration and drilling methods to become obsolete.

The oil and natural gas industry is subject to rapid and significant advancements in technology, including the introduction of new products and services using new technologies. As competitors use or develop new technologies, we may be placed at a competitive disadvantage, and competitive pressures may force us to implement new technologies at a substantial cost. In addition, competitors may have greater financial, technical and personnel resources that allow them to enjoy technological advantages and may in the future allow them to implement new technologies before we can. One or more of the technologies that we currently use or that we may implement in the future may become obsolete. We cannot be certain that we will be able to implement technologies on a timely basis or at a cost that is acceptable to us. If we are unable to maintain technological advancements consistent with industry standards, our business, results of operations and financial condition may be materially adversely affected.

Our business depends on access to oil, natural gas and NGLs processing, gathering and transportation systems and facilities.

The marketability of our oil, natural gas and NGLs production depends in large part on the operation, availability, proximity, capacity and expansion of processing, gathering and transportation facilities owned by third parties. We can provide no assurance that sufficient processing, gathering and/or transportation capacity will exist or that we will be able to obtain sufficient processing, gathering and/or transportation capacity on economic terms. A lack of available capacity on processing, gathering and transportation facilities or delays in their planned expansions could result in the shut-in of producing wells or the delay or discontinuance of drilling plans for properties. A lack of availability of these facilities for an extended period of time could negatively impact our revenues. In

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addition, we have entered into contracts for firm transportation and any failure to renew those contracts on the same or better commercial terms could increase our costs and our exposure to the risks described above.

Our operations are substantially dependent on the availability of water. Restrictions on our ability to obtain water may have an adverse effect on our financial condition, results of operations and cash flows.

Water currently is an essential component of deep shale oil and natural gas production during both the drilling and hydraulic fracturing processes. Historically, we have been able to purchase water from local land owners for use in our operations. According to the Lower Colorado River Authority, during 2011, Texas experienced the lowest inflows of water of any year in recorded history. As a result of this severe drought, some local water districts have begun restricting the use of water subject to their jurisdiction for hydraulic fracturing to protect local water supply. If we are unable to obtain water to use in our operations from local sources, we may be unable to economically produce our reserves, which could have an adverse effect on our financial condition, results of operations and cash flows.

We may face unanticipated water and other waste disposal costs.

We may be subject to regulation that restricts our ability to discharge water produced as part of our operations. Productive zones frequently contain water that must be removed in order for the oil and natural gas to produce, and our ability to remove and dispose of sufficient quantities of water from the various zones will determine whether we can produce oil and natural gas in commercial quantities. The produced water must be transported from the lease and injected into disposal wells. The availability of disposal wells with sufficient capacity to receive all of the water produced from our wells may affect our ability to produce our wells. Also, the cost to transport and dispose of that water, including the cost of complying with regulations concerning water disposal, may reduce our profitability.

Where water produced from our projects fails to meet the quality requirements of applicable regulatory agencies, our wells produce water in excess of the applicable volumetric permit limits, the disposal wells fail to meet the requirements of all applicable regulatory agencies, or we are unable to secure access to disposal wells with sufficient capacity to accept all of the produced water, we may have to shut in wells, reduce drilling activities, or upgrade facilities for water handling or treatment. The costs to dispose of this produced water may increase if any of the following occur:

·we cannot obtain future permits from applicable regulatory agencies;

·water of lesser quality or requiring additional treatment is produced;

·our wells produce excess water;

·new laws and regulations require water to be disposed in a different manner; or

·costs to transport the produced water to the disposal wells increase.

Our acquisition attempts may not be successful or may result in completed acquisitions that do not perform as anticipated.

We have made and may continue to make acquisitions of businesses and properties. However, suitable acquisition candidates may not continue to be available on terms and conditions we find acceptable or at all. Any acquisition, including any completed or future acquisition, involves potential risks, including, among others:

·we may not produce revenues, reserves, earnings or cash flow at anticipated levels or could have environmental, permitting or other problems for which contractual protections prove inadequate;

·we may assume liabilities that were not disclosed to us and for which contractual protections prove inadequate or that exceed our estimates;

·we may acquire properties that are subject to burdens on title that we were not aware of at the time of acquisition that interfere with our ability to hold the property for production and for which contractual protections prove inadequate;

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·we may be unable to integrate acquired businesses successfully and realize anticipated economic, operational and other benefits in a timely manner, which could result in substantial costs and delays or other operational, technical or financial problems;

·we may encounter disruption to our ongoing business, distract management, divert resources and make it difficult to maintain our current business standards, controls,  procedures and policies;

·we may issue (or assume) additional equity or debt securities or debt instruments in connection with future acquisitions, which may affect our liquidity or financial leverage;

·we may make mistaken assumptions about costs, including synergies related to an acquired business;

·we may encounter difficulties in complying with regulations, such as environmental regulations, and managing risks related to an acquired business;

·we may encounter limitations on rights to indemnity from the seller;

·we may make mistaken assumptions about the overall costs of equity or debt used to finance any such acquisition;

·we may encounter difficulties in entering markets in which we have no or limited direct prior experience and where competitors in such markets have stronger expertise and/or market positions;

·we may potentially lose key customers; and

·we may lose key employees and/or encounter costly litigation resulting from the termination of those employees.

Any of the above risks could significantly impair our ability to manage our business, complete or effectively integrate acquisitions and may have a material adverse effect on our business, results of operations and financial condition.

Certain of our undeveloped leasehold acreage is subject to leases that will expire in several years unless production is established on units containing the acreage.

Although most of our reserves are located on leases that are held-by-production or held by continuous development, we do have provisions in many of our leases that provide for the lease to expire unless certain conditions are met, such as drilling having commenced on the lease or production in paying quantities having been obtained within a defined time period. If commodity prices remain low or we are unable to fund our anticipated capital program there is a risk that some of our existing proved reserves and some of our unproved inventory could be subject to lease expiration or a requirement to incur additional leasehold costs to extend the lease. This could result in a reduction in our reserves and our growth opportunities (or the incurrence of significant costs) and therefore could have a material adverse effect on our financial results.

If oil and/or natural gas prices decrease, we may be required to take write-downs of the carrying values of our properties, which could result in a material adverse effect on our results of operations and financial condition.

Accounting rules require that we review periodically the carrying value of our oil and natural gas properties for impairment. Under the successful efforts method of accounting, we review our oil and natural gas properties periodically (at least annually) to determine if impairment of such properties is necessary. Significant undeveloped leasehold costs are assessed for impairment at a lease level or resource play level based on our current exploration plans, while leasehold acquisition costs associated with prospective areas that have limited or no previous exploratory drilling are generally assessed for impairment by major prospect area. Proved oil and natural gas property values are reviewed when circumstances suggest the need for such a review and may occur if actual discoveries in a field are lower than anticipated reserves, reservoirs produce below original estimates or if commodity prices fall to a level that significantly affects anticipated future cash flows on the property. If required, the proved properties are written down to their estimated fair market value based on proved reserves and other market factors.

We may incur impairment charges in the future depending on the value of our proved reserves, which are subject to change as a result of factors such as prices, costs and well performance. These impairment charges could have a material adverse effect on our results of operations and financial condition for the periods in which such charges are taken.

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Our operations are subject to governmental laws and regulations relating to environmental matters, which may expose us to significant costs and liabilities and could exceed current expectations. In addition, regulations relating to climate change and energy conservation may negatively impact our operations.

Our business is subject to laws and regulations that govern environmental matters. These regulations include compliance obligations for air emissions, water quality, wastewater discharge and solid and hazardous waste disposal, spill prevention, control and countermeasures, as well as regulations designed for the protection of threatened or endangered species. In some cases, our operations are subject to federal requirements for performing or preparing environmental assessments, environmental impact studies and/or plans of development before commencing exploration and production activities. In addition, our activities are subject to state regulations relating to conservation practices and protection of correlative rights. These regulations may negatively impact our operations and limit the quantity of natural gas and oil we produce and sell. We must take into account the cost of complying with such requirements in planning, designing, constructing, drilling, operating and abandoning wells and related surface facilities, including gathering, transportation, storage and waste disposal facilities. The regulatory frameworks govern, and often require permits for, the handling of drilling and production materials, water withdrawal, disposal of produced water, drilling and production wastes, operation of air emissions sources, and drilling activities, including those conducted on lands lying within wilderness, wetlands, Federal and Indian lands and other protected areas. Various governmental authorities, including the U.S. Environmental Protection Agency (EPA), the DOI, the BIA and analogous state agencies and tribal governments, have the power to enforce compliance with these laws and regulations and the permits issued under them, often requiring difficult and costly actions, such as installing and maintaining pollution controls and maintaining measures to address personnel and process safety and protection of the environment and animal habitat near our operations. Failure to comply with these laws, regulations and permits may result in the assessment of administrative, civil and criminal penalties, the imposition of remedial obligations, the imposition of stricter conditions on or revocation of permits, the issuance of injunctions limiting or preventing some or all of our operations, delays in granting permits and cancellation of leases. Our exploration and production operations in Brazil (which we expect to sell in 2014) are subject to various types of regulations similar to those described above, which are imposed by the Brazilian government, and which may affect our operations and costs within that country. Liabilities, penalties, suspensions, terminations and increased costs resulting from any failure to comply with regulations and requirements of the type described above, or from the enactment of additional similar regulations or requirements in the future or a change in the interpretation or the enforcement of existing regulations or requirements of this type, could have a material adverse effect on our business, results of operations and financial condition.

On December 15, 2009, the EPA published its findings that emissions of carbon dioxide, methane, and other GHGs present an endangerment to public health and the environment because emissions of such gases are, according to the EPA, contributing to the warming of the earth’s atmosphere and other climate changes. These findings served as a statutory prerequisite for EPA to adopt and implement regulations that would restrict emissions of GHGs under existing provisions of the Clean Air Act. The EPA has adopted two sets of related rules, one of which regulates emissions of GHGs from motor vehicles and the other of which regulates emissions of GHGs from certain large stationary sources of emissions such as power plants or industrial facilities. The EPA finalized the motor vehicle rule in April 2010 and it became effective January 2011. The EPA adopted the stationary source rule, also known as the “Tailoring Rule,” in May 2010, and it also became effective January 2011, although on October 15, 2013, the U.S. Supreme Court announced it will review aspects of the rule in 2014. Additionally, in September 2009, the EPA issued a final rule requiring the reporting of GHG emissions from specified large GHG emission sources in the U.S., including NGLs fractionators and local natural gas/distribution companies, beginning in 2011 for emissions occurring in 2010. In November 2010, the EPA expanded its existing GHG reporting rule to include onshore and offshore oil and natural gas production and onshore processing, transmission, storage and distribution facilities, which may include certain of our facilities, beginning in 2012 for emissions occurring in 2011. In addition, the EPA has continued to adopt GHG regulations of the oil and gas and other industries, such as the proposed New Source Performance Standards for new coal-fired and natural gas-fired power plants published January 8, 2014.  As a result of this continued regulatory focus, future GHG regulations of the oil and natural gas industry remain a possibility.

In addition, the U.S. Congress has from time to time considered adopting legislation to reduce emissions of GHGs and almost one-half of the states have already taken legal measures to reduce emissions of GHGs primarily through the planned development of GHG emission inventories and/or regional GHG cap and trade programs. Although the U.S. Congress has not adopted such legislation at this time, it may do so in the future and many states continue to pursue regulations to reduce greenhouse gas emissions. Most of these cap and trade programs work by requiring major sources of emissions, such as electric power plants or major producers of fuels, such as refineries and natural gas processing plants, to acquire and surrender emission allowances that correspond to their annual emissions of GHGs. The number of allowances available for purchase is reduced each year until the overall GHG emission reduction goal is achieved. As the number of GHG emission allowances declines each year, the cost or value of such allowances is expected to escalate significantly.

Regulation of GHG emissions could also result in reduced demand for our products, as oil and natural gas consumers seek to reduce their own GHG emissions. Any regulation of GHG emissions, including through a cap-and-trade system, technology mandate,

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emissions tax, reporting requirement or other program, could have a material adverse effect on our business, results of operations and financial condition. In addition, to the extent climate change results in more severe weather and significant physical effects, such as increased frequency and severity of storms, floods, droughts and other climatic effects, our own, our counterparties’ or our customers’ operations may be disrupted, which could result in a decrease in our available products or reduce our customers’ demand for our products.

Further, there have been various legislative and regulatory proposals at the federal and state levels to provide incentives and subsidies to (i) shift more power generation to renewable energy sources and (ii) support technological advances to drive less energy consumption. These incentives and subsidies could have a negative impact on oil, natural gas and NGLs consumption.

Any of the above risks could impair our ability to manage our business and have a material adverse effect on our operations, cash flows and financial position.

Our operations may be exposed to significant delays, costs and liabilities as a result of environmental and health and safety laws and regulations applicable to our business and new legislation or regulation on safety procedures in exploration and production operations could require us to adopt expensive measures and adversely impact our results of operation.

There is inherent risk in our operations of incurring significant environmental costs and liabilities due to our generation and handling of petroleum hydrocarbons and wastes, because of our air emissions and wastewater discharges, and as a result of historical industry operations and waste disposal practices. Some of our owned and leased properties have been used for oil and natural gas exploration and production activities for a number of years, often by third parties not under our control. During that time, we and/or other owners and operators of these facilities may have generated or disposed of wastes that polluted the soil, surface water or groundwater at our facilities and adjacent properties. For our non-operated properties, we are dependent on the operator for operational and regulatory compliance. We could be subject to claims for personal injury and/or natural resource and property damage (including site clean-up and restoration costs) related to the environmental, health or safety impacts of our oil and natural gas production activities, and we have been from time to time, and currently are, named as a defendant in litigation related to such matters. Under certain laws, we also could be subject to joint and several and/or strict liability for the removal or remediation of contamination regardless of whether such contamination was the result of our activities, even if the operations were in compliance with all applicable laws at the time the contamination occurred and even if we no longer own and/or operate on the properties . Private parties, including the owners of properties upon which our wells are drilled and facilities where our petroleum hydrocarbons or wastes are taken for reclamation or disposal, may also have the right to pursue legal actions to enforce compliance, as well as to seek damages for non-compliance, with environmental laws and regulations or for personal injury or property damage. We have been and continue to be responsible for remediating contamination, including at some of our current and former facilities or areas where we produce hydrocarbons. While to date none of these obligations or claims have involved costs that have materially adversely affected our business, we cannot predict with certainty whether future costs of newly discovered or new contamination might result in a materially adverse impact on our business or operations.

There have been various regulations proposed and implemented that could materially impact the costs of exploration and production operations and cause substantial delays in the receipt of regulatory approvals from both an environmental and safety perspective in the Gulf of Mexico. Although we have sold our Gulf of Mexico assets, it is possible that similar, more stringent, regulations might be enacted or delays in receiving permits may occur in other areas, such as in offshore regions of other countries (such as Brazil) and in other onshore regions of the United States (including drilling operations on other federal or state lands).

Our operations could result in an equipment malfunction or oil spill that could expose us to significant liability.

Despite the existence of various procedures and plans, there is a risk that we could experience well control problems in our operations. As a result, we could be exposed to regulatory fines and penalties, as well as landowner lawsuits resulting from any spills or leaks that might occur. While we maintain insurance against some of these risks in amounts that we believe are reasonable, our insurance coverages have material deductibles, self-insurance levels and limits on our maximum recovery and do not cover all risks. For example, from time to time we may not carry, or may be unable to obtain on terms that we find acceptable and/or reasonable, insurance coverage for certain exposures including, but not limited to, certain environmental exposures (including potential environmental fines and penalties), business interruption and named windstorm/hurricane exposures and, in limited circumstances, certain political risk exposures. The premiums and deductibles we pay for certain insurance policies are also subject to the risk of substantial increases over time that could negatively impact our financial results. In addition, we may not be able to renew existing insurance policies or procure desirable insurance on commercially reasonable terms. There is also a risk that our insurers may default on their insurance coverage obligations or that amounts for which we are insured, or that the proceeds of such insurance, will not compensate us fully for our losses. Any of these outcomes could have a material adverse effect on our business, results of operations and financial condition.

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Although we might also have remedies against our contractors or vendors or our joint working interest owners with regard to any losses associated with unintended spills or leaks the ability to recover from such parties will depend on the indemnity provisions in our contracts as well as the facts and circumstances associated with the causes of such spills or leaks. As a result, our ability to recover associated costs from insurance coverages or other third parties is uncertain.

Legislation and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays.

We use hydraulic fracturing extensively in our operations. The hydraulic fracturing process is typically regulated by state oil and natural gas commissions. Hydraulic fracturing involves the injection of water, sand and chemicals under pressure into formations to fracture the surrounding rock and stimulate production. The Safe Drinking Water Act (the SDWA) regulates the underground injection of substances through the Underground Injection Control (UIC) program. While hydraulic fracturing generally is exempt from regulation under the UIC program, the EPA has taken the position that hydraulic fracturing with fluids containing diesel fuel is subject to regulation under the UIC program as “Class II” UIC wells. On October 21, 2011, the EPA announced its intention to propose federal Clean Water Act regulations by 2014 governing wastewater discharges from hydraulic fracturing and certain other natural gas operations. In addition, the DOI published a revised proposed rule on May 24, 2013 that would update existing regulation of hydraulic fracturing activities on federal lands, including requirements for disclosure, well bore integrity and handling of flowback water. The revised proposed rule was subject to an extended 90-day public comment period, which ended on August 23, 2013 and a final rule is expected in 2014.

The EPA has commenced a study of the potential environmental impacts of hydraulic fracturing activities, and a committee of the U.S. House of Representatives is also conducting an investigation of hydraulic fracturing practices. The EPA issued a Progress Report in December 2012 and a final draft is anticipated by 2014 for peer review and public comment. As part of these studies, both the EPA and the House committee have requested that certain companies provide them with information concerning the chemicals used in the hydraulic fracturing process. These studies, depending on their results, could spur initiatives to regulate hydraulic fracturing under the SDWA or otherwise. Congress has in recent legislative sessions considered legislation to amend the SDWA, including legislation that would repeal the exemption for hydraulic fracturing from the definition of “underground injection” and require federal permitting and regulatory control of hydraulic fracturing, as well as legislative proposals to require disclosure of the chemical constituents of the fluids used in the fracturing process, were proposed in recent sessions of Congress. The U.S. Congress may consider similar SDWA legislation in the future.

On August 16, 2012, the EPA published final regulations under the Clean Air Act (CAA) that establish new air emission controls for oil and natural gas production and natural gas processing operations. Specifically, EPA promulgated New Source Performance Standards establishing emission limits for sulfur dioxide (SO2) and volatile organic compounds (VOCs). The final rule requires a 95% reduction in VOCs emitted by mandating the use of reduced emission completions or “green completions” on all hydraulically-fractured gas wells constructed or refractured after January 1, 2015. Until this date, emissions from fractured and refractured gas wells must be reduced through reduced emission completions or combustion devices. The rules also establish new requirements regarding emissions from compressors, controllers, dehydrators, storage tanks and other production equipment. In response to numerous requests for reconsideration of these rules from both industry and the environmental community and court challenges to the final rules, EPA announced its intention to issue revised rules.  For example, the EPA published revised portions of these rules on September 23, 2013 for VOCs emissions for production oil and gas storage tanks, in part phasing in emissions controls on storage tanks past October 15, 2013.

Several states have adopted, or are considering adopting, regulations that could restrict or prohibit hydraulic fracturing in certain circumstances and/or require the disclosure of the composition of hydraulic fracturing fluids. For example, Texas enacted a law requiring oil and natural gas operators to publicly disclose the chemicals used in the hydraulic fracturing process, effective as of September 1, 2011. The Texas Railroad Commission adopted rules and regulations applicable to all wells for which the Texas Railroad Commission issues an initial drilling permit on or after February 1, 2012. The new regulations require that well operators disclose the list of chemical ingredients subject to the requirements of the OSHA for disclosure on an internet website and also file the list of chemicals with the Texas Railroad Commission with the well completion report. The total volume of water used to hydraulically fracture a well must also be disclosed to the public and filed with the Texas Railroad Commission. Furthermore, on May 23, 2013, the Texas Railroad Commission issued an updated “well integrity rule,” addressing requirements for drilling, casing and cementing wells. The rule also includes new testing and reporting requirements, such as (i) clarifying the due date for cementing reports after well completion or after cessation of drilling, whichever is earlier, and (ii) the imposition of additional testing on “minimum separation wells” less than 1,000 feet below usable groundwater, which are not found in the Eagle Ford Shale or Permian Basin. The “well integrity rule” took effect in January 2014. Similarly, Utah’s Division of Oil, Gas and Mining passed a rule on October 24, 2012 requiring all oil and gas operators to disclose the amount and type of chemicals used in hydraulic fracturing

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operations using the national registry FracFocus.org. Finally, the federal BLM has proposed rules requiring similar disclosure of hydraulic fracturing fluid used on BLM lands to FracFocus.org and optionally directly to the BLM.

A number of lawsuits and enforcement actions have been initiated across the country alleging that hydraulic fracturing practices have adversely impacted drinking water supplies, use of surface water, and the environment generally. If new laws or regulations that significantly restrict hydraulic fracturing, such as amendments to the SDWA, are adopted, such laws could make it more difficult or costly for us to perform fracturing to stimulate production from tight formations as well as make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings based on allegations that specific chemicals used in the fracturing process could adversely affect groundwater. In addition, if hydraulic fracturing is further regulated at the federal or state level, our fracturing activities could become subject to additional permitting and financial assurance requirements, more stringent construction specifications, increased monitoring, reporting and recordkeeping obligations, plugging and abandonment requirements and also to attendant permitting delays and potential increases in costs. Such legislative changes could cause us to incur substantial compliance costs, and compliance or the consequences of any failure to comply by us could have a material adverse effect on our financial condition and results of operations. Until such regulations are finalized and implemented, it is not possible to estimate their impact on our business. At this time, no adopted regulations have imposed a material impact on our hydraulic fracturing operations.

Any of the above risks could impair our ability to manage our business and have a material adverse effect on our operations, cash flows and financial position.

Our Brazilian operations involve special risks.

In July 2013, we entered into a Quota Purchase Agreement relating to the sale of our Brazil operations, which is expected to close in 2014. Pending the closing of that divestiture, we will continue activities in Brazil, which are subject to the risks inherent in foreign operations and other additional risks not associated with assets located in the United States, which include:

·protracted delays in securing government consents, permits, licenses, customer authorizations or other regulatory approvals necessary to conduct our operations;

·loss of revenue, property and equipment as a result of hazards such as wars, insurrection, piracy or acts of terrorism;

·changes in laws, regulations and policies of foreign governments, including changes to tax laws and regulations and changes in the governing parties, nationalization, expropriation and unilateral renegotiation of contracts by government entities;

·difficulties in enforcing rights against government agencies, including being subject to the jurisdiction of local courts in certain instances;

·the effects of currency fluctuations and exchange controls, such as devaluation of foreign currencies, relative inflation risks, and the imposition of foreign exchange restrictions that may negatively impact convertibility and repatriation of our foreign earnings into U.S. dollars;

·protracted delays in payments and collections of accounts receivables from state-owned energy companies;

·transparency and corruption issues, including compliance issues with the U.S. Foreign Corrupt Practices Act, the United Kingdom bribery laws and other anti-corruption compliance issues; and

·laws and policies of the United States that adversely affect foreign trade and taxation.

We have certain contingent liabilities that could exceed our estimates.

We have certain contingent liabilities associated with litigation, regulatory, environmental and tax matters described in Note 8  to our consolidated financial statements and elsewhere in this 10-K. In addition, the positions taken in our federal, state, local and non-U.S. tax returns require significant judgments, use of estimates and interpretation of complex tax laws. Although we believe that we have established appropriate reserves for our litigation, regulatory, environmental and tax matters, we could be required to accrue additional amounts in the future and/or incur more actual cash expenditures than accrued for and these amounts could be material.

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We have significant capital programs in our business that may require us to access capital markets, and any inability to obtain access to the capital markets in the future at competitive rates, or any negative developments in the capital markets, could have a material adverse effect on our business.

We have significant capital programs in our business, which may require us to access the capital markets. Since we are rated below investment grade, our ability to access the capital markets or the cost of capital could be negatively impacted in the future, which could require us to forego capital opportunities or could make us less competitive in our pursuit of growth opportunities, especially in relation to many of our competitors that are larger than us or have investment grade ratings.

In addition, the credit markets and the financial services industry in recent years has experienced a period of unprecedented turmoil and upheaval characterized by the bankruptcy, failure, collapse or sale of various financial institutions and an unprecedented level of intervention from the United States government. These circumstances and events led to reduced credit availability, tighter lending standards and higher interest rates on loans. While we cannot predict the future condition of the credit markets, future turmoil in the credit markets could have a material adverse effect on our business, liquidity, financial condition and cash flows, particularly if our ability to borrow money from lenders or access the capital markets to finance our operations were to be impaired.

Although we believe that the banks participating in the RBL Facility have adequate capital and resources, we can provide no assurance that all of those banks will continue to operate as a going concerns in the future. If any of the banks in our lending group were to fail, it is possible that the borrowing capacity under the RBL Facility would be reduced. In the event of such reduction, we could be required to obtain capital from alternate sources in order to finance our capital needs. Our options for addressing such capital constraints would include, but not be limited to, obtaining commitments from the remaining banks in the lending group or from new banks to fund increased amounts under the terms of the RBL Facility, and accessing the public and private capital markets. In addition, we may delay certain capital expenditures to ensure that we maintain appropriate levels of liquidity. If it became necessary to access additional capital, any such alternatives could have terms less favorable than the terms under the RBL Facility, which could have a material adverse effect on our business, results of operations, financial condition and cash flows.

Retained liabilities associated with businesses or assets that we have sold could exceed our estimates and we could experience difficulties in managing these liabilities.

We have sold and have agreed to sell various assets and either retained certain liabilities or indemnified certain purchasers against future liabilities relating to businesses and assets sold or to be sold, including breaches of warranties, environmental expenditures, asset retirements and other representations that we have provided.  We may also be subject to retained liabilities with respect to certain divested assets by operation of law.  Although we believe that we have established appropriate reserves for any such liabilities, we could be required to accrue additional amounts in the future and these amounts could be material.

Our debt agreements contain restrictions that limit our flexibility in operating our business.

Our existing debt agreements contain, and any other existing or future indebtedness of ours would likely contain, a number of covenants that impose operating and financial restrictions on us, including restrictions on our and our subsidiaries ability to, among other things:

·incur additional debt, guarantee indebtedness or issue certain preferred shares;

·pay dividends on or make distributions in respect of, or repurchase or redeem, our capital stock or make other restricted payments;

·prepay, redeem or repurchase certain debt;

·make loans or certain investments;

·sell certain assets;

·create liens on certain assets;

·consolidate, merge, sell or otherwise dispose of all or substantially all of our assets;

·enter into certain transactions with our affiliates;

·alter the businesses we conduct;

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·enter into agreements restricting our subsidiaries’ ability to pay dividends; and

·designate our subsidiaries as unrestricted subsidiaries.

In addition, the RBL Facility requires us to comply with certain financial covenants. See Note 7 for additional discussion of the RBL covenants.

As a result of these covenants, we may be limited in the manner in which we conduct our business, and we may be unable to engage in favorable business activities or finance future operations or capital needs.

A failure to comply with the covenants under the RBL Facility or any of our other indebtedness could result in an event of default, which, if not cured or waived, could have a material adverse effect on our business, financial condition and results of operations. In the event of any such default, the lenders thereunder:

·will not be required to lend any additional amounts to us;

·could elect to declare all borrowings outstanding, together with accrued and unpaid interest and fees, to be due and payable and terminate all commitments to extend further credit; or

·could require us to apply all of our available cash to repay these borrowings.

Such actions by the lenders could cause cross defaults under our other indebtedness. If we were unable to repay those amounts, the lenders or holders under the RBL Facility and our other secured indebtedness could proceed against the collateral granted to them to secure that indebtedness. We pledged a significant portion of our assets as collateral under the RBL Facility, our senior secured term loan and our senior secured notes.

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ITEM 1B.UNRESOLVED STAFF COMMENTS

None.

ITEM 2.PROPERTIES

A description of our properties is included in Part I, Item 1, Business.

ITEM 3.LEGAL PROCEEDINGS

A description of our material legal proceedings is included in Part II, Item 8, Financial Statements and Supplementary Data, Note 8, and is incorporated herein by reference.

ITEM 4.MINE SAFETY DISCLOSURES

Not applicable.

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

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

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

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

The internal review indicates that, in  February 2013, CEVA Freight Holdings (Malaysia) SDN BHD (CEVA Malaysia) provided customs brokerage for export and local haulage services for a shipment of polyethylene resin to Iran shipped on a vessel owned and/or operated by HDS Lines, also an SDN.  The revenues and net profits for these services were approximately $779.54 USD and $311.13 USD, respectively.  In September 2013, CEVA Malaysia provided customs brokerage services for the import into Malaysia of fruit juice from Alifard Co. in Iran via HDS Lines.  The revenues and net profits for these services were approximately $227.41 USD and $89.29 USD, respectively.

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

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PART II

ITEM 5.MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES.

Our equity securities are privately held by our sole member and thus there is no established public trading market for our membership interests.

ITEM 6.SELECTED HISTORICAL CONSOLIDATED FINANCIAL DATA

Set forth below is our selected historical consolidated financial data for the periods and as of the dates indicated.  We have derived the selected historical consolidated balance sheet data as of December 31, 2013 and December 31, 2012 and the statements of income data  and statements of cash flow data for the year ended December 31, 2013, for the period from March 23 to December 31, 2012, the period from January 1, 2012 through May 24, 2012 and the year ended December 31, 2011, from  the audited consolidated financial statements of EP Energy LLC included in this Report on Form 10-K.  We have derived the selected historical consolidated balance sheet data as of December 31, 2011, 2010 and 2009, and the statements of income data and statements of cash flow data for the years ended December 31, 2010 and 2009 from the consolidated historical predecessor financial statements of EP Energy LLC, which are not included in this Report on Form 10-K.  All financial statement periods present our Brazil operations as discontinued operations.  Financial statement periods after May 24, 2012 (successor periods) also present certain domestic natural gas assets sold as discontinued operations.  See Item 8. “Financial Statements and Supplementary Data”, Note 2. “Acquisitions and Divestitures”, for further discussion.

The following selected historical financial data should be read in conjunction with Item 7, “Management’s Discussion and Analysis of Financial Condition” and “Results of Operations” and Item 8, “Financial Statements and Supplementary Data” included in this Report on Form 10-K.

	Successor										Predecessor
		Year ended  December 31,				March 23 (inception), to December 31,					January 1, to May 24,				For Years ended December 31,
		2013				2012					2012				2011					2010					2009
											(in millions)
Results of Operations
Operating revenues		$	1,640			$		727			$		932		$	1,756				$	1,704				$	1,803
Operating income (loss)		381				(66				)	338				648					738					(1,231		)
Interest expense		(321			)	(218				)	(14			)	(14				)	(23				)	(27		)
Income (loss) from continuing operations		39				(299				)	187				385					451					(823		)
Cash Flow
Net cash provided by (used in):
Operating activities		$	975			$		449			$		580		$	1,426				$	1,067				$	1,573
Investing activities		(475			)	(7,893				)	(628			)	(1,237				)	(1,130				)	(1,156		)
Financing activities		(515			)	7,507					110				(238				)	(46				)	(336		)
		As of December 31,									As of December 31,
		2013					2012				2011						2010					2009
											(in millions)
Financial Position
Total assets		$		8,326			$		8,293		$	5,103					$	4,942				$	4,457
Long-term debt		4,039					4,346				851						301					835
Member’s/Stockholder’s equity		3,455					3,085				3,100						3,067					2,529

Factors Affecting Trends. In May 2012, the Sponsors acquired us for approximately $7.2 billion with approximately $3.3 billion in equity contributions and the issuance of $4.25 billion of debt.  For the period ended December 31, 2013 and the period from March 23 (inception) to December 31, 2012, we recorded realized and unrealized losses on financial derivatives included in operating revenues of $52 million and $62 million respectively, in addition in the period from March 23 (inception) to December 31, 2012, we recorded restructuring costs of $221 million.  For the period from January 1 to May 24, 2012, and for the years ended December 31,

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2011, 2010 and 2009 we recorded realized and unrealized gains on financial derivatives included in operating revenues of $365 million, $284 million, $390 million and $687 million, and non-cash ceiling test and other impairment charges of $62 million, $6 million, $25 million and $2.1 billion, respectively.

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ITEM 7.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 8 of this Annual Report on Form 10-K. This discussion contains forward-looking statements and involves numerous risks and uncertainties, including, but not limited to, those described in “Risk Factors”.  Our actual results may differ materially from those contained in any forward-looking statements. See “Cautionary Statement Regarding Forward-Looking Statements” in the front of this report. Additionally, the financial results for the successor period subsequent to the Acquisition 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.  All periods included in these financial statements present our Brazil operations as discontinued operations. The successor periods present certain domestic natural gas assets sold, including the CBM, South Texas and the majority of our Arklatex assets as discontinued operations.  Predecessor periods do not present these domestic sales as discontinued operations due to the application of the full cost method of accounting prior to the Acquisition.  As a result of these differences in presentation, trends and results in future periods may be different than those that existed prior to the Acquisition.  Unless otherwise indicated or the context otherwise requires, references in this MD&A section to “we”, “our”, “us” and “the Company” refer to both EP Energy LLC (the “Successor”) and EP Energy Global LLC (the “Predecessor” for accounting purposes), and each of its consolidated subsidiaries.

Our Business

Overview.  We are an independent exploration and production company engaged in the acquisition and development of unconventional onshore oil and natural gas properties in the United States. We are focused on creating shareholder value through the development of our low-risk drilling inventory located in our four core areas: the Eagle Ford Shale (South Texas), the Wolfcamp Shale (Permian Basin in West Texas), Altamont field in the Uinta Basin (Northeastern Utah) and the Haynesville Shale (North Louisiana).  We also have other domestic activities in Texas and Louisiana.  Below are summary descriptions of each of our core programs:

·Eagle Ford Shale. The Eagle Ford Shale provides the highest economic returns in our portfolio.

·Wolfcamp Shale. In our Wolfcamp Shale program, we are focused on optimizing our drilling, completion and artificial lift systems.

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

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

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

During 2013, we sold certain of our natural gas properties, including CBM properties located in the Raton, Black Warrior and Arkoma basins; the majority of our Arklatex natural gas properties; our natural gas properties in South Texas and our interests in Four Star Oil & Gas Company (Four Star). The total consideration from these transactions was approximately $1.5 billion. In July 2013, certain of our subsidiaries entered into a Quota Purchase Agreement relating to the sale of all of our Brazil operations. This transaction represents the sale of all of our remaining international assets and is expected to close in 2014, subject to Brazilian regulatory approval and certain other customary closing conditions.

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

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

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

·managing cash costs; and

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

In addition to these factors, our future profitability and performance will be affected by our ability to execute our strategy, volatility in the financial and commodity markets, changes in the cost of drilling and oilfield services, operating and capital costs and our debt level and related interest costs. Additionally, we may be impacted by weather events, or domestic or international regulatory issues or other third party actions outside of our control (e.g., oil spills).

To the extent possible, we attempt to mitigate certain of these risks through actions such as entering into longer term contractual arrangements to control costs and entering into derivative contracts to stabilize cash flows and reduce the financial impact of downward commodity price movements on commodity sales.  In addition, because we apply mark-to-market accounting, our reported results of operations, financial position and cash flows can be impacted significantly by commodity price movements from period to period. Adjustments to our strategy and the decision to enter into new positions or to alter existing positions are made based on the goals of the overall company.

Derivative Instruments.  During 2013, approximately 94% of our liquids production and 91% of our natural gas production were hedged and settled at average floor prices of $100.01 per barrel and $3.49 per MMBtu, respectively. The following table reflects the contracted volumes and the prices we will receive under derivative contracts we held as of December 31, 2013.

	2014			2015			2016
	Volumes(1)	Average Price(1)		Volumes(1)	Average Price(1)		Volumes(1)	Average Price(1)
Oil
Fixed Price Swaps
WTI	12,757	$	97.06	19,928	$	90.12	5,216	$	85.25
Brent	3,339	$	102.54	—	$	—	—	$	—
Ceilings	1,126	$	100.00	1,095	$	100.00	—	$	—
Three Way Collars
Ceiling - WTI	2,920	$	103.76	—	$	—	—	$	—
Floors - WTI(2)	2,920	$	95.00	—	$	—	—	$	—
Ceiling - Brent	—	$	—	1,095	$	110.02	—	$	—
Floors - Brent(3)	—	$	—	1,095	$	100.00	—	$	—
Basis Swaps	5,840	$	Various	3,650	$	Various	1,830	$	Various
Natural Gas
Fixed Price Swaps	76	$	4.02	51	$	4.26	7	$	4.20

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

(2)If market prices settle at or below $75.00 in 2014, we will receive a “locked-in” cash settlement of the market price plus $20.00 per Bbl.

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

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The following table reflects the volumes and the prices associated with derivative contracts entered into between January 1, 2014 and February 24, 2014, which are not reflected in the table above.

	2014			2015			2016
	Volumes(1)	Average Price(1)		Volumes(1)	Average Price(1)		Volumes(1)	Average Price(1)
Oil
Fixed Price Swaps
Brent	160	$	108.44	2,555	$	100.01	4,026	$	95.01
LLS(2)	—	$	—	—	$	—	2,562	$	93.96
Basis Swaps	1,557	$	Various	—	$	—	183	$	Various
Natural Gas
Fixed Price Swaps	—	$	—	4	$	4.20	—	$	—
NGLs
Propane Fixed Price Swaps	28	$	1.14	—	$	—	—	$	—
Propane Collars
Ceilings	14	$	1.30	—	$	—	—	$	—
Floors	14	$	1.00	—	$	—	—	$	—

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

(2)In January 2014, we unwound 2,555 MBbls of 2015 WTI fixed price swaps in exchange for 2,562 MBbls of 2016 LLS fixed price swaps. No cash or other considerations was included as part of this exchange.

Summary of Liquidity and Capital Resources.  As of December 31, 2013, we had available liquidity, including existing cash, of approximately $2.25 billion. We believe we have sufficient liquidity for 2014 from our cash flows from operations, combined with the availability under our RBL Facility and available cash, to fund our current obligations, projected working capital requirements and capital spending plan.  Additionally, the earliest maturity date of our debt obligations is in 2017. See “Liquidity and Capital Resources” for more information.

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

·Capital expenditures of approximately $2 billion, or a 4% increase from 2013, allocated entirely to our core oil programs: $1 billion for Eagle Ford, $680 million for Wolfcamp and $240 million for Altamont.

·20% increase in well completions from 2013 to between 265 and 290.

·Average daily production volumes for the year of approximately 94.5 MBoe/d to 102.5 MBoe/d, including average daily oil production volumes of approximately 50 MBbls/d to 54 MBbls/d.

·Per unit adjusted cash operating costs for the year of approximately $12.25 to $14.35 per Boe, and transportation costs of $3.00 to $3.50 per Boe.

·Per unit depreciation, depletion and amortization rate for the year of approximately $24.00 to $26.00 per Boe.

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Production Volumes and Drilling Summary

Production Volumes.  Below is an analysis of our production volumes by area and commodity for the years ended December 31:

	2013	2012	2011
United States (MBoe/d)
Eagle Ford Shale	37	20	7
Wolfcamp Shale	5	2	1
Altamont	12	11	9
Haynesville Shale	27	48	44
Other	5	7	7
Core areas and other	86	88	68
Divested assets(1)	—	20	56
Total Consolidated	86	108	124
Unconsolidated affiliate (MBoe/d)(2)	6	9	10
Total Combined (MBoe/d)	92	117	134
Oil and condensate (MBbls/d)
Core areas and other volumes	37	24	12
Divested assets(1)	—	1	3
Unconsolidated affiliate volumes(2)	1	1	1
Total Combined	38	26	16
Natural Gas (MMcf/d)
Core areas and other volumes	253	368	328
Divested assets(1)	—	108	304
Unconsolidated affiliate volumes(2)	28	42	46
Total Combined	281	518	678
NGLs (MBbls/d)
Core areas and other volumes	7	3	1
Divested assets(1)	—	1	2
Unconsolidated affiliate volumes(2)	1	1	1
Total Combined (MBbls/d)	8	5	4

(1)

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

(2)

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

·Eagle Ford Shale—Our Eagle Ford Shale equivalent volumes and oil production increased 17 MBoe/d (85%) and 10 MBbls/d (75%), respectively, for the year ended December 31, 2013 compared to 2012 due to the success of our drilling program in the area.  In the fourth quarter of 2013 combined Eagle Ford oil and NGLs production increased to approximately 34 MBbls/d compared with approximately 33 MBbls/d during the third quarter of 2013. During 2013, we drilled 136 additional operated wells in the Eagle Ford, and we had a total of 270 net operated wells as of December 31, 2013. With a majority of our acreage located in the core of the oil window, primarily in LaSalle and Atascosa counties, we continue to grow our oil and NGLs production in the area.

·Wolfcamp Shale—Our Wolfcamp Shale equivalent volumes increased 3 MBoe/d (150%) for the year ended December 31, 2013 compared to 2012 as we continue to progress the development of the program. During 2013, we drilled 68 additional operated wells, for a total of 99 net operated wells as of December 31, 2013.

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·Altamont—Our Altamont equivalent volumes increased 1 MBoe/d (9%) for the year ended December 31, 2013 compared to 2012. Altamont produced an average of 9 MBbls/d of oil during 2013, and we drilled an additional 27 operated oil wells for a total of 318 net operated wells at December 31, 2013.

·Haynesville Shale—Our Haynesville Shale equivalent volumes decreased 126 MMcf/d (44%) for the year ended December 31, 2013 compared to 2012, due to natural declines as we suspended our drilling program at the end of the first quarter of 2012 as a result of low natural gas prices. As of December 31, 2013, we had 99 net operated wells in the Haynesville Shale, and our total production for 2013 was approximately 163 MMcf/d.

·Divested assets—Our divested assets were reclassified as discontinued operations in periods after May 24, 2012 and thus volumes related to these assets are not reflected in the successor periods of the table above. Equivalent volumes of divested assets in predecessor periods prior to May 24, 2012 relate to volumes for our divested CBM, south Texas, Arklatex and Gulf of Mexico assets, which were not reflected as discontinued operations.

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Reserve Replacement Ratio/Reserve Replacement Costs

We calculate two primary non-GAAP metrics associated with reserves performance: (i) a reserve replacement ratio and (ii) reserve replacement costs, to measure our ability to establish a trend of adding reserves at a reasonable cost in our drilling programs. The reserve replacement ratio is an indicator of our ability to replenish annual production volumes and grow our reserves. It is important for us to economically find and develop new reserves that will more than offset produced volumes and provide for future production given the inherent decline of hydrocarbon reserves. In addition, we calculate reserve replacement costs to assess the cost of adding reserves, which is ultimately included in depreciation, depletion and amortization expense. We believe the ability to develop a competitive advantage over other oil and natural gas companies is dependent on adding reserves at lower costs than our competition. We calculate these metrics as follows:

Reserve replacement ratio	Sum of reserve additions(1)
	Actual production for the corresponding period
Reserve replacement costs/Boe	Total oil and natural gas capital costs(2)
	Sum of reserve additions (1)

(1)

Reserve additions include proved reserves and reflect reserve revisions for prices and performance, extensions, discoveries and other additions and acquisitions and do not include unproved reserve quantities. We present these metrics separately, both including and excluding the impact of price revisions on reserves, to demonstrate the effectiveness of our drilling program exclusive of economic factors (such as price) outside of our control. All amounts are derived directly from the table presented in Financial Statements and Supplementary Data—Supplemental Oil and Natural Gas Operations.

(2)

Total oil and natural gas capital costs include the costs of development, exploration and property acquisition activities conducted to add reserves and exclude asset retirement obligations. Amounts are derived directly from the table presented in Financial Statements and Supplementary Data—Supplemental Oil and Natural Gas Operations which includes both successor and predecessor capital costs. For 2012, capital costs utilized in this ratio reflect the combined predecessor and successor periods as further described in Results of Operations below. We do not include estimated future capital costs for the development of proved undeveloped reserves in our calculation of reserve replacement costs.

The reserve replacement ratio and reserve replacement costs per unit are statistical indicators that have limitations, including their predictive and comparative value. As an annual measure, the reserve replacement ratio is limited because it typically varies widely based on the extent and timing of new discoveries, project sanctioning and property acquisitions. In addition, since the reserve replacement ratio does not consider the cost or timing of developing future production of new reserves, it cannot be used as a measure of value creation.

The exploration for and the acquisition and development of oil and natural gas reserves is inherently uncertain as further discussed in Risk Factors—Risks Related to Our Business and Industry. One of these risks and uncertainties is our ability to spend sufficient capital to increase our reserves. While we currently expect to spend such amounts in the future, there are no assurances as to the timing and magnitude of these expenditures or the classification of the proved reserves as developed or undeveloped. At December 31, 2013, proved developed reserves represented approximately 33% of our total proved reserves. Proved developed reserves will generally begin producing within the year they are added, whereas proved undeveloped reserves generally require additional future expenditures.

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The table below shows our reserve replacement ratio and reserve replacement costs, including and excluding the effect of price revisions on reserves, for our domestic operations for each of the years ended December 31:

	Including Price Revisions									Excluding Price Revisions(1)
	2013			2012			2011			2013			2012			2011
Reserve Replacement Ratios(2)	476		%	47		%	416		%	464		%	298		%	418		%
Proved Developed Reserves(3)	33		%	46		%	48		%	33		%	46		%	48		%
Proved Undeveloped Reserves(3)	67		%	54		%	52		%	67		%	54		%	52		%
Reserve Replacement Costs(2)(4) ($/Boe)	$	12.62		$	67.56		$	8.52		$	12.95		$	10.74		$	8.46

(1)                   Final reported proved undeveloped reserves generated positive undiscounted cash flow in each respective report year.

(2)                   No acquisitions are included in our reserve replacement ratio or reserve replacement costs as any such amounts are immaterial to the amounts presented.

(3)                   Represents our net proved reserve percentage by classification based on our internal reserve reports.

(4)                   Proved and unproved leasehold costs are included in all calculations.

We typically cite reserve replacement costs in the context of a multi-year trend, in recognition of its limitation as a single year measure, and also to demonstrate consistency and stability, which are essential to our business model. The table below shows our reserve replacement costs for our domestic operations for the three years ended December 31, 2013.

	Including Price Revisions	Excluding Price Revisions
	Three years ended December 31, 2013
	($/Boe)
Reserve Replacement Costs	$13.94	$10.52

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Results of Operations

The information below reflects financial results for EP Energy LLC for the year ended December 31, 2013, for the period from March 23 (inception) to December 31, 2012, for the period from January 1 to May 24, 2012 and for the year ended December 31, 2011. Beginning with the Acquisition on May 24, 2012, our financial results reflect the application of the acquisition method of accounting, the application of the successful efforts method of accounting for oil and natural gas properties, and the presentation of certain domestic natural gas assets divested in 2013 and the pending sale of our Brazilian operations as discontinued operations. For periods prior to the Acquisition or the predecessor periods, we have not reflected these divested domestic natural gas assets as discontinued operations since they did not qualify as such for accounting purposes under the full cost accounting method applied by the predecessor during those periods. We have reflected our Brazilian operations as discontinued operations in all periods. As a result, trends and results in future periods are different than those prior to the Acquisition.

Prior to the Acquisition, we had no independent oil and gas operations, and accordingly there were no operational exploration and production activities that changed as a result of the Acquisition.  Consequently, in certain period-to-period explanations that follow we have provided supplemental information that compares (i) results for the year ended December 31, 2013 with results for the successor period from March 23 (inception) to December 31, 2012 and for the predecessor period from January 1 to May 24, 2012 on a combined basis and excluding divested assets (such combined period is referred to as the “combined year ended December 31, 2012”) and (ii) results from the combined year ended December 31, 2012 with results for the year ended December 31, 2011, excluding divested assets. We have provided this additional analysis for comparability of results and to aid in the analysis and understanding of our operating performance period over period. Any non-GAAP analysis is provided as supplemental financial information to our GAAP results and is not intended to be a substitute for our reported successor and predecessor period GAAP results.

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The information in the table below provides summary GAAP financial results by each of the periods presented.

	Year-to-Date Periods
	2013			2012						2011
	Successor						Predecessor
	Year ended December 31			March 23(inception) to December 31			January 1 to May 24			Year ended December 31
	(in millions)
Operating revenues:
Oil and condensate	$	1,283		$	523		$	310		$	513
Natural gas	331			234			228			901
NGLs	78			32			29			58
Total physical sales	1,692			789			567			1,472
Financial derivatives	(52		)	(62		)	365			284
Total operating revenues	1,640			727			932			1,756
Operating expenses:
Natural gas purchases	25			19			—			—
Transportation costs	92			51			45			85
Lease operating expenses	163			71			80			177
General and administrative expenses	228			358			69			185
Depreciation, depletion and amortization	618			209			307			579
Impairment and ceiling test charges	2			1			62			6
Exploration expense	45			43			—			—
Taxes, other than income taxes	86			41			31			76
Total operating expenses	1,259			793			594			1,108
Operating income (loss)	381			(66		)	338			648
Loss from unconsolidated affiliates	(13		)	(1		)	(5		)	(7		)
Other income	1			—			2			1
Loss on extinguishment of debt	(9		)	(14		)	—			—
Interest expense	(321		)	(218		)	(14		)	(14		)
Income (loss) from continuing operations before income tax	39			(299		)	321			628
Income tax expense	—			—			134			243
Income (loss) from continuing operations	39			(299		)	187			385
Income (loss) from discontinued operations, net of tax	510			44			(9		)	(123		)
Net income (loss)	$	549		$	(255	)	$	178		$	262

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Operating Revenues

The table below provides our operating revenues, volumes and prices per unit for the year ended December 31, 2013, for each of the successor and predecessor periods in 2012, and for the predecessor 2011 period. We present (i) average realized prices based on physical sales of oil and condensate, natural gas and NGLs as well as (ii) average realized prices inclusive of the impacts of financial derivative settlements and premiums which reflect cash received or paid during the respective period.

	Year-to-Date Periods
	2013			2012					2011
	Successor						Predecessor
	Year ended December 31			March 23 to December 31			January 1 to May 24		Year ended December 31
	(in millions)
Operating revenues(1):
Oil and condensate	$	1,283		$	523		$	310	$	513
Natural gas	331			234			228		901
NGLs	78			32			29		58
Total physical sales	1,692			789			567		1,472
Financial derivatives	(52		)	(62		)	365		284
Total operating revenues	$	1,640		$	727		$	932	$	1,756
Volumes(1):
Oil and condensate
Consolidated volumes (MBbls)	13,515			5,896			3,105		5,680
Unconsolidated affiliate volumes (MBbls)(2)	197			167			115		306
Natural gas
Consolidated volumes (MMcf)	92,239			79,429			94,847		230,669
Unconsolidated affiliate volumes (MMcf)(2)	10,050			9,242			6,310		16,881
NGLs
Consolidated volumes (MBbls)	2,541			940			673		1,068
Unconsolidated affiliate volumes (MBbls)(2)	327			288			190		556
Equivalent volumes
Consolidated MBoe	31,429			20,074			19,586		45,193
Unconsolidated affiliate MBoe(2)	2,199			1,995			1,357		3,675
Total Combined MBoe	33,628			22,069			20,943		48,868
Consolidated MBoe/d	86			91			135		124
Unconsolidated affiliate MBoe/d(2)	6			9			9		10
Total Combined MBoe/d	92			100			144		134
Consolidated prices per unit(3):
Oil and condensate
Average realized price on physical sales ($/Bbl)	$	94.97		$	88.80		$	99.76	$	90.22
Average realized price, including financial derivatives ($/Bbl)(4)	$	97.72		$	95.92		$	99.61	$	88.98
Natural gas
Average realized price on physical sales ($/Mcf)	$	3.31		$	2.70		$	2.40	$	3.91
Average realized price, including financial derivatives ($/Mcf)(4)	$	3.02		$	4.90		$	4.15	$	5.37
NGLs
Average realized price on physical sales ($/Bbl)	$	30.81		$	33.83		$	42.94	$	53.50

(1)	Operating revenues and volumes in the successor periods do not include amounts associated with domestic natural gas assets sold and all periods do not include Brazilian operations held for sale at December 31, 2013, as such amounts are included as discontinued operations.
(2)	In September 2013, we sold our equity investment in Four Star.
(3)	Natural gas prices for the year ended December 31, 2013 and from March 23 to December 31, 2012 are calculated including a reduction of $25 million and $19 million, respectively, for natural gas purchases associated with managing our physical sales.
(4)	The successor periods for the year ended December 31, 2013 and from March 23 to December 31, 2012 include approximately $28 million of cash paid and approximately $175 million of cash received for the settlement of natural gas financial derivatives. The predecessor periods from January 1 to May 24, 2012 and for the year ended December 31, 2011 include approximately $165 million and $338 million, respectively, of cash received for the settlement of natural gas financial derivatives. The successor periods for the year ended December 31, 2013 and from March 23 to December 31, 2012 include approximately $29 million and $45 million, respectively, of cash receipts for the settlement of crude oil derivative contracts. The year ended December 31, 2011 included approximately $7 million, of cash paid for the settlement of crude oil derivative contracts.

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Physical sales.  Physical sales represent accrual-based commodity sales transactions with customers. For the year ended December 31, 2013, overall increases in physical sales were due primarily to oil volume growth from our Eagle Ford and Wolfcamp drilling programs, partially offset by decreases in natural gas sales volumes primarily due to a decrease in volumes in Haynesville.

Oil and condensate sales for the year ended December 31, 2013, compared to the combined year ended December 31, 2012, increased by $450 million (54%), mainly from growth in our Eagle Ford drilling program. In 2013, Eagle Ford oil and condensate production volumes increased by 75% (10 MBbls/d) compared with the combined year ended December 31, 2012.  In addition, Wolfcamp oil and condensate production volumes increased by 168% (2 MBbls/d). For the combined year ended December 31, 2012, oil and condensate sales increased by $320 million compared to 2011 attributable to a 62% increase (11 MBbls/d) in consolidated oil volumes in our Eagle Ford, Wolfcamp and Altamont core areas.

Natural gas sales for the year ended December 31, 2013 and for the successor period from March 23 to December 31, 2012, were $331 million and $234 million, respectively. For the predecessor period from January 1 to May 24, 2012, natural gas sales were $228 million (including approximately $88 million of natural gas sales related to divested assets). Natural gas sales (excluding amounts related to divested assets) decreased for the year ended December 31, 2013 compared with the combined year ended December 31, 2012, due to the decrease in volumes in Haynesville, partially offset by higher natural gas prices. During the first quarter of 2012, we suspended our drilling program in the Haynesville Shale due to low natural gas prices.  Natural gas sales (excluding amounts related to divested assets in both periods) decreased for the combined year ended December 31, 2012 compared with 2011 primarily due to lower natural gas prices.

NGLs sales increased for the year ended December 31, 2013 compared with the combined year ended December 31, 2012. Although average realized prices for the year ended December 31, 2013 decreased compared to the same period in 2012; this was more than offset by an increase in 2013 in NGLs volumes over 2012 primarily as a result of our Eagle Ford drilling program. Eagle Ford NGLs volumes increased by 128% (3 MBbls/d) over the year ended December 31, 2012. For the combined year ended December 31, 2012, NGLs sales increased by $3 million compared to 2011 primarily again as a result of Eagle Ford.

As of December 31, 2013, the NYMEX spot price of a barrel of oil was $98.42 versus the NYMEX spot price of natural gas of $4.23, or a ratio of 23 to 1. We have and will continue to target increases in our oil volumes due to this value difference, but we also expect volumes of natural gas to decline with less capital focus in this area. Growth in our revenue will largely be impacted by our ability to grow our oil volumes and by changes in oil prices.

Gains or losses on financial derivatives.  We record gains or losses due to cash settlements and changes in the fair value of our derivative contracts based on forward commodity prices relative to the prices in the underlying contracts. During the year ended December 31, 2013, we recorded $52 million of derivative losses compared to a derivative gain of $303 million during the combined year ended December 31, 2012.  Realized and unrealized gains for the combined year ended December 31, 2012 increased by $19 million compared to 2011.

Operating Expenses

Transportation costs.  Transportation costs for the year ended December 31, 2013 and for the successor period from March 23 to December 30, 2012 were $92 million and $51 million, respectively, and for the predecessor period from January 1 to May 24, 2012 were $45 million (including $18 million of transportation costs related to divested assets). Total transportation costs (excluding amounts related to the divested assets) have increased over the three year period beginning in 2011 due to oil transportation costs associated with Eagle Ford as a result of our production growth and new transportation contracts in that area.

Lease operating expense.  Lease operating expense for the year ended December 31, 2013 and for the successor period from March 23 to December 31, 2012 were $163 million and $71 million, respectively, and for the predecessor period from January 1 to May 24, 2012 were $80 million (including $31 million of lease operating expense related to divested assets). Total lease operating expense (excluding amounts related to the divested assets) for the year ended December 31, 2013 increased as compared to the combined year ended December 31, 2012 due to increased equipment and chemical costs in our Eagle Ford play and higher maintenance, repair and power costs. Lease operating expense (excluding amounts related to divested assets) for the combined year ended December 31, 2012 increased $57 million compared to 2011 due to increased water disposal, equipment and chemical costs in Eagle Ford as activity ramped up in that area.

35

General and administrative expenses.  General and administrative expenses for the year ended December 31, 2013 decreased $199 million compared to the combined year ended December 31, 2012. The decrease was primarily due to transition and restructuring costs of $221 million ($173 million of acquisition related costs and $48 million of transition and severance costs) recorded in 2012 as a result of the Acquisition, partly offset by an increase of $11 million in management consulting and advisory service charges reflected for the year ended December 31, 2013.  On January 1, 2014, we paid a non-refundable quarterly installment of $6.25 million under an amended and restated management fee agreement.  In connection with our parent’s initial public offering on January 23, 2014, the amended and restated management fee agreement was terminated.  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.  General and administrative expenses for the combined year ended December 31, 2012 increased $242 million compared to 2011 primarily due to the transition and restructuring costs of $221 million in 2012 in conjunction with the Acquisition.

Depreciation, depletion and amortization expense.  Our depreciation, depletion and amortization costs increased during the year ended December 31, 2013 compared with 2012 due to the ongoing development of higher cost oil programs (e.g. Eagle Ford and Wolfcamp) as well as the step up in 2012 in the book basis of our oil and natural gas assets as a result of the Acquisition.  For the year ended December 31, 2012 depreciation, depletion and amortization decreased compared to 2011 due to an average lower depletion rate following the application of the successful efforts method of accounting for oil and natural gas properties, partially offset by higher production volumes. Due to the ongoing development of higher cost liquids programs, we expect our depletion rate will continue to increase as compared to our current levels. Our average depreciation, depletion and amortization costs per unit for the year-to-date periods were:

	Year-to-Date Periods
	2013		2012				2011
	Successor				Predecessor
	Year ended December 31		March 23 to December 31		January 1 to May 24		Year ended December 31
Depreciation, depletion and amortization ($/Boe)(1)	$	19.65	$	10.42	$	15.66	$	12.81

(1) Includes $0.11 per Boe for the year ended December 31, 2013, $0.13 per Boe for the successor period from March 23 to December 31, 2012, $0.23 per Boe and $0.25 per Boe for the predecessor period from January 1 to May 24, 2012 and the year ended December 31, 2011 related to accretion expense on asset retirement obligations.

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

Prior to the Acquisition in May 2012, the predecessor used the full cost method of accounting. Under this method of accounting, quarterly ceiling tests of capitalized costs were conducted in each of the full cost pools and costs outside of the full cost depletion base were periodically assessed for impairment. During the predecessor period from January 1, 2012 to May 24, 2012, the predecessor recorded a non-cash charge of approximately $62 million as a result of the decision to end exploration activities in Egypt. In June of 2012, the predecessor sold all its interests in Egypt.  During the year ended December 31, 2011 the predecessor recorded a non-cash charge of approximately $6 million impairment of certain oil field related equipment and supplies.

Exploration expense.  For the year ended December 31, 2013 we recorded $45 million of exploration expense compared to $43 million for the successor period from March 23 to December 31, 2012.  Exploration expense is the result of applying the successful efforts method of accounting following the Acquisition. Prior to the Acquisition, exploration costs were capitalized under full cost accounting. Included in exploration expense for the year ended December 31, 2013 is $36 million of amortization of unproved leasehold costs.

Taxes, other than income taxes.  Taxes, other than income taxes for the year ended December 31, 2013 and for the successor period from March 23 to December 31, 2012, were $86 million and $41 million, respectively, and for the predecessor period from January 1 to May 24, 2012 were $31 million (including approximately $9 million of taxes, other than income taxes related to divested assets).  Production taxes increased in 2013 over the combined period in 2012 due to higher production volumes. Additionally, year-to-date production taxes in 2013 reflect a reduction in sales and use tax of $13 million recorded in the second quarter of 2013 associated with settling a Texas sales and use tax audit.  Taxes, other than income taxes (excluding amounts related to divested assets) for the combined year ended December 31, 2012 increased compared to 2011 primarily due to higher severance and ad valorem taxes associated with higher oil production volumes and 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, natural gas purchases, 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, transaction, management and other fees paid to the Sponsors (which terminated on January 23, 2014), and non-cash compensation expense. We believe cash operating costs and adjusted cash operating costs per unit are valuable measures of operating performance and efficiency; however, these measures may not be comparable to similarly titled measures used by other companies. The table below represents a reconciliation of our cash operating costs and adjusted cash operating costs to operating expenses for the year-to-date periods below:

	Year-to-Date Periods
	2013						2012												2011
	Successor												Predecessor
	Year ended December 31						March 23 (inception) to December 31						January 1 to May 24						Year ended December 31
	Total			Per Unit(1)			Total			Per Unit(1)			Total			Per Unit(1)			Total			Per Unit(1)
	(in millions, except per unit costs)
Total continuing operating expenses	$	1,259		$	40.07		$	793		$	39.52		$	594		$	30.32		$	1,108		$	24.51
Depreciation, depletion and amortization	(618		)	(19.65		)	(209		)	(10.42		)	(307		)	(15.66		)	(579		)	(12.81		)
Transportation costs	(92		)	(2.95		)	(51		)	(2.55		)	(45		)	(2.32		)	(85		)	(1.87		)
Exploration expense	(45		)	(1.43		)	(43		)	(2.15		)	—			—			—			—
Natural gas purchases	(25		)	(0.80		)	(19		)	(0.97		)	—			—			—			—
Impairment and ceiling test charges	(2		)	(0.06		)	(1		)	(0.06		)	(62		)	(3.15		)	(6		)	(0.16		)
Total continuing cash operating costs	477			15.18			470			23.37			180			9.19			438			9.67
Transition/restructuring costs, non-cash compensation expense and other(2)	(64		)	(2.04		)	(266		)	(13.24		)	(11		)	(0.58		)	(27		)	(0.58		)
Total adjusted cash operating costs and adjusted per-unit cash costs(2)	$	413		$	13.14		$	204		$	10.13		$	169		$	8.61		$	411		$	9.09
Total equivalent volumes (MBoe)(3)	31,429						20,074						19,586						45,193

(1)	Per Boe costs are based on actual total amounts rather than the rounded totals presented.
(2)	For the year ended December 31, 2013, includes $7 million of transition and severance costs associated with asset divestitures, management and other fees paid to our Sponsors of $26 million and $31 million of non-cash compensation expense. The period from March 23 (inception) to December 31, 2012 includes transition and severance costs of $215 million, management fees paid to our Sponsors of $16 million and $35 million of non-cash compensation expense. The predecessor period from January 1 to May 24, 2012 includes severance costs of $5 million and $6 million of non-cash compensation expense. The year ended December 31, 2011 includes $6 million of restructuring costs associated with the closure of our Denver office and $21 million of non-cash compensation expense.
(3)	Excludes volumes associated with Four Star.

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

	Year-to-Date Periods
	2013			2012						2011
	Successor						Predecessor
	Year ended December 31			March 23 (inception) to December 31			January 1 to May 24			Year ended December 31
Average cash operating costs ($/Boe)
Lease operating expenses	$	5.19		$	3.53		$	4.07		$	3.89
Production taxes(1)	2.90			1.98			1.79			1.53
General and administrative expenses	7.25			17.80			3.53			4.10
Taxes, other than production and income taxes	(0.16		)	0.06			(0.20		)	0.15
Total cash operating costs	15.18			23.37			9.19			9.67
Transition/restructuring costs, non-cash compensation expense and other	(2.04		)	(13.24		)	(0.58		)	(0.58		)
Total adjusted cash operating costs	$	13.14		$	10.13		$	8.61		$	9.09

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

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Other Income Statement Items.

Loss from unconsolidated affiliates.  For the year ended December 31, 2013 we recorded losses on our equity investees as a result of an impairment recorded upon our decision to sell our investment in Four Star. The impairment of $20 million was based on comparison of $183 million in net proceeds received for the sale of Four Star in September 2013 to the underlying carrying value of the investment.

Loss on extinguishment of debt.  For the year ended December 31, 2013 we recorded $9 million in losses of extinguishment of debt for the pro-rata portion of deferred financing costs written off in conjunction with (i) the repayment of approximately $250 million under each of our $750 million and $400 million term loans, (ii) our $750 million term loan re-pricing in May 2013 and (iii) the semi-annual redeterminations of our RBL Facility in March 2013.  For the year ended December 31, 2012 we recorded a $14 million loss on the extinguishment of debt for the pro-rata portion of deferred financing costs written off, debt discount and call premiums paid related to the re-pricing of our existing $750 million term loan.

Interest expense. Interest expense for the year ended December 31, 2013 compared to 2012 increased due to the issuance of approximately $4.25 billion of debt in conjunction with the Acquisition in May 2012. Prior to the Acquisition and related financing transactions, interest expense primarily related to borrowings under the predecessor’s $1 billion credit facility in place at that time.

Income (loss) from discontinued operations. Our income (loss) from discontinued operations for 2013 includes a $468  million gain on the sale of assets during 2013 and 2011 includes a non-cash charge of approximately $152 million related to our Brazil oil and natural gas operations.

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Supplemental Non-GAAP Measures

We use the non-GAAP measures “EBITDAX,” “Adjusted EBITDAX” and “Pro Forma Adjusted EBITDAX” as supplemental measures. We believe these supplemental measures provide meaningful information to our investors. We define EBITDAX as income (loss) from continuing operations plus interest and debt expense, income taxes, depreciation, depletion and amortization and exploration expense. Adjusted EBITDAX is defined as EBITDAX, adjusted as applicable in the relevant period for the net change in the fair value of derivatives (mark-to-market effects of financial derivatives, net of cash settlements and premiums related to these derivatives), impairment and/or ceiling test charges, equity earnings from Four Star due to its sale in 2013, non-cash compensation expense, transition and restructuring costs, transaction, management and other fees paid to our Sponsors and losses or gains on extinguishment of debt. Pro Forma Adjusted EBITDAX is defined as total Adjusted EBITDAX less Adjusted EBITDAX related to divested assets. We believe that the presentation of EBITDAX, Adjusted EBITDAX, and Pro Forma Adjusted EBITDAX is important to provide management and investors with (i) additional information to evaluate our ability to service debt adjusting for items required or permitted in calculating covenant compliance under our debt agreements, (ii) an important supplemental indicator of the operational performance of our business, (iii) an additional criterion for evaluating our performance relative to our peers, (iv) additional information to measure our liquidity (before cash capital requirements and working capital needs) and (v) supplemental information about certain material non-cash and/or other items that may not continue at the same level in the future. EBITDAX, Adjusted EBITDAX, and Pro Forma Adjusted EBITDAX have limitations as analytical tools and should not be considered in isolation or as a substitute for analysis of our results as reported under GAAP or as an alternative to income (loss) from continuing operations, operating income, net cash provided by operating activities or any other measure of financial performance or liquidity presented in accordance with GAAP.

Below is a reconciliation of our EBITDAX, Adjusted EBITDAX, and Pro Forma Adjusted EBITDAX to our consolidated income (loss) from continuing operations:

	Successor					Predecessor
	Year ended December 31,		March 23 to December 31,			January 1 toMay 24,			Year ended December 31,
	2013		2012			2012			2011
	(in millions)
Income (loss) from continuing operations	$	39	$	(299	)	$	187		$	385
Income tax expense	—		—			134			243
Interest expense, net of capitalized interest	321		218			14			14
Depreciation, depletion and amortization	618		209			307			579
Exploration expense	45		43			—			—
EBITDAX	1,023		171			642			1,221
Mark-to-market on financial derivatives(1)	52		62			(365		)	(284		)
Cash settlements and premiums on financial derivatives(2)	10		217			165			331
Impairment and ceiling test charges	2		1			62			6
Transition and restructuring costs(3)	7		215			5			6
Loss from unconsolidated affiliate(4)	13		1			5			7
Non-cash compensation expense(5)	31		35			6			21
Management and other fees(6)	26		16			—			—
Loss on extinguishment of debt(7)	9		14			—			—
Adjusted EBITDAX	1,173		732			520			1,308
Less: Adjusted EBITDAX—divested assets(8)	—		5			64			460
Pro Forma Adjusted EBITDAX	$	1,173	$	727		$	456		$	848

(1)	Represents the income statement impact of financial derivatives.
(2)	Represents actual cash settlements received/(paid) related to financial derivatives, including cash premiums. For the year ended December 31, 2013 we received $9 million of cash premiums and for the period from March 23 to December 31, 2012 we paid $3 million of cash premiums. There were no cash premiums for the year ended December 31, 2011.
(3)	Reflects the transaction costs paid as part of the Acquisition in 2012 and severance costs incurred in connection with divested assets in 2013 and the closure of our office in Denver in 2011.
(4)	Reflects the elimination of equity income (losses) recognized from Four Star, net of amortization of our purchase cost in excess of our equity interest in the underlying net assets, as a result of the sale of Four Star in September 2013.
(5)	Represents the non-cash portion of compensation expense.
(6)	Represents the annual management fee of $25 million and other fees paid to affiliates of the Sponsors and other investors.
(7)	Represents the loss on extinguishment of debt recorded related to re-pricing of the term loan and redetermination of the RBL Facility.
(8)	Consists of Adjusted EBITDAX related to assets that have been divested, including our (i) CBM, South Texas and Arklatex assets, which are treated as discontinued operations after May 2012, (ii) Gulf of Mexico assets, (iii) Blue Creek West, Minden and Powder River operations and (iv) Catapult operations and Altamont processing plant and related gathering systems.

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Liquidity and Capital Resources

Our primary sources of liquidity are cash generated by our operations and borrowings under the RBL Facility. Our primary uses of cash are capital expenditures, debt service requirements and working capital requirements. We currently maintain a borrowing base on our RBL Facility of $2.5 billion, subject to semi-annual redetermination.  As of December 31, 2013, our available liquidity was approximately $2.25 billion, including approximately $2.2 billion of additional borrowing capacity available under the RBL Facility.

During June 2013, we entered into purchase and sale agreements for the sale of CBM properties (Raton, Arkoma and Black Warrior basins), the majority of our Arklatex natural gas properties, our natural gas properties in South Texas and our approximate 49% equity interest in Four Star, receiving total consideration of approximately $1.5 billion.  While we have experienced lower cash flow from operations compared with prior years as a result of these asset divestitures, we used the proceeds, among other items, to pay down debt and invest incremental capital in our core oil programs to generate higher return oil production growth.

We believe we have sufficient liquidity from our cash flows from operations, combined with availability under the RBL Facility and available cash, to fund our capital program, current obligations, and projected working capital requirements in 2014. Our ability to (i) generate sufficient cash flows from operations or obtain future borrowings under the RBL Facility, (ii) repay or refinance any of our indebtedness on commercially reasonable terms or at all on the occurrence of certain events, such as a change of control, or (iii) obtain additional capital if required on acceptable terms or at all for any potential future acquisitions, joint ventures or other similar transactions, will depend on prevailing economic conditions many of which are beyond our control. We have attempted to mitigate certain of these risks. For example, we enter into oil and gas derivative contracts to reduce the financial impact of downward commodity price movements on a substantial portion of our anticipated production. These contracts have been effective in providing greater cash flow certainty. Additionally, we occasionally enter into transactions to supplement the prices we receive through our hedging programs that involve the receipt or payment of premiums. These transactions are usually short term in nature (less than one year) and during 2013, we received $9 million in premiums on such transactions, substantially all of which settled during 2013. We could be required to take additional future actions if necessary to address further changes in the financial or commodity markets.

Capital Expenditures. For 2014, we expect our total capital budget will be approximately $2 billion, substantially all of which will be expended in our core oil programs. Our capital expenditures and our average drilling rigs for the twelve months ended December 31, 2013 were:

	Capital Expenditures (in millions)		Average Drilling Rigs
Eagle Ford Shale	$	1,191	5.5
Wolfcamp Shale	505		3.0
Altamont	207		2.5
Haynesville Shale	1		—
Other	21		—
Total capital expenditures(1)	$	1,925	11.0

(1)                   Excludes capital expenditures of $9 million from domestic assets sold in the third quarter of 2013.

Long-Term Debt. As of December 31, 2013, our long-term debt is approximately $4.0 billion, comprised of $3.1 billion in senior notes due in 2019, 2020 and 2022, $644 million in senior secured term loans with maturity dates in 2018 and 2019, and $295 million outstanding under the RBL Facility expiring in 2017.  While our debt and interest expense is significantly higher than in predecessor periods due to debt incurred with the Acquisition, we have reduced our debt utilizing proceeds from our 2013 asset divestitures and our parent’s initial public offering. During 2014, we received a contribution from our parent subsequent to their initial public offering to pay down a portion of our then outstanding balance.  For additional details on our long-term debt, including restrictive covenants under our debt agreements, see Part II, Item 8, “Financial Statements and Supplementary Data”, Note 7.

40

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

	Successor						Predecessor
	Year ended December 31,			March 23 (inception) to December 31,			January 1 to May 24,			Year ended December 31,
	2013			2012			2012			2011
Cash Flow from Operations
Operating activities
Net income (loss)	$	549		$	(255	)	$	178		$	262
Impairment and ceiling test charges	46			1			62			158
Gain on sale of assets	(468		)	—			—			—
Other income adjustments	796			351			537			973
Change in other assets and liabilities	52			352			(197		)	33
Total cash flow from operations	$	975		$	449		$	580		$	1,426
Other Cash Inflows
Investing activities
Net proceeds from the sale of assets and investments	$	1,451		$	110		$	9		$	612
Financing activities
Proceeds from debt	1,880			5,477			215			2,030
Contributions	—			3,323			960			—
	1,880			8,800			1,175			2,030
Total cash inflows	$	3,331		$	8,910		$	1,184		$	2,642
Cash Outflows
Investing activities
Capital expenditures	$	1,924		$	877		$	636		$	1,591
Cash paid for acquisitions	2			7,126			1			22
Increase in note receivable with parent	—			—			—			236
	1,926			8,003			637			1,849
Financing activities
Repayment of debt	2,190			1,139			1,065			1,480
Net change in note payable with parent company and affiliates	—			—			—			781
Member distribution	200
Debt issuance costs	5			154			—			7
	2,395			1,293			1,065			2,268
Total cash outflows	$	4,321		$	9,296		$	1,702		$	4,117
Net change in cash and cash equivalents	$	(15	)	$	63		$	62		$	(49	)

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Contractual Obligations

We are party to various contractual obligations. Some of these obligations are reflected in our financial statements, such as liabilities from commodity-based derivative contracts, while other obligations, such as operating leases and capital commitments, are not reflected on our balance sheet. The following table and discussion summarizes our contractual cash obligations as of December 31, 2013, for each of the periods presented:

	2014		2015 - 2016		2017 - 2018		Thereafter		Total
	(in millions)
Long-term financing obligations:
Principal	$	—	$	—	$	795	$	3,250	$	4,045
Interest	297		594		573		369		1,833
Liabilities from derivatives	35		—		—		—		35
Operating leases	12		22		8		—		42
Other contractual commitments and purchase obligations:
Volume and transportation commitments	81		144		152		219		596
Other obligations	62		51		50		135		298
Total contractual obligations	$	487	$	811	$	1,578	$	3,973	$	6,849

Long-term Financing Obligations (Principal and Interest).  Debt obligations included in the table above represent stated maturities. Interest payments are shown through the stated maturity date of the related debt based on (i) the contractual interest rate for fixed rate debt and (ii) current market interest rates and the contractual credit spread for variable rate debt.

Liabilities from Derivatives.  These amounts include the fair value of our commodity-based and interest rate derivative liabilities.

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

Other Contractual Commitments and Purchase Obligations.  Other contractual commitments and purchase obligations are legally enforceable agreements to purchase goods or services that have fixed or minimum quantities and fixed or minimum variable price provisions, and that detail approximate timing of the underlying obligations. Included are the following:

·Volume and Transportation Commitments.  Included in these amounts are commitments for volume deficiency contracts and demand charges for firm access to natural gas transportation as well as firm oil capacity.  Subsequent to December 31, 2013, we entered into an additional transportation commitment for approximately $66 million which will be incurred over the next five years.

·Other Obligations.  Included in these amounts are commitments for drilling, completions and seismic activities for our operations and various other maintenance, engineering, procurement, construction contracts and our management fee agreement. We have excluded asset retirement obligations and reserves for litigation and environmental remediation, as these liabilities are not contractually fixed as to timing and amount. Prior to 2014, our affiliates were party to a management fee agreement requiring the payment of an annual management fee of $25 million to our Sponsors which is reflected annually in the table above through May 24, 2024.  On January 1, 2014, we paid a $6.25 million installment under that agreement. The management fee agreement terminated later in January 2014 in connection with our parent’s initial public offering, and accordingly no further management fee payments will be required.

Commitments and Contingencies

For a further discussion of our commitments and contingencies, see Part II, Item 8, “Financial Statements and Supplementary Data”, Note 8.

Off-Balance Sheet Arrangements

We have no investments in unconsolidated entities or persons that could materially affect our liquidity or the availability of capital resources.  We do not have any material off-balance sheet arrangements that have, or are reasonably likely to have, or are reasonably likely to have, a material effect on our financial condition or results of operations.

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Critical Accounting Estimates

Our significant accounting policies are described in Note 1 of our consolidated financial statements included elsewhere in this Annual Report on Form 10-K. The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amount of assets, liabilities, revenue and expense and the disclosures of contingent assets and liabilities. We consider our critical accounting estimates to be those estimates that require complex or subjective judgment in the application of the accounting policy and that could significantly impact our financial results based on changes in those judgments. Changes in facts and circumstances may result in revised estimates and actual results may differ materially from those estimates. Our management has identified the following critical accounting estimates.

Accounting for Oil and Natural Gas Producing Activities.  We apply the successful efforts method of accounting for our oil and natural gas exploration and development activities. Under this method, non-drilling exploratory costs and costs of carrying and retaining undeveloped properties are charged to expense as incurred while acquisition costs, development costs and the costs of drilling exploratory wells are capitalized, pending the determination of proved oil and gas reserves. As a result, at any point in time, we may have capitalized costs on our consolidated balance sheet associated with exploratory wells that may be charged to exploration expense in a future period. Costs of drilling exploratory wells that do not result in proved reserves are charged to expense. We capitalize salaries and benefits that we determine are directly attributable to our oil and natural gas activities. Depreciation, depletion, amortization and the impairment of oil and natural gas properties are calculated on a depletable unit basis based significantly on estimates of quantities of proved oil and natural gas reserves. Revisions to these estimates could alter our depletion rates in the future and affect our future depletion expense.

Under the successful efforts method of accounting for oil and natural gas properties, we evaluate capitalized costs related to proved properties at least annually or upon a triggering event to determine if impairment of such properties is necessary.  Our evaluation is made based on common geological structure or stratigraphic conditions and considers estimated future cash flows for all proved developed (producing and non-producing), proved undeveloped reserves and risk-weighted non-proved reserves in comparison to the carrying amount of the proved properties to determine recoverability. If the carrying amount of a property exceeds the estimated undiscounted future cash flows, the carrying amount is reduced to estimated fair value through a charge to income. Fair value is calculated by discounting the future cash flows based on estimates of future oil and gas production, forward commodity prices based on published commodity price curves as of the date of the estimate, adjusted for geographical location and quality differentials, estimates of future operating and development costs, and a risk-adjusted discount rate. The discount rate is based on rates utilized by market participants that are commensurate with the risks inherent in the development and production of the underlying crude oil and natural gas.  Each of these estimates involves judgment.  Leasehold acquisition costs associated with non-producing areas are assessed for impairment by major prospect area based on our current drilling plans which could change in the future and result in impairments of unproved property. A majority of the Company’s unproved property costs are associated with properties acquired in the Eagle Ford and Wolfcamp shales. Generally, economic recovery of unproved reserves in such areas is not yet supported by actual production or conclusive formation tests, but may be confirmed by our continuing exploration and development programs. In 2013 and from the Acquisition (May 25, 2012) to December 31, 3012, we did not record any impairments of our oil and gas properties included in continuing operations.

Prior to the Acquisition on May 24, 2012, our predecessor accounted for oil and natural gas producing activities in accordance with the full cost method. Under the full cost accounting method, substantially all of the costs incurred in connection with the acquisition, exploration and development of oil and natural gas reserves were capitalized in full cost pools by country.  These capitalized amounts included the costs of unproven properties.  Under the full cost method our most critical accounting assessment was a quarterly ceiling test performed on capitalized costs for each full cost pool since many of the variables (reserves, costs and future capital) involved significant estimation.  Cost pools were also evaluated periodically based on estimates of future plans and activities. Prior to the Acquisition, our predecessor recorded non-cash charges of $62 million as a result of the decision to end exploration activities in Egypt and a $6 million impairment of certain oil field related equipment and supplies for the period from January 1, 2012 through May 24, 2012 and for the year ended 2011, respectively.

Our estimates of proved reserves reflect quantities of oil, natural gas and NGLs which geological and engineering data demonstrate, with reasonable certainty, will be recoverable in future years from known reservoirs under existing economic conditions. These estimates of proved oil and natural gas reserves primarily impact our property, plant and equipment amounts on our balance sheets and the depreciation, depletion and amortization amounts including any impairment or ceiling test charges on our income statements, among other items. The process of estimating oil and natural gas reserves is complex and requires significant judgment to evaluate all available geological, geophysical engineering and economic data. Our proved reserves are estimated at a property level and compiled for reporting purposes by a centralized group of experienced reservoir engineers who work closely with the operating groups. These engineers interact with engineering and geoscience personnel in each of our operating areas and accounting and marketing personnel to obtain the necessary data for projecting future production, costs, net revenues and economic recoverable reserves. Reserves are reviewed internally with senior management quarterly and presented to the board of directors of our parent, EP

43

Energy Corporation, in summary form on an annual basis. Additionally, on an annual basis each property is reviewed in detail by our centralized and operating divisional engineers to ensure forecasts of operating expenses, netback prices, production trends and development timing are reasonable. Our proved reserves are reviewed by internal committees and the processes and controls used for estimating our proved reserves are reviewed by our internal auditors. In addition, a third-party reservoir engineering firm, which is appointed by and reports to the Audit Committee of the board of directors of our parent, EP Energy Corporation, conducts an audit of the estimates of a significant portion of our proved reserves.

As of December 31, 2013, 67% of our total proved reserves were undeveloped and 3% were developed, but non-producing. The data for a given field may change substantially over time as a result of numerous factors, including additional development activity, evolving production history and a continual reassessment of the viability of production under changing economic conditions. As a result, material revisions to existing reserve estimates occur from time to time. In addition, the subjective decisions and variances in available data for various fields increase the likelihood of significant changes in these estimates.

Asset Retirement Obligations.  The accounting guidance for future abandonment costs requires that a liability for the discounted fair value of an asset retirement obligation be recorded in the period in which it is incurred and the corresponding cost capitalized by increasing the carrying amount of the related long-lived asset. The liability is accreted to its present value each period, and the capitalized cost is depreciated over the useful life of the related asset. Future abandonment costs include costs to dismantle and relocate or dispose of our production platforms, gathering systems and related structures and restoration costs of land and seabed. We develop estimates of these costs for each of our properties based upon their geographic location, type of production structure, water depth, reservoir depth and characteristics, market demand for equipment, currently available procedures and ongoing consultations with construction and engineering consultants. Because these costs typically extend many years into the future, estimating these future costs is difficult and requires management to make judgments that are subject to future revisions based upon numerous factors, including changing technology and the political and regulatory environment. We review our assumptions and estimates of future development and abandonment costs on an annual basis, or more frequently if an event occurs or circumstances change that would affect our assumptions and estimates. Additionally, inherent in the present value calculations are numerous assumptions and judgments including the ultimate settlement amounts, inflation factors, credit adjusted discount rates, timing of settlements and changes in the legal, regulatory, environmental and political environments. As of December 31, 2013, our net asset retirement liability was approximately $53 million (excluding $37 million related to Brazil classified as discontinued operations).

Derivatives.  We record derivative instruments at their fair values. We estimate the fair value of our derivative instruments using exchange prices, third-party pricing, interest rates, data and valuation techniques that incorporate specific contractual terms, derivative modeling techniques and present value concepts. One of the primary assumptions used to estimate the fair value of commodity-based derivative instruments is pricing. Our pricing assumptions are based upon price curves derived from actual prices observed in the market, pricing information supplied by a third-party valuation specialist and independent pricing sources and models that rely on this forward pricing information. The extent to which we rely on pricing information received from third parties in developing these assumptions is based, in part, on whether the information considers the availability of observable data in the marketplace. For example, in relatively illiquid markets we may make adjustments to the pricing information we receive from third parties based on our evaluation of whether third party market participants would use pricing assumptions consistent with these sources.

The table below presents the hypothetical sensitivity of our commodity-based derivatives to changes in fair values arising from immediate selected potential changes in oil and natural gas prices at December 31, 2013:

			Change in Price
			10 Percent Increase						10 Percent Decrease
	Fair Value		Fair Value			Change			Fair Value		Change
	(in millions)
Commodity-based derivatives—net assets (liabilities)	$	105	$	(349	)	$	(454	)	$	551	$	446

Other significant assumptions that we use in determining the fair value of our derivative instruments are those related to credit and non-performance risk. We adjust the fair value of our derivative assets based on our counterparty’s creditworthiness and the risk of non-performance.  These adjustments are based on applicable credit ratings, bond yields, changes in actively traded credit default swap prices (if available) and other information related to non-performance and credit standing.

44

ITEM 7A.  Qualitative and Quantitative Disclosures About Market Risk

We are exposed to market risks in our normal business activities. Market risk is the potential loss that may result from market changes associated with an existing or forecasted financial or commodity transaction. The types of market risks we are exposed to and examples of each are:

Commodity Price Risk

·changes in oil, natural gas and NGLs prices impact the amounts at which we sell our production and affect the fair value of our oil and natural gas derivative contracts; and

·changes in locational price differences also affect amounts at which we sell our oil, natural gas and NGLs production, and the fair values of any related derivative products.

Interest Rate Risk

·changes in interest rates affect the interest expense we incur on our variable-rate debt and the fair value of fixed-rate debt;

·changes in interest rates result in increases or decreases in the unrealized value of our derivative positions; and

·changes in interest rates used to discount liabilities result in higher or lower accretion expense over time.

Risk Management Activities

Where practical, we manage commodity price and interest rate risks by entering into contracts involving physical or financial settlement that attempt to limit exposure related to future market movements. The timing and extent of our risk management activities are based on a number of factors, including our market outlook, risk tolerance and liquidity. Our risk management activities typically involve the use of the following types of contracts:

·forward contracts, which commit us to purchase or sell energy commodities in the future;

·option contracts, which convey the right to buy or sell a commodity, financial instrument or index at a predetermined price;

·swap contracts, which require payments to or from counterparties based upon the differential between two prices or rates for a predetermined contractual (notional) quantity; and

·structured contracts, which may involve a variety of the above characteristics.

Many of the contracts we use in our risk management activities qualify as derivative financial instruments. A discussion of our accounting policies for derivative instruments is included in Part II Item 8, Financial Statements and Supplementary data, Note 1 and 5.

For information regarding changes in commodity prices and interest rates during 2013, please see “Management’s Discussion and Analysis of Financial Condition” and “Results of Operations”.

Commodity Price Risk

Oil and Natural Gas Derivatives. We attempt to mitigate commodity price risk and stabilize cash flows associated with our forecasted sales of oil and natural gas production through the use of derivative oil and natural gas swaps, basis swaps and option contracts. These contracts impact our earnings as the fair value of these derivatives changes. Our derivatives do not mitigate all of the commodity price risks of our forecasted sales of oil and natural gas production and, as a result, we are subject to commodity price risks on our remaining forecasted production.

45

Sensitivity Analysis. The table below presents the hypothetical sensitivity of our commodity-based derivatives to changes in fair values arising from immediate selected potential changes in oil and natural gas prices, discount rates and credit rates at December 31, 2013:

			Oil and Natural Gas Derivatives
			10 Percent Increase						10 Percent Decrease
	Fair Value		Fair Value			Change			Fair Value		Change
	(in millions)
Price impact(1)	$	105	$	(349	)	$	(454	)	$	551	$	446

			Oil and Natural Gas Derivatives
			1 Percent Increase					1 Percent Decrease
	Fair Value		Fair Value		Change			Fair Value		Change
	(in millions)
Discount Rate(2)	$	105	$	103	$	(2	)	$	107	$	2
Credit rate(3)	$	105	$	104	$	(1	)	$	105	$	—

(1)	Presents the hypothetical sensitivity of our commodity-based derivatives to changes in fair values arising from changes in oil and natural gas prices.
(2)	Presents the hypothetical sensitivity of our commodity-based derivatives to changes in the discount rates we used to determine the fair value of our derivatives.
(3)	Presents the hypothetical sensitivity of our commodity-based derivatives to changes in credit risk.

Interest Rate Risk

Certain of our debt agreements are sensitive to changes in interest rates.  The table below shows the maturity of the carrying amounts and related weighted-average effective interest rates on our long-term interest-bearing debt by expected maturity date as well as the total fair value of the debt.  The fair value of our long-term debt has been estimated primarily based on quoted market prices for the same or similar issues.

	December 31, 2013																						December 31, 2012
	Expected Fiscal Year of Maturity of Carrying Amounts																				Fair		Carrying		Fair
	2014			2015			2016			2017			2018			Thereafter			Total		Value		Amounts		Value
	(in millions)
Fixed rate long-term debt	$	—		$	—		$	—		$	—		$	—		$	3,100		$	3,100	$	3,506	$	3,100	$	3,430
Average interest rate	8.6		%	8.6		%	8.6		%	8.6		%	8.6		%	8.3		%
Variable rate long-term debt	$	—		$	—		$	—		$	295		$	495		$	149		$	939	$	945	$	1,246	$	1,260
Average interest rate	3.3		%	3.3		%	3.3		%	3.5		%	4.0		%	4.5		%

46

Item 8.FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Index

Below is an index to the items contained in Part II, Item 8, Financial Statements and Supplementary Data

		Page
Management’s Annual Report on Internal Control over Financial Reporting		48
Reports of Independent Registered Public Accounting Firms		49
Consolidated Statements of Income for (i) the Year Ended December 31, 2013 and for the successor period from March 23, 2012 (inception) to December 31, 2012 and (ii) the predecessor periods from January 1, 2012 to May 24, 2012 and the Year Ended December 31, 2011		51
Consolidated Statements of Comprehensive Income for (i) the Year Ended December 31, 2013 and for the successor period from March 23, 2012 (inception) to December 31, 2012 and (ii) the predecessor periods from January 1, 2012 to May 24, 2012 and the Year Ended December 31, 2011		52
Consolidated Balance Sheets as of December 31, 2013 and December 31, 2012		53
Consolidated Statements of Cash Flows for (i) the Year Ended December 31, 2013 and for the successor period from March 23, 2012 (inception) to December 31, 2012 and (ii) the predecessor periods from January 1, 2012 to May 24, 2012 and the Year Ended December 31, 2011		55
Consolidated Statements of Changes in Equity for (i) the Year Ended December 31, 2013 and for the successor period from March 23, 2012 (inception) to December 31, 2012 and (ii) the predecessor periods from January 1, 2012 to May 24, 2012 and the Year Ended December 31, 2011		56
Notes to Consolidated Financial Statements
	1. Basis of Presentation and Significant Accounting Policies	57
	2. Acquisitions and Divestitures	60
	3. Impairment and Ceiling Test Charges	62
	4. Income Taxes	63
	5. Financial Instruments	64
	6. Property, Plant and Equipment	66
	7. Long Term Debt	67
	8. Commitments and Contingencies	68
	9. Long-Term Incentive Compensation / Retirement 401(k) Plan	70
	10. Investments in Unconsolidated Affiliate	72
	11. Related Party Transactions	72
	12. Consolidating Financial Statements	74
Supplemental Financial Information
	Supplemental Selected Quarterly Financial Information (Unaudited)	87
	Supplemental Oil and Natural Gas Operations (Unaudited)	88

47

MANAGEMENT’S ANNUAL REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as defined by SEC rules adopted under the Securities Exchange Act of 1934, as amended. Our internal control over financial reporting is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. It consists of policies and procedures that:

·Pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of our assets;

·Provide reasonable assurance that transactions are recorded as necessary to permit preparation of the financial statements in accordance with generally accepted accounting principles, and that our receipts and expenditures are being made only in accordance with authorizations of our management and directors; and

·Provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of our assets that could have a material effect on the financial statements.

Under the supervision and with the participation of management, including the Chief Executive Officer and Chief Financial Officer, we made an assessment of the effectiveness of our internal control over financial reporting as of December 31, 2013. In making this assessment, we used the criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (1992 framework). Based on our evaluation, we concluded that our internal control over financial reporting was effective as of December 31, 2013.

48

Report of Independent Registered Public Accounting Firm

The Board of Directors of EP Energy Corporation

We have audited the accompanying consolidated balance sheets of EP Energy LLC as of December 31, 2013 and 2012 (Successor), and the related consolidated statements of income, comprehensive income, cash flows and changes in equity for the year ended December 31, 2013 (Successor), the period from March 23, 2012 to December 31, 2012 (Successor), the period from January 1, 2012 to May 24, 2012 (Predecessor) and for the year ended December 31, 2011 (Predecessor).  These financial statements are the responsibility of the Company’s management.  Our responsibility is to express an opinion on these financial statements based on our audits.  The financial statements of Four Star Oil & Gas Company (a corporation in which the Company had a 49 percent interest), have been audited by other auditors whose report has been furnished to us, and our opinion on the consolidated financial statements, insofar as it relates to the amounts included from Four Star Oil & Gas Company for the year ended December 31, 2011, is based solely on the report of other auditors. In the consolidated financial statements, earnings from unconsolidated affiliate includes approximately $29 million for the year ended December 31, 2011, from Four Star Oil & Gas Company.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. We were not engaged to perform an audit of the Company’s internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits and the report of other auditors provide a reasonable basis for our opinion.

In our opinion, based on our audits and the report of other auditors, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of EP Energy LLC at December 31, 2013 and 2012, and the consolidated results of its operations and its cash flows for the year ended December 31, 2013 (Successor), the period from March 23, 2012 to December 31, 2012 (Successor), the period from January 1, 2012 to May 24, 2012 (Predecessor) and for the year ended December 31, 2011 (Predecessor), in conformity with U.S. generally accepted accounting principles.

/s/ Ernst & Young LLP

Houston, Texas

February 27, 2014

49

Report of Independent Registered Public Accounting Firm

To the Board of Directors and the Stockholders of

Four Star Oil & Gas Company:

In our opinion, the consolidated balance sheet and the related consolidated statements of income, of stockholders’ equity and of cash flows (not presented separately herein) present fairly, in all material respects, the financial position of Four Star Oil & Gas Company and its subsidiary (the “Company”) at December 31, 2011, and the results of their operations and their cash flows for the year then ended in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audit. We conducted our audit of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.

As described in Notes 4 and 5 to the consolidated financial statements, the Company has significant transactions with affiliated companies. Because of these relationships, it is possible that the terms of these transactions are not the same as those that would result from transactions among wholly unrelated parties.

/s/PricewaterhouseCoopers LLP

February 24, 2012

Houston, Texas

50

EP ENERGY LLC

CONSOLIDATED STATEMENTS OF INCOME

(In millions)

	Successor						Predecessor
	Year Ended December 31, 2013			March 23  (inception) to December 31, 2012			January 1  to May 24, 2012			Year Ended December 31, 2011
Operating revenues
Oil and condensate	$	1,283		$	523		$	310		$	513
Natural gas	331			234			228			901
NGLs	78			32			29			58
Financial derivatives	(52		)	(62		)	365			284
Total operating revenues	1,640			727			932			1,756
Operating expenses
Natural gas purchases	25			19			—			—
Transportation costs	92			51			45			85
Lease operating expense	163			71			80			177
General and administrative	228			358			69			185
Depreciation, depletion and amortization	618			209			307			579
Impairment and ceiling test charges	2			1			62			6
Exploration expense	45			43			—			—
Taxes, other than income taxes	86			41			31			76
Total operating expenses	1,259			793			594			1,108
Operating income (loss)	381			(66		)	338			648
Loss from unconsolidated affiliate	(13		)	(1		)	(5		)	(7		)
Other income	1			—			2			1
Loss on extinguishment of debt	(9		)	(14		)	—			—
Interest expense
Third party	(321		)	(218		)	(14		)	(9		)
Affiliated	—			—			—			(5		)
Income (loss) from continuing operations before income taxes	39			(299		)	321			628
Income tax expense	—			—			134			243
Income (loss) from continuing operations	39			(299		)	187			385
Income (loss) from discontinued operations, net of tax	510			44			(9		)	(123		)
Net income (loss)	$	549		$	(255	)	$	178		$	262

See accompanying notes.

51

EP ENERGY LLC

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(In millions)

	Successor					Predecessor
	Year Ended December 31, 2013		March 23 (inception) to December 31, 2012			January 1 to May 24, 2012		Year Ended December 31, 2011
Net income (loss)	$	549	$	(255	)	$	178	$	262
Cash flow hedging activities:
Reclassification adjustment(1)	—		—			3		7
Comprehensive income (loss)	$	549	$	(255	)	$	181	$	269

(1)Reclassification adjustments are stated net of tax. Taxes recognized for the predecessor periods related to January 1, 2012 to May 24, 2012 and the year ended December 31, 2011 are $2 million and $4 million, respectively.

See accompanying notes.

52

EP ENERGY LLC

CONSOLIDATED BALANCE SHEETS

(In millions)

	December 31, 2013		December 31, 2012
ASSETS
Current assets
Cash and cash equivalents	$	48	$	63
Accounts receivable
Customer, net of allowance of less than $1 in 2013 and 2012	239		158
Other, net of allowance of $2 for 2013 and $1 for 2012	41		14
Materials and supplies	20		16
Derivative instruments	47		108
Assets of discontinued operations	88		1,034
Prepaid assets	12		10
Total current assets	495		1,403
Property, plant and equipment, at cost
Oil and natural gas properties	8,371		6,513
Other property, plant and equipment	63		52
	8,434		6,565
Less accumulated depreciation, depletion and amortization	818		214
Total property, plant and equipment, net	7,616		6,351
Other assets
Investment in unconsolidated affiliate	—		220
Derivative instruments	97		88
Assets of discontinued operations	—		93
Unamortized debt issue costs	111		134
Other	7		4
	215		539
Total assets	$	8,326	$	8,293

See accompanying notes.

53

EP ENERGY LLC

CONSOLIDATED BALANCE SHEETS

(In millions)

	December 31, 2013		December 31, 2012
LIABILITIES AND EQUITY
Current liabilities
Accounts payable
Trade	$	140	$	98
Other	387		302
Derivative instruments	35		17
Accrued interest	54		57
Asset retirement obligations	3		4
Liabilities of discontinued operations	91		211
Other accrued liabilities	65		74
Total current liabilities	775		763
Long-term debt	4,039		4,346
Other long-term liabilities
Derivative instruments	—		14
Liabilities of discontinued operations	—		42
Asset retirement obligations	50		40
Other	7		3
Total non-current liabilities	4,096		4,445
Commitments and contingencies (Note 8)
Member’s equity	3,455		3,085
Total liabilities and equity	$	8,326	$	8,293

See accompanying notes.

54

EP ENERGY LLC

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In millions)

	Successor						Predecessor
	Year Ended December 31, 2013			March 23 (inception) to December 31, 2012			January 1 to May 24, 2012			Year Ended December 31, 2011
Cash flows from operating activities
Net income (loss)	$	549		$	(255	)	$	178		$	262
Adjustments to reconcile net income (loss) to net cash provided by operating activities
Depreciation, depletion and amortization	666			268			319			612
Gain on sale of assets	(468		)	—			—			—
Deferred income tax expense	1			1			199			304
Loss from unconsolidated affiliates, net of cash distributions	37			15			12			53
Impairment and ceiling test charges	46			1			62			158
Loss on extinguishment of debt	9			14			—			—
Amortization of equity compensation expense	22			17			—			—
Non-cash portion of exploration expense	39			23			—			—
Other non-cash income items	22			13			7			4
Asset and liability changes
Accounts receivable	(51		)	(73		)	132			(20		)
Accounts payable	80			66			(56		)	(67		)
Derivative instruments	56			281			(201		)	47
Accrued interest	(3		)	57			(1		)	(1		)
Other asset changes	(10		)	(18		)	(7		)	95
Other liability changes	(20		)	39			(64		)	(21		)
Net cash provided by operating activities	975			449			580			1,426
Cash flows from investing activities
Capital expenditures	(1,924		)	(877		)	(636		)	(1,591		)
Net proceeds from the sale of assets and investments	1,451			110			9			612
Cash paid for acquisitions, net of cash acquired	(2		)	(7,126		)	(1		)	(22		)
Increase in note receivable with parent	—			—			—			(236		)
Net cash used in investing activities	(475		)	(7,893		)	(628		)	(1,237		)
Cash flows from financing activities
Proceeds from long term debt	1,880			5,477			215			2,030
Repayment of long term debt	(2,190		)	(1,139		)	(1,065		)	(1,480		)
Distributions to member	(200		)	—			—			—
Contributions from member	—			3,323			—			—
Contributions from parent	—			—			960			—
Change in note payable with parent	—			—			—			(781		)
Debt issuance costs	(5		)	(154		)	—			(7		)
Net cash (used in) provided by financing activities	(515		)	7,507			110			(238		)
Change in cash and cash equivalents	(15		)	63			62			(49		)
Cash and cash equivalents
Beginning of period	63			—			25			74
End of period	$	48		$	63		$	87		$	25
Supplemental cash flow information
Interest paid, net of amounts capitalized	$	305		$	145		$	7		$	9
Income tax payments (refunds)	4			2			2			(158		)

See accompanying notes.

55

EP ENERGY LLC

CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY

(In millions, except share amounts)

	Shares		Common Stock		Additional Paid-in Capital			Retained Earnings (Accumulated deficit)			Accumulated Other Comprehensive Income			Total Stockholder’s /Member’s Equity
Predecessor
Balance at January 1, 2011	1,000		$	—	$	4,816		$	(1,738	)	$	(11	)	$	3,067
Distribution to parent			—		(236		)	—			—			(236		)
Other			—		—			—			7			7
Net income			—		—			262			—			262
Balance at December 31, 2011	1,000		$	—	$	4,580		$	(1,476	)	$	(4	)	$	3,100
Contribution from parent			—		1,481			—			—			1,481
Other			—		12			—			3			15
Net income			—		—			178			—			178
Elimination of predecessor parent stockholder’s equity	(1,000	)	—		(6,073		)	1,298			1			(4,774		)
Balance at May 24, 2012	—		$	—	$	—		$	—		$	—		$	—
Successor
Balance at March 23, 2012 (inception)	—		$	—	$	—		$	—		$	—		$	—
Member contributions	—		—		—			—			—			3,323
Equity compensation expense	—		—		—			—			—			17
Net loss	—		—		—			—			—			(255		)
Balance at December 31, 2012	—		$	—	$	—		$	—		$	—		$	3,085
Member distributions	—		—		—			—			—			(200		)
Equity compensation expense	—		—		—			—			—			22
Other	—		—		—			—			—			(1		)
Net income	—		—		—			—			—			549
Balance at December 31, 2013	—		$	—	$	—		$	—		$	—		$	3,455

See accompanying notes.

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EP ENERGY LLC

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

1.  Basis of Presentation and Significant Accounting Policies

Basis of Presentation and Consolidation

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

Our consolidated financial statements are prepared in accordance with United States generally accepted accounting principles and include the accounts of all consolidated subsidiaries after the elimination of all significant intercompany accounts and transactions. Predecessor periods reflect reclassifications to conform to EP Energy LLC’s financial statement presentation.

We consolidate entities when we have the ability to control the operating and financial decisions of the entity or when we have a significant interest in the entity that gives us the ability to direct the activities that are significant to that entity. The determination of our ability to control, direct or exert significant influence over an entity involves the use of judgment. We apply the equity method of accounting where we can exert significant influence over, but do not control or direct the policies, decisions and activities of an entity.

Our oil and natural gas properties are managed as a whole in one operating segment rather than through discrete operating segments or business units. We track basic operational data by area and allocate capital resources on a project-by-project basis across our entire asset base without regard to individual areas.  We assess financial performance as a single enterprise and not on a geographical area basis.

Use of Estimates

The preparation of our financial statements requires the use of estimates and assumptions that affect the amounts we report as assets, liabilities, revenues and expenses and our disclosures in these financial statements. Actual results can, and often do, differ from those estimates.

Revenue Recognition

Our revenues are generated primarily through the physical sale of oil, condensate, natural gas and NGLs. Revenues from sales of these products are recorded upon delivery and the passage of title using the sales method, net of any royalty interests or other profit interests in the produced product. Revenues related to products delivered, but not yet billed, are estimated each month. These estimates are based on contract data, commodity prices and preliminary throughput and allocation measurements. When actual sales volumes exceed our entitled share of sales volumes, an overproduced imbalance occurs. To the extent the overproduced imbalance exceeds our share of the remaining estimated proved natural gas reserves for a given property, we record a liability.

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

As of December 31, 2013 and 2012, we had two customers that accounted for 10 percent or more of our total revenues.  The predecessor period in 2012 had three customers, and for the year ended December 31, 2011, had one customer that accounted for 10 percent or more of total revenues.  The loss of any one customer would not have an adverse effect on our ability to sell our oil, natural gas and NGLs production.

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Cash and Cash Equivalents

We consider short-term investments with an original maturity of less than three months to be cash equivalents.  As of December 31, 2013 and 2012, we had less than $1 million, respectively, of restricted cash in other current assets to cover escrow amounts required for leasehold agreements in our domestic operations.

Allowance for Doubtful Accounts

We establish provisions for losses on accounts receivable and for natural gas imbalances with other parties if we determine that we will not collect all or part of the outstanding balance. We regularly review collectability and establish or adjust our allowance as necessary using the specific identification method.

Oil and Natural Gas Properties

Successful Efforts (Successor). In conjunction with the Acquisition, we began applying the successful efforts method of accounting for oil and natural gas exploration and development activities.

Under the successful efforts method, (i) lease acquisition costs and all development costs are capitalized and exploratory drilling costs are capitalized until results are determined, (ii) other non-drilling exploratory costs, including certain geological and geophysical costs such as seismic costs and delay rentals, are expensed as incurred, (iii) certain internal costs directly identified with the acquisition, successful drilling of exploratory wells and development activities are capitalized, and (iv) interest costs related to financing oil and natural gas projects actively being developed are capitalized until the projects are evaluated or substantially complete and ready for their intended use if the projects were evaluated as successful.

The provision for depreciation, depletion, and amortization is determined on a basis identified by common geological structure or stratigraphic conditions applied to total capitalized costs plus future abandonment costs net of salvage value, using the unit of production method.  Lease acquisition costs are amortized over total proved reserves, and other exploratory drilling and all developmental costs are amortized over total proved developed reserves.

We evaluate capitalized costs related to proved properties at least annually or upon a triggering event to determine if impairment of such properties is necessary.  Our evaluation is made based on common geological structure or stratigraphic conditions and considers estimated future cash flows for all proved developed (producing and non-producing) and proved undeveloped reserves in comparison to the carrying amount of the proved properties to determine recoverability. If the carrying amount of a property exceeds the estimated undiscounted future cash flows, the carrying amount is reduced to estimated fair value through a charge to income. Fair value is calculated by discounting the future cash flows based on estimates of future oil and gas production, commodity prices based on published forward commodity price curves as of the date of the estimate, adjusted for geographical location and quality differentials, estimates of future operating and development costs, and a risk-adjusted discount rate. The discount rate is based on rates utilized by market participants that are commensurate with the risks inherent in the development and production of the underlying crude oil and natural gas.

Full Cost (Predecessor). Prior to the Acquisition, the predecessor used the full cost method to account for their oil and natural gas properties. Under the full cost method, substantially all costs incurred in connection with the acquisition, development and exploration of oil and natural gas reserves were capitalized on a country-by-country basis. These capitalized amounts included the costs of unproved properties that were transferred into the full cost pool when the properties were determined to have proved reserves, internal costs directly related to acquisition, development and exploration activities, asset retirement costs and capitalized interest. Under the full cost method, both dry hole costs and geological and geophysical costs were capitalized into the full cost pool, which was subject to amortization and was periodically assessed for impairment through a ceiling test calculation discussed below.

Under full cost accounting, capitalized costs associated with proved reserves were amortized over the life of the proved reserves using the unit of production method. Conversely, capitalized costs associated with unproved properties were excluded from the amortizable base until these properties were evaluated or determined that the costs were impaired. On a quarterly basis, unproved property costs were transferred into the amortizable base when properties were determined to have proved reserves. If costs were determined to be impaired, the amount of any impairment was transferred to the full cost pool if an oil or natural gas reserve base exists, or was expensed if a reserve base has not yet been created. The amortizable base included future development costs; dismantlement, restoration and abandonment costs, net of estimated salvage values; and geological and geophysical costs incurred that could not be associated with specific unevaluated properties or prospects in which we owned a direct interest.

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Under full cost accounting, capitalized costs in each country, net of related deferred income taxes, were limited to a ceiling based on the present value of future net revenues from proved reserves less estimated future capital expenditures, discounted at 10 percent, plus the cost of unproved oil and natural gas properties not being amortized, less related income tax effects.  Prior to the Acquisition, this ceiling test calculation was performed each quarter.  The prices used when performing the ceiling test were based on the unweighted arithmetic average of the price on the first day of each month within the 12-month period prior to the end of the reporting period. These prices were required to be held constant over the life of the reserves, even though actual prices of oil and natural gas changed from period to period.  If total capitalized costs exceeded the ceiling, a writedown of capitalized costs to the ceiling was required. Any required write-down was included as a ceiling test charge in the consolidated income statement and as an increase to accumulated depreciation, depletion and amortization on the consolidated balance sheet. The present value of future net revenues used for these ceiling test calculations excludes the impact of derivatives and the estimated future cash outflows associated with asset retirement liabilities related to proved developed reserves.

Property, Plant and Equipment (Other than Oil and Natural Gas Properties)

Our property, plant and equipment, other than our assets accounted for under the successful efforts method, are recorded at their original cost of construction or, upon acquisition, at the fair value of the assets acquired. We capitalize the major units of property replacements or improvements and expense minor items. We depreciate our non-oil and natural gas property, plant and equipment using the straight-line method over the useful lives of the assets which range from three to 15 years.

Accounting for Asset Retirement Obligations

We record a liability for legal obligations associated with the replacement, removal or retirement of our long-lived assets in the period the obligation is incurred and is estimable. Our asset retirement liabilities are initially recorded at their estimated fair value with a corresponding increase to property, plant and equipment. This increase in property, plant and equipment is then depreciated over the useful life of the asset to which that liability relates. An ongoing expense is recognized for changes in the value of the liability as a result of the passage of time, which we record as depreciation, depletion and amortization expense in our consolidated income statement.

Accounting for Long-Term Incentive Compensation

We measure the cost of long-term incentive compensation based on the grant date fair value of the award.  Awards issued under these programs are recognized as either equity awards or liability awards based on their characteristics.  Expense is recognized in our consolidated financial statements as general and administrative expense over the requisite service period, net of estimated forfeitures. See Note 9 for further discussion of our Long-Term Incentive Compensation.

Environmental Costs, Legal and Other Contingencies

Environmental Costs. We record environmental liabilities at their undiscounted amounts on our consolidated balance sheet in other current and long-term liabilities when our environmental assessments indicate that remediation efforts are probable and the costs can be reasonably estimated. Estimates of our environmental liabilities are based on current available facts, existing technology and presently enacted laws and regulations, taking into consideration the likely effects of other societal and economic factors, and include estimates of associated legal costs. These amounts also consider prior experience in remediating contaminated sites, other companies’ clean-up experience and data released by the Environmental Protection Agency (EPA) or other organizations. Our estimates are subject to revision in future periods based on actual costs or new circumstances. We capitalize costs that benefit future periods and we recognize a current period charge in general and administrative expense when clean-up efforts do not benefit future periods.

We evaluate any amounts paid directly or reimbursed by government sponsored programs and potential recoveries or reimbursements of remediation costs from third parties, including insurance coverage, separately from our liability. Recovery is evaluated based on the creditworthiness or solvency of the third party, among other factors. When recovery is assured, we record and report an asset separately from the associated liability on our consolidated balance sheet.

Legal and Other Contingencies.  We recognize liabilities for legal and other contingencies when we have an exposure that indicates it is both probable that a liability has been incurred and the amount of the loss can be reasonably estimated. Where the most likely outcome of a contingency can be reasonably estimated, we accrue a liability for that amount. Where the most likely outcome cannot be estimated, a range of potential losses is established and if no one amount in that range is more likely than any other to occur, the low end of the range is accrued.

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Derivatives

We enter into derivative contracts on our oil and natural gas products primarily to stabilize cash flows and reduce the risk and financial impact of downward commodity price movements on commodity sales.  We also use derivatives to reduce the risk of variable interest rates.  Derivative instruments are reflected on our balance sheet at their fair value as assets and liabilities. We classify our derivatives as either current or non-current assets or liabilities based on their anticipated settlement date. We net derivative assets and liabilities on counterparties where we have a legal right of offset.

All of our derivatives are marked-to-market each period and changes in the fair value of our commodity based derivatives, as well as any realized amounts, are reflected as operating revenues.  Changes in the fair value of our interest rate derivatives are reflected as interest expense.  We classify cash flows related to derivative contracts based on the nature and purpose of the derivative. As the derivative cash flows are considered an integral part of our oil and natural gas operations, they are classified as cash flows from operating activities. In our consolidated balance sheet, receivables and payables resulting from the settlement of our derivative instruments are reported as trade receivables and payables. See Note 5 for a further discussion of our derivatives.

Income Taxes

We are a limited liability company, treated as a partnership for federal and state income tax purposes, with income tax liabilities and/or benefits passed through to our member. We are, however subject to the Texas margin tax and pay any liability directly to the state of Texas.  Texas Margin tax liability was less than $1 million as of December 31, 2013 and 2012.  The aggregate difference in the basis of net assets for financial reporting and tax reporting is approximately $1.1 billion.

Prior to the Acquisition, the predecessor’s taxable income or loss was included in El Paso’s U.S. federal and certain state returns and we recorded income taxes on a separate return basis in our financial statements as if we had filed separate income tax returns under our then existing structure for the periods presented in accordance with a tax sharing agreement between us and El Paso. Under that agreement El Paso paid all consolidated U.S. federal and state income tax directly to the appropriate taxing jurisdictions and, under a separate tax billing agreement, El Paso billed or refunded for their portion of these income taxes. In certain states, the predecessor filed and paid taxes directly to the state taxing authorities.

2.  Acquisitions and Divestitures

Acquisitions. On May 24, 2012, investment funds managed by Apollo (collectively, “the Apollo Funds”) and other investors acquired all of the equity of EP Energy Global LLC for approximately $7.2 billion. The Acquisition was funded with approximately $3.3 billion in equity contributions and the issuance of approximately $4.25 billion of debt. In conjunction with the Acquisition, a portion of the proceeds were also used to repay approximately $960 million outstanding under predecessor’s revolving credit facility at that time. See Note 7 for 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 consolidated balance sheet at their fair values as of the Acquisition date. Our consolidated balance sheet for all periods includes the following purchase price allocation based on available information to specific assets and liabilities assumed based on estimates of fair values and costs. There was no goodwill associated with the transaction.

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

The unaudited pro forma information below for the years ended December 31, 2012 and 2011 has been derived from the historical consolidated financial statements and has been prepared as though the Acquisition occurred as of the beginning of January 1, 2011. The unaudited pro forma information does not purport to represent what our results of operations would have been if such transactions had occurred on such date.

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	Year ended December 31, 2012		Year ended December 31, 2011
	(in millions)
Operating Revenues	$	1,659	$	1,756
Net Income	143		454

In conjunction with the Acquisition, approximately $330 million in transaction, advisory, and other fees were incurred, of which $142 million were capitalized as debt issue costs and $15 million were capitalized as prepaid costs in other assets on our balance sheet. The remaining $173 million in fees were reflected in general and administrative expense in our income statement.  Additionally, during the successor period in 2012 we recorded approximately $48 million related to transition and restructuring costs, including severance charges totaling approximately $17 million ($4 million related to divested assets).  These amounts, substantially all of which had been paid as of December 31, 2012, were included as general and administrative expenses in our income statement.

Discontinued Operations.  In June 2013, we entered into three separate agreements to sell our CBM properties located in the Raton, Black Warrior and Arkoma basins; our Arklatex conventional natural gas assets located in East Texas and North Louisiana and our legacy South Texas conventional natural gas assets. We completed these sales in 2013 for total consideration of approximately $1.3 billion and recorded a gain on the sale of approximately $468 million. In July 2013, we entered into a Quota Purchase Agreement to sell our Brazil operations which is expected to close in 2014. The sale is subject to Brazilian regulatory approval as well as certain other customary closing conditions. During 2013, we recorded $34 million of impairment charges ($10 million based on a comparison of the fair market value of our Brazil operations to its underlying carrying value when we entered into the purchase and sale agreement and $24 million to impair earnings subsequent to entering into that agreement. We estimated the fair value of our Brazil operations (representing a Level 3 fair value measurement) based primarily on sales proceeds expected to be received less estimates of retained liabilities.

In February 2014, we sold additional domestic natural gas assets in our Atklatex area for approximately $16 million and expect to record a gain on the sale of approximately $12 million in 2014.

We have reflected the domestic natural gas assets sold as discontinued operations in all successor periods and reflected our Brazilian operations as discontinued operations in all periods presented in these consolidated financial statements.  For periods prior to the Acquisition, the predecessor applied the full cost method of accounting for oil and natural gas properties where capitalized costs were aggregated by country (e.g., U.S.); accordingly, these domestic assets sold did not qualify for, and have not been reflected as, discontinued operations in the predecessor financial statement periods.

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

	Successor					Predecessor
	Year ended December 31, 2013			March 23 to December 31, 2012		January 1 to May 24, 2012			Year ended December 31, 2011
Operating revenues	$	297		$	262	$	46		$	111
Operating expenses
Natural gas purchases	19			23		—			—
Transportation costs	18			22		—			—
Lease operating expense	76			65		16			40
Depreciation, depletion and amortization	48			59		12			33
Impairment and ceiling test charges	44			—		—			152
Other expense	41			50		20			31
Total operating expenses	246			219		48			256
Gain on sale of assets	468			—		—			—
Other (expense) income	(2		)	3		(5		)	(1		)
Income (loss) from discontinued operations before income taxes	517			46		(7		)	(146		)
Income tax expense (benefit)	7			2		2			(23		)
Income (loss) from discontinued operations, net of tax	$	510		$	44	$	(9	)	$	(123	)

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	December 31, 2013		December 31, 2012
Assets of discontinued operations
Current assets	$	26	$	95
Property, plant and equipment, net	52		1,019
Other non-current assets	10		13
Total assets of discontinued operations	$	88	$	1,127
Liabilities of discontinued operations
Accounts payable	$	39	$	84
Other current liabilities	10		16
Asset retirement obligations	37		146
Other non-current liabilities	5		7
Total liabilities of discontinued operations	$	91	$	253

Other Divestitures.  During 2013, we (i) received approximately $10 million from the sale of certain domestic oil and natural gas properties and (ii) sold our approximate 49% equity interest in Four Star Oil & Gas Company (Four Star) for proceeds of approximately $183 million. We did not record a gain or loss on the sale of these other domestic properties; however, in connection with entering into the sale of Four Star, we recorded a $20 million impairment in earnings from unconsolidated affiliates. See Note 10 for further discussion.

In 2012, we sold our interests in Egypt for approximately $22 million and sold oil and natural gas properties located in the Gulf of Mexico for a net purchase price of approximately $79 million. We did not record a gain or loss on any of these sales as the purchase price allocated to the assets sold was reflective of the estimated sales price of these properties and the relationship between capitalized costs and proved reserves was not altered.

During 2011, the predecessor sold non-core domestic oil and natural gas properties in several transactions from which they received proceeds that totaled approximately $612 million.  The predecessor did not record a gain or loss on any of these sales.

3.  Impairment and Ceiling Test Charges

During 2013, we recorded a $2 million impairment on certain materials and supplies to reflect a market value lower than underlying cost of those items. Under the full cost method of accounting, the predecessor recorded a non-cash charge of approximately $62 million in the period from January 1 to May 24, 2012,  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.  For the predecessor period ended December 31, 2011, we recorded an impairment of certain oil field related materials and supplies of $6 million to reflect a market value lower than underlying cost of those items.

Forward commodity prices can play a significant role in determining future impairments. Due to the current forecast of future oil, natural gas and NGLs prices and considering the significant amount of fair value allocated to our natural gas and oil 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.

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4.  Income Taxes

Pretax Income (Loss) and Income Tax Expense (Benefit).  The tables below show the pretax income (loss) from continuing operations and the components of income tax expense (benefit) from continuing operations for the following periods:

	Successor					Predecessor
	Year ended December 31, 2013		March 23 (inception) to December 31, 2012			January 1 to May 24, 2012			Year ended December 31, 2011
	(in millions)
Pretax Income (Loss)
U.S.	$	39	$	(299	)	$	384		$	629
Foreign	—		—			(63		)	(1		)
	$	39	$	(299	)	$	321		$	628
Components of Income Tax Expense (Benefit)
Current
Federal	$	—	$	—		$	(62	)	$	(79	)
State	—		—			(3		)	1
	—		—			(65		)	(78		)
Deferred
Federal	—		—			188			302
State	—		—			11			19
	—		—			199			321
Total income tax expense	$	—	$	—		$	134		$	243

Effective Tax Rate Reconciliation.  Income taxes included in net income differs from the amount computed by applying the statutory federal income tax rate of 35 percent for the following reasons for the following periods:

	Successor						Predecessor
	Year ended December 31, 2013			March 23 (inception) to December 31, 2012			January 1 to May 24, 2012			Year ended December 31, 2011
	(in millions, except rates)
Income taxes at the statutory federal rate of 35%	$	14		$	(105	)	$	112		$	220
Increase (decrease)
State income taxes, net of federal income tax effect	—			—			5			12
Partnership earnings not subject to tax	(14		)	105			—			—
Earnings from unconsolidated affiliates where we received or will receive dividends	—			—			(2		)	(8		)
Valuation allowances	—			—			—			15
Foreign income (loss) taxed at different rates	—			—			22			4
Other	—			—			(3		)	—
Income tax expense (benefit)	$	—		$	—		$	134		$	243
Effective tax rate	—		%	—		%	42		%	39		%

The effective tax rate for the successor period for the year ended December 31, 2013 and the period from March 23 (inception) to December 31, 2012 was significantly lower than the statutory rate as we are a limited liability company, treated as a partnership for federal and state income tax purposes, with income tax liabilities and/or benefits of the Company passed through to our members.  The effective tax rate for the predecessor period from January 1, 2012 to May 24, 2012 was significantly higher than the statutory rate primarily due to the impact of an Egyptian non-cash charge without a corresponding tax benefit. For the year ended December 31, 2011, the effective tax rate was higher than the statutory rate primarily due to valuation allowances partially offset by the impact dividend exclusions on earnings from unconsolidated affiliates where the predecessor anticipated receiving dividends and the favorable resolution of certain tax matters related to the first half of 2011.

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Deferred Tax Assets and Liabilities.  In conjunction with the Acquisition, U.S. deferred taxes of the predecessor were settled with El Paso through a non-cash contribution. As a partnership, for U.S. federal and state income tax purposes, we do not record differences between the underlying tax and book basis of our assets and liabilities as deferred taxes.

5.  Financial Instruments

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

	December 31, 2013				December 31, 2012
	Carrying				Carrying
	Amount		Fair Value		Amount		Fair Value
	(in millions)
Long-term debt	$	4,039	$	4,451	$	4,346	$	4,690
Derivative instruments	$	109	$	109	$	165	$	165

For the years ended December 31, 2013 and 2012, the carrying amount of cash and cash equivalents, accounts receivable and accounts payable represent fair value because of the short-term nature of these instruments.  We hold long term debt obligations (see Note 7) with various terms. We estimated the fair value of debt (representing a Level 2 fair value measurement) primarily based on quoted market prices for the same or similar issuances, including consideration of our credit risk related to these instruments.

Oil 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 December 31, 2013 and 2012, we had total derivative contracts of 47 MMBbls and 34 MMBbls of oil and 135 TBtu and 276 TBtu of natural gas, respectively. None of these contracts are designated as accounting hedges.

The following table reflects the volumes associated with derivative contracts entered into between January 1, 2014 and February 24, 2014.

	2014	2015	2016
	Volumes	Volumes(1)	Volumes(1)
Oil (MBbls)
Fixed Price Swaps
Brent	160	2,555	4,026
LLS(1)	—	—	2,562
Basis Swaps	1,557	—	183
Natural Gas (TBtu)
Fixed Price Swaps	—	4	—
NGLs (MMGal)
Propane Fixed Price Swaps	28	—	—
Propane Collars
Ceilings	14	—	—
Floors	14	—	—

(1)In January 2014, we unwound 2,555 MBbls of 2015 WTI fixed price swaps in exchange for 2,562 MBbls of 2016 LLS fixed price swaps. No cash or other considerations was included as part of this exchange.

Interest Rate Derivative Instruments. In 2012, we entered into interest rate swaps with a notional amount of $600 million that are intended to reduce variable interest rate risk. These interest rate derivative instruments started in November 2012 and extend through April 2017.  As of December 31, 2013 and 2012, we had a net asset of  $4 million and a net liability of $2 million, respectively, related to interest rate derivative instruments listed in our consolidated balance sheet. For the year ended December 31, 2013 and the period from March 23 to December 31, 2012 we recorded income of $3 million and expense of $3 million, respectively, in interest expense related to the change in fair market value and cash settlements of our interest rate derivative instruments.

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Fair Value Measurements.  We use various methods to determine the fair values of our financial instruments. The fair value of a financial instrument depends on a number of factors, including the availability of observable market data over the contractual term of the underlying instrument. We separate the fair value of our financial instruments into three levels (Levels 1, 2 and 3) based on our assessment of the availability of observable market data and the significance of non-observable data used to determine fair value. Each of the levels are described below:

·Level 1 instruments’ fair values are based on quoted prices in actively traded markets.

·Level 2 instruments’ fair values are based on pricing data representative of quoted prices for similar assets and liabilities in active markets (or identical assets and liabilities in less active markets).

·Level 3 instruments’ fair values are partially calculated using pricing data that is similar to Level 2 instruments, but also reflect adjustments for being in less liquid markets or having longer contractual terms.

As of December 31, 2013 and 2012, all financial instruments were classified as Level 2. Our assessment of an instrument within a level can change over time based on the maturity or liquidity of the instrument, which could result in a change in the classification of our financial instruments between other levels.

Financial Statement Presentation.  The following table presents the fair value associated with derivative financial instruments as of December 31, 2013 and 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 derivative contracts recorded as assets in the table below, we are exposed to the risk that our counterparties may not perform.

	Level 2
	Derivative Assets									Derivative Liabilities
	Gross(1)					Balance Sheet Location				Gross(1)					Balance Sheet Location
	Fair Value		Impact of Netting			Current		Non- current		Fair Value			Impact of Netting		Current			Non-current
	(in millions)									(in millions)
December 31, 2013
Derivatives	$	164	$	(20	)	$	47	$	97	$	(55	)	$	20	$	(35	)	$	—
December 31, 2012
Derivatives	$	235	$	(39	)	$	108	$	88	$	(70	)	$	39	$	(17	)	$	(14	)

(1)Gross derivative assets are comprised primarily of $157 million and $231 million of oil and natural gas derivatives and $7 million and $4 million of interest rate derivatives as of December 31, 2013 and December 31, 2012, respectively.  Gross derivative liabilities are comprised primarily of $52 million and $64 million of oil and natural gas derivatives and $3 million and $6 million of interest rate derivatives as of December 31, 2013 and December 31, 2012, respectively.

The following table presents gains and losses on financial oil and natural 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
	Year ended December 31,			March 23 (inception) to December 31,			January 1 to May 24,		Year ended December 31,
	2013			2012			2012		2011
(Losses) gains on financial derivative instruments	$	(52	)	$	(62	)	$	365	$	284
Accumulated other comprehensive income	—			—			5		11

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Credit Risk. We are subject to the risk of loss on our financial instruments that we would incur as a result of non-performance by counterparties pursuant to the terms of their contractual obligations. We maintain credit policies with regard to our counterparties to minimize our overall credit risk. These policies require (i) the evaluation of potential counterparties’ financial condition to determine their credit worthiness; (ii) the daily monitoring of our oil, natural gas and NGLs counterparties’ credit exposures; (iii) comprehensive credit reviews on significant counterparties from physical and financial transactions on an ongoing basis; (iv) the utilization of contractual language that affords us netting or set off opportunities to mitigate exposure risk; and (v) when appropriate requiring counterparties to post cash collateral, parent guarantees or letters of credit to minimize credit risk.  Our assets related to derivatives as of December 31, 2013 represent derivative instruments from twelve counterparties; all of which are financial institutions that have an “investment grade” (minimum Standard & Poor’s rating of A- or better) credit rating and are lenders associated with our $2.5 billion RBL credit facility. Subject to the terms of our $2.5 billion RBL credit facility, collateral or other securities are not exchanged in relation to derivatives activities with the parties in the RBL Facility.

6.  Property, Plant and Equipment

Unproved Oil and Natural Gas Properties (Successor).  As December 31, 2013 and December 31, 2012, we had $1.4 billion and $2.3 billion of unproved oil and natural gas properties on our balance sheet.  During 2013, we transferred approximately $0.8 billion from unproved properties to proved properties. During 2013 and the successor period of 2012, we recorded $36 million and $23 million of amortization of unproved leasehold costs in exploration expense in our income statement. Suspended well costs were not material as of December 31, 2013 or December 31, 2012.

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

In estimating the liability associated with our asset retirement obligations, we utilize several assumptions, including a credit-adjusted risk-free rate of 7 percent and a projected inflation rate of 2.5 percent. Changes in estimates in the table below represent changes to the expected amount and timing of payments to settle our asset retirement obligations. Typically, these changes primarily result from obtaining new information about the timing of our obligations to plug and abandon oil and natural gas wells and the costs to do so. The net asset retirement liability as of December 31 on our consolidated balance sheet in other current and non-current liabilities, and the changes in that liability for the periods ended December 31 were as follows:

	Year ended December 31, 2013			March 23  (inception) to December 31, 2012
	(in millions)
Net asset retirement liability at beginning of period	$	44		$	—
Fair value of asset retirement liability at Acquisition date	—			102
Liabilities settled	(2		)	(2		)
Property sale(1)	(1		)	(64		)
Accretion expense	4			3
Liabilities incurred	7			5
Other	1			—
Net asset retirement liability at December 31(2)	$	53		$	44

(1)From March 23 to December 31, 2012, property sales relate to the sale of properties in the Gulf of Mexico.

(2)Amounts do not include $37 million and $36 million as of December 31, 2013 and 2012, respectively, of net asset retirement liability associated with our Brazil operations classified as discontinued operations.

Capitalized Interest.  Interest expense is reflected in our financial statements net of capitalized interest. We capitalize interest primarily on the costs associated with drilling and completing wells until production begins. The interest rate used is the weighted average interest rate of our outstanding borrowings. Capitalized interest for the year ended December 31, 2013 was $19 million.  For the period from March 23, 2012 (inception) to December 31, 2012 capitalized interest was $12 million, and for the predecessor periods from January 1, 2012 to May 24, 2012 and the year ended December 31, 2011, it was $4 million and $13 million, respectively.

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7.  Long Term Debt

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

		Interest Rate	December 31, 2013		December 31, 2012
		(in millions)
$	2.5 billion RBL credit facility - due May 24, 2017	Variable	$	295	$	105
$	750 million senior secured term loan - due May 24, 2018(1)(3)	Variable	495		742
$	400 million senior secured term loan - due April 30, 2019(2)(3)	Variable	149		399
$	750 million senior secured notes - due May 1, 2019(3)	6.875%	750		750
$	2.0 billion senior unsecured notes - due May 1, 2020	9.375%	2,000		2,000
$	350 million senior unsecured notes - due September 1, 2022	7.75%	350		350
Total			$	4,039	$	4,346

(1)The Term Loan was issued at 99 percent of par and carries interest at a specified margin over the LIBOR of 4.00%, with a minimum LIBOR floor of 1.00%. As of December 31, 2013 the effective interest rate of the note was 3.50%.  In May 2013, we entered into an agreement to reprice our term loan which will carry interest at 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 interest at a specified margin over the LIBOR of 3.50%, with a minimum LIBOR floor of 1.00%.

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

As of December 31, 2013 and 2012 we have $111 million and $134 million, respectively, in deferred financing costs on our consolidated balance sheets. During 2013, the period from March 23 (inception) to December 31, 2012, and the predecessor period from January 1 to May 24, 2012, we amortized $21 million, $13 million, and $7 million, respectively, of deferred financing costs.  These costs are included in interest expense.  During 2013, we recorded a $9 million loss on the extinguishment of debt in our consolidated income statement reflecting the pro-rata portion of deferred financing costs written off in conjunction with (i) the repayment of approximately $250 million under each of our $750 million and $400 million term loans, (ii) our $750 million term loan re-pricing in May 2013 and (iii) the semi-annual redetermination of our RBL Facility in March 2013.  During the successor period of 2012, we recorded a $14 million loss on debt extinguishment in our consolidated income statement reflecting the pro-rata portion of deferred financing costs written off, debt discount and call premiums paid related to lenders who exited or reduced their loan commitments in conjunction with our $750 million term loan repricing.

$2.5 Billion Reserve-based Loan (RBL). We have a $2.5 billion credit facility in place which allows us to borrow funds or issue letters of credit (LCs).  As of December 31, 2013, we had $295 million of outstanding borrowings and approximately $8 million of letters of credit issued under the facility, leaving $2.2 billion of remaining capacity available.  During 2014, we received a contribution from our parent subsequent to their initial public offering to pay down a portion of our then outstanding balance.  As of February 24, 2014 we had $275 million in outstanding borrowings under the facility.  Listed below is a further description of our credit facility as of December 31, 2013:

Credit Facility	Maturity Date	Interest Rate	Commitment fees
$2.5 billion RBL	May 24, 2017	LIBOR + 1.50%(1) 1.50% for LCs	0.375% commitment fee on unused capacity

(1)  Based on our December 31, 2013 borrowing level. Amounts outstanding under the $2.5 billion RBL facility bear interest at specified margins over the LIBOR of between 1.50% and 2.50% for Eurodollar loans or at specified margins over the Alternative Base Rate (ABR) of between 0.50% and 1.50% for ABR loans. Such margins will fluctuate based on the utilization of the facility.

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

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Guarantees.  Our obligations under the RBL Facility, term loan, secured and unsecured notes are fully and unconditionally guaranteed, jointly and severally, by the Company’s present and future direct and indirect wholly owned material domestic subsidiaries. Our foreign wholly-owned subsidiaries are not parties to the guarantees.   As of December 31, 2013, foreign subsidiaries that do not guarantee the unsecured notes and are recorded as discontinued operations held approximately 1% of our consolidated assets and had no outstanding indebtedness, excluding intercompany obligations. For the year ended December 31, 2013, and for the period from March 23 (inception) to December 31, 2012, these non-guarantor subsidiaries generated approximately 5% and 7%, respectively, 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. Our most restrictive financial covenant requires that our debt to EBITDAX ratio, as defined in the credit agreement, must not exceed 4.75 to 1.0 during the current period. Certain other covenants and restrictions, among other things, also limit our ability to incur or guarantee additional indebtedness; make any restricted payments or pay any dividends on equity interests or redeem, repurchase or retire parent entities’ equity interests or subordinated indebtedness; sell assets; make investments; create certain liens; prepay debt obligations; engage in transactions with affiliates; and enter into certain hedge agreements. As of December 31, 2013, we were in compliance with our debt covenants.

8.  Commitments and Contingencies

Legal Matters

We and our subsidiaries and affiliates are parties to various legal actions and claims that arise in the ordinary course of our business.  For each of these matters, we evaluate the merits of the case or claim, our exposure to the matter, possible legal or settlement strategies and the likelihood of an unfavorable outcome.  If we determine that an unfavorable outcome is probable and can be estimated, we establish the necessary accruals. While the outcome of our current matters cannot be predicted with certainty and there are still uncertainties related to the costs we may incur, based upon our evaluation and experience to date, we believe we have established appropriate reserves for these matters. It is possible, however, that new information or future developments could require us to reassess our potential exposure related to these matters and adjust our accruals accordingly, and these adjustments could be material. As of December 31, 2013, we had approximately $1 million accrued for all outstanding legal matters.

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

Indemnification and Other Matters. We periodically enter into indemnification arrangements as part of the divestitures of  assets or businesses.  These arrangements include, but are not limited to, indemnifications for income taxes, the resolution of existing disputes, environmental and other contingent matters. In addition, under various laws or regulations, we could be subject to the imposition of certain liabilities, for example, plugging and abandonment obligations for assets no longer owned or operated by us.  As of December 31, 2013, we had approximately $5 million accrued related to these indemnifications and other matters.

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

Environmental Matters

We are subject to existing federal, state and local laws and regulations governing environmental quality, pollution control and greenhouse gas (GHG) emissions. The environmental laws and regulations to which we are subject also require us to remove or remedy the effect on the environment of the disposal or release of specified substances at current and former operating sites. As of December 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

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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 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 regarding GHG emissions would likely increase our costs of compliance by potentially delaying the receipt of permits and other regulatory approvals; requiring us to monitor emissions, install additional equipment or modify facilities to reduce GHG and other emissions; purchase emission credits; and utilize electric-driven compression at facilities to obtain regulatory permits and approvals in a timely manner.

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

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

The EPA has promulgated regulations to require pre-construction permits for minor sources of air emissions in tribal lands as of September 2, 2014.  On January 14, 2014, EPA proposed extending this deadline twelve to eighteen months, during which time EPA anticipates separate rulemaking to create general permits for true minor sources in the oil and gas production industry.  Comments to EPA’s proposed extension are due March 17, 2014.  Until such regulations are adopted, it is uncertain what impact they might have on our operations in tribal lands.

In the State of Utah we are currently obtaining or amending air quality permits for a number of small oil and natural gas production facilities. As part of this permitting process, we incurred capital expenditures of less than $1 million during 2013 and anticipate that we will incur less than $1 million in 2014 related to the installation of storage tank emission controls at our existing facilities.

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

Comprehensive Environmental Response, Compensation and Liability Act (CERCLA) Matters. As part of our environmental remediation projects, we are or have received notice that we could be designated as a Potentially Responsible Party (PRP) with respect to one active site under the CERCLA or state equivalents. As of December 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 because in some cases we have asserted a defense to any liability, our estimates could change. Moreover, liability under the federal CERCLA statute may be joint and several, meaning that we could be required to pay in excess of our pro rata share of remediation costs. Our understanding of the financial strength of other PRPs has been considered, where appropriate, in estimating our liabilities. Accruals for these matters are included in the reserve for environmental matters discussed above.

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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.

Lease Obligations

We maintain operating leases in the ordinary course of our business activities.  These leases include those for office space and various equipment.  The terms of the agreements vary from 2012 through 2018.  Future minimum annual rental commitments under non-cancelable future operating lease commitments at December 31, 2013, were as follows:

Year Ending December 31,	Operating Leases
	(in millions)
2014	$	12
2015	11
2016	11
2017	8
2018	—
Total	$	42

Rental expense for the successor periods for the year ended December 31, 2013 and for the period from March 23, 2012 (inception) to December 31, 2012 was $13 million and $10 million, respectively. Rental expense for the predecessor periods from January 1, 2012 to May 24, 2012 and the year ended December 31, 2011 was $1 million and $2 million, respectively.

Other Commercial Commitments

At December 31, 2013, we have various commercial commitments totaling $894 million primarily related to commitments and contracts associated with volume and transportation, drilling rigs, completion activities, seismic activities and management fees. Our annual obligations under these arrangements are $143 million in 2014, $95 million in 2015, $100 million in 2016, $100 million in 2017, $102 million in 2018, and $354 million thereafter.  We were party to a management fee agreement requiring an annual management fee of $25 million paid to our Sponsors. Commencing on January 1, 2014, the agreement was amended whereby the management fee is payable in non-refundable quarterly installments of $6.25 million at the beginning of each quarter and was paid by us on January 1, 2014.  Also in January, the amended agreement was terminated.

9.  Long-Term Incentive Compensation / Retirement 401(k) Plan

Long Term Incentive Compensation Programs. Upon the closing of the Acquisition, we adopted new long term incentive (LTI) programs, including an annual performance-based cash incentive payment program and certain long-term equity based programs.  For accounting and financial reporting purposes, we record the compensation expense related to these awards issued to our employees.  Each of these awards is further discussed below:

·Cash-Based Long Term Incentive.  In 2012 and 2013, we provided long term cash-based incentives to certain of our employees linking annual performance-based cash incentive payments to the financial performance of the company as approved by the Compensation Committee of the board of directors of our parent, EPE Acquisition, LLC, and the employee’s individual performance for the year.  These cash-based LTI awards have a three-year vesting schedule (50% vesting at the end of the first year, and 25% vesting at the end of each of the succeeding two years). These performance based cash incentive awards were treated as liability awards.  Cash-based LTI awards granted during 2013 and 2012 had a fair value of $22 million and $24 million on each respective grant date that will be amortized primarily on an accelerated basis over a three-year vesting period. For the year ended December 31, 2013 and for the period from March 23 (inception) to December 31, 2012, we recorded approximately $16 million and $8 million, respectively, in expense related to these awards.  As of December 31, 2013, we had unrecognized compensation expense of $12 million related to these awards of which approximately $9 million will be recognized in 2014 and the remainder on an accelerated basis over the remaining requisite service period.

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·Long Term Equity Incentive Awards.  We have provided certain individuals with long term equity incentive awards as follows:

·Class A “Matching” Grants.  In conjunction with the Acquisition, certain of our employees purchased Class A units. In connection with their purchase of these units, these employees were awarded (i) “matching” Class A unit grants in an amount equal to 50% of the Class A units purchased subject to repurchase by the company in the event of certain termination scenarios and (ii) a “guaranteed cash bonus” which was treated as a liability award and was paid in March 2013 equivalent to the amount of the “matching” Class A unit grant.  For accounting purposes, we treated the “matching” Class A unit grants as compensatory equity awards. These awards had a combined fair value of approximately $24 million on the grant date. For the “guaranteed cash bonus”, we  recognized the fair value as compensation cost over the period from the date of grant (May 24, 2012) through the cash payout date in March 2013. For the “matching” Class A unit grant, we recognize the fair value as compensation cost ratably over the four year period from the date of grant through the period over which the requisite service is provided and the time period at which certain transferability restrictions are removed. For the year ended December 31, 2013 and the period from March 23 (inception) to December 31, 2012, we recognized approximately $6 million and $11 million, respectively, as compensation expense related to both of these awards.  As of December 31, 2013, we had unrecognized compensation expense of $7 million related to the “matching” Class A unit grants, of which we will recognize $3 million in 2014 and the remainder ratably thereafter as noted above.

·Management Incentive Units.  In addition to the Class A “matching” awards described above, certain employees were awarded Management Incentive Units (MIPs). These MIPs are intended to constitute profits interests.  Each award of MIPs represents a share in any future appreciation of the company after the date of grant, subject to certain limitations, and once certain shareholder returns have been achieved. The MIPs vest ratably over 5 years subject to certain forfeiture provisions based on continued employment with the company, although 25% of any vested awards are forfeitable in the event of certain termination events. The MIPs become payable based on the achievement of certain predetermined performance measures, including, without limitation, the occurrence of certain specified capital transactions. The MIPs were issued at no cost to the employees and have value only to the extent the value of the company increases. For accounting purposes, these profits interests were treated as compensatory equity awards. On May 24, 2012, the grant date fair value of this award was determined using a non-controlling, non-marketable option pricing model which valued these management incentive units assuming a 0.77 %  risk free rate, a 5 year time to expiration, and a 73 percent volatility rate.  Based on these factors, we determined a grant date fair value of $74 million. For the year ended December 31, 2013 and the period from March 23 (inception) to December 31, 2012, we recognized approximately $19 million and $15 million, respectively, of compensation expense related to these awards.  As of December 31, 2013, we had unrecognized compensation expense of $40 million. Of this amount, $21 million of the unrecognized compensation expense, net of forfeitures, will continue to be recognized on an accelerated basis for each tranche of the award, over the remainder of the five year requisite service period. The remaining $19 million will be recognized upon a specified capital transaction when the right to such amounts become nonforfeitable.

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

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Retirement 401(k) Plan.  We sponsor a tax-qualified defined contribution retirement plan for a broad-based group of employees.  We make matching contributions (dollar for dollar up to 6% of eligible compensation) and non-elective employer contributions (5% of eligible compensation) to the plan, and individual employees are also eligible to contribute to the defined contribution plan.  During 2013 and after the Acquisition in 2012, we had contributed $12 million and $7 million, respectively, of matching and non-elective employer contributions.

10.  Investments in Unconsolidated Affiliate

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

Below is summarized financial information of the operating results of Four Star (in millions).

	Successor				Predecessor
	Year ended						Year ended
	December 31,		March 23 (inception) to		January 1 to		December 31,
	2013		December 31, 2012		May 24, 2012		2011
	(in millions)
Operating revenues	$	142	$	105	$	75	$	257
Operating expenses	94		87		58		167
Net income	30		11		11		60

	December 31, 2012
	(in millions)
Financial position data:
Current assets	$	64
Non-current assets	241
Current liabilities	51
Non-current liabilities	133
Equity in net assets	121

In addition to recording our share of Four Star operating results, we amortized the excess of our investment in Four Star prior to its sale over the underlying equity in its net assets using the unit-of-production method over the life of our estimate of Four Star’s oil and natural gas reserves. Amortization of our investment for the year ended December 31, 2013, and the period of March 23 to December 31, 2012, was $8 million and $7 million, respectively. Amortization of our investment for the predecessor period from January 1 to May 24, 2012  and for the year ended December 31, 2011 was $12 million and $34 million, respectively.

For the year ended December 31, 2013, and the period from March 23 (inception) to December 31, 2012, we received dividends from Four Star of approximately $24 million and $13 million, respectively. Dividends received from Four Star for the predecessor period from January 1 to May 24, 2012 and for the year ended December 31, 2011 were $8 million and $46 million, respectively.

11.  Related Party Transactions

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

Transaction Fee Agreement. Following the Acquisition, we were subject to a transaction fee agreement with certain of our Sponsors (the Service Providers) for the provision of certain structuring, financial, investment banking and other similar advisory services. At the time of the Acquisition, we paid one-time transaction fees of $71.5 million (recorded as general and administrative expense in our income statement) to the Service Providers in the aggregate in exchange for services rendered in connection with structuring, arranging the financing and performing other services. On December 20, 2013, the Transaction Fee Agreement was amended and restated in its entirety pursuant to which the requirement to pay an additional transaction fee to the Service Providers

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under the agreement was eliminated (and, as described below, an additional fee became payable under the amended and restated Management Fee Agreement). The amended and restated Transaction Fee Agreement terminated automatically in accordance with its terms upon the closing of our parent’s initial public offering

Management Fee Agreement. We entered into a management fee agreement with certain of our Sponsors to provide certain management consulting and advisory services which terminates on the twelve-year anniversary of the Acquisition (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 fee agreement, we paid a non-refundable annual management fee of $25 million at the beginning of each year.  For the year ended December 31, 2013 we recognized approximately $26 million in general and administrative expense related to the management fee and other fees.   Commencing in 2014, the management fee became payable in quarterly installments at the beginning of each calendar quarter, and on January 1, 2014, we paid $6.25 million for services to be rendered in that quarter. The management fee agreement terminated later in January 2014.

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 December 31, 2013, we recorded approximately $120 million as capital expenditures for amounts provided under this agreement.

Related Party Transactions Prior to the Acquisition. At the time of the Acquisition, El Paso made total contributions of approximately $1.5 billion to the predecessor including a non-cash contribution of approximately $0.5 billion to satisfy its then current and deferred income tax balances and a cash contribution to facilitate repayment of approximately $960 million of then outstanding debt of the predecessor under its revolving credit facility. Additionally, 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 NGLs production.

The agreements noted below ceased on the date of Acquisition and included the following services:

·       General. 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. El Paso also 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.  Compensation cost associated with the acceleration of vesting as a result of the merger between El Paso and KMI was assumed by El Paso and KMI and is not reflected in the predecessor financial statements.

·Pension and Retirement Benefits.  El Paso maintained a primary pension plan, the El Paso Corporation Pension Plan, a defined benefit plan covering substantially all of our employees prior to the Acquisition and providing benefits under a cash balance formula. El Paso also maintained a defined contribution plan covering all of our employees prior to the Acquisition. El Paso matched 75 percent of participant basic contributions up to 6 percent of eligible compensation and made additional discretionary matching contributions. El Paso was responsible for benefits accrued under these plans and allocated related costs.

·Other Post-Retirement Benefits.  El Paso provided limited post-retirement life insurance benefits for current and retired employees prior to the Acquisition. El Paso was responsible for benefits accrued under its plan and allocated the related costs to its affiliates.

·Marketing. Prior to the completion of the Acquisition, the predecessor sold natural gas primarily to El Paso Marketing at spot market prices. The predecessor was also a party to a hedging contract with El Paso Marketing. Realized gains and losses on these hedges were included in operating revenues.

·Transportation and Related Services. Prior to the completion of the Acquisition, the predecessor contracted for services with El Paso’s regulated interstate pipelines that provided transportation and related services for natural gas production.

73

The following table shows revenues and charges to/from affiliates for the following predecessor periods (in millions):

	Predecessor
	January 1 to May 24, 2012		Year ended December 31, 2011
Operating revenues	$	143	$	634
Operating expenses	44		138
Reimbursements of operating expenses	—		3

·Income Taxes.  Prior to the Acquisition, El Paso filed consolidated U.S. federal and certain state tax returns which included the predecessor’s taxable income. See Note 4 for additional information on income tax related matters.

·Cash Management Program. Prior to the Acquisition, our predecessor participated in El Paso’s cash management program which matched short-term cash surpluses and needs of its participating affiliates, thus minimizing total borrowings from outside sources.

12. 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 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 our consolidated financial statements are presented herein.

74

EP ENERGY LLC

CONSOLIDATING STATEMENT OF INCOME

FOR THE YEAR ENDED DECEMBER 31, 2013

(In millions)

	Successor
	Issuer			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Eliminations			Consolidated
Operating revenues
Oil and condensate	$	—		$	1,283		$	—		$	—		$	1,283
Natural gas	—			331			—			—			331
NGLs	—			78			—			—			78
Financial derivatives	(52		)	—			—			—			(52		)
Total operating revenues	(52		)	1,692			—			—			1,640
Operating expenses
Natural gas purchases	—			25			—			—			25
Transportation costs	—			92			—			—			92
Lease operating expense	—			163			—			—			163
General and administrative	49			179			—			—			228
Depreciation, depletion and amortization	—			618			—			—			618
Impairment and ceiling test charges	—			2			—			—			2
Exploration expense	—			45			—			—			45
Taxes, other than income taxes	—			86			—			—			86
Total operating expenses	49			1,210			—			—			1,259
Operating (loss) income	(101		)	482			—			—			381
Loss from unconsolidated affiliate	—			(13		)	—			—			(13		)
Earnings from consolidated subsidiaries	474			—			—			(474		)	—
Other income	—			1			—			—			1
Affiliated interest (expense) income	(4		)	4			—			—			—
Loss on extinguishment of debt	(9		)	—			—			—			(9		)
Interest expense	(321		)	—			—			—			(321		)
Income from continuing operations before income taxes	39			474			—			(474		)	39
Income tax expense	—			—			—			—			—
Income from continuing operations	39			474			—			(474		)	39
Income (loss) from discontinued operations, net of tax	510			510			(5		)	(505		)	510
Net income (loss)	$	549		$	984		$	(5	)	$	(979	)	$	549

75

EP ENERGY LLC

CONSOLIDATING STATEMENT OF INCOME

FOR THE PERIOD FROM MARCH 23, 2012 (INCEPTION) TO DECEMBER 31, 2012

(In millions)

	Successor
	Issuer			Guarantor Subsidiaries			Non- Guarantor Subsidiaries		Eliminations			Consolidated
Operating revenues
Oil and condensate	$	—		$	523		$	—	$	—		$	523
Natural gas	—			234			—		—			234
NGLs	—			32			—		—			32
Financial derivatives	(50		)	(12		)	—		—			(62		)
Total operating revenues	(50		)	777			—		—			727
Operating expenses
Natural gas purchases	—			19			—		—			19
Transportation costs	—			51			—		—			51
Lease operating expense	—			71								71
General and administrative	206			152			—		—			358
Depreciation, depletion and amortization	—			209			—		—			209
Impairment and ceiling test charges	—			1			—		—			1
Exploration expense	—			43			—		—			43
Taxes, other than income taxes	—			41			—		—			41
Total operating expenses	206			587			—		—			793
Operating (loss) income	(256		)	190			—		—			(66		)
Loss from unconsolidated affiliate	—			(1		)	—		—			(1		)
Earnings from consolidated subsidiaries	188			—			—		(188		)	—
Other income (expense)	1			(1		)	—		—			—
Loss on extinguishment of debt	(14		)	—			—		—			(14		)
Interest expense	(218		)	—			—		—			(218		)
(Loss) income from continuing operations before income taxes	(299		)	188			—		(188		)	(299		)
Income tax expense	—			—			—		—			—
(Loss) income from continuing operations	(299		)	188			—		(188		)	(299		)
Income from discontinued operations, net of tax	44			44			12		(56		)	44
Net (loss) income	$	(255	)	$	232		$	12	$	(244	)	$	(255	)

76

EP ENERGY LLC

CONSOLIDATING STATEMENT OF INCOME AND COMPREHENSIVE INCOME

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

(In millions)

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

(1)Reclassification adjustments are stated net of tax. Taxes recognized for the predecessor period related to January 1, 2012 to May 24, 2012 are $2 million.

77

EP ENERGY LLC

CONSOLIDATING STATEMENT OF INCOME AND COMPREHENSIVE INCOME

FOR THE YEAR ENDED DECEMBER 31, 2011

(In millions)

	Predecessor
	Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Eliminations		Consolidated
Operating revenues
Oil and condensate	$	513		$	—		$	—	$	513
Natural gas	901			—			—		901
NGLs	58			—			—		58
Financial derivatives	284			—			—		284
Total operating revenues	1,756			—			—		1,756
Operating expenses
Transportation costs	85			—			—		85
Lease operating expense	177			—			—		177
General and administrative	185			—			—		185
Depreciation, depletion and amortization	579			—			—		579
Impairment and ceiling test charges	6			—			—		6
Taxes, other than income taxes	76			—			—		76
Total operating expenses	1,108			—			—		1,108
Operating income	648			—			—		648
Loss from unconsolidated affiliate	(7		)	—			—		(7		)
Other income	1			—			—		1
Interest (expense) income
Third party	(10		)	1			—		(9		)
Affiliated	(4		)	(1		)	—		(5		)
Income from continuing operations before income taxes	628			—			—		628
Income tax expense	243			—			—		243
Income from continuing operations	385			—			—		385
Loss from discontinued operations, net of tax	(123		)	(123		)	123		(123		)
Net income (loss)	$	262		$	(123	)	$	123	$	262
Cash flow hedging activities:
Reclassification adjustment(1)	7			—			—		7
Comprehensive income (loss)	$	269		$	(123	)	$	123	$	269

(1)             Reclassification adjustments are stated net of tax. Taxes recognized for the predecessor period related to the year ended December 31, 2011 are $4 million.

78

EP ENERGY LLC

CONSOLIDATING BALANCE SHEET

AS OF DECEMBER 31, 2013

(In millions)

	Issuer		GuarantorSubsidiaries		Non- GuarantorSubsidiaries		Eliminations			Consolidated
ASSETS
Current assets
Cash and cash equivalents	$	15	$	—	$	33	$	—		$	48
Accounts receivable
Customer, net of allowance of less than $1	5		234		—		—			239
Other, net of allowance of $2	1		40		—		—			41
Materials and supplies	—		20		—		—			20
Derivative instruments	47		—		—		—			47
Assets of discontinued operations	—		30		85		(27		)	88
Prepaid assets	—		12		—		—			12
Total current assets	68		336		118		(27		)	495
Property, plant and equipment, at cost
Oil and natural gas properties	—		8,371		—		—			8,371
Other property, plant and equipment	—		63		—		—			63
	—		8,434		—		—			8,434
Less accumulated depreciation, depletion and amortization	—		818		—		—			818
Total property, plant and equipment, net	—		7,616		—		—			7,616
Other assets
Investment in unconsolidated affiliate	8,142		—		—		(8,142		)	—
Derivative instruments	97		—		—		—			97
Assets of discontinued operations	—		—		—		—			—
Notes receivable from consolidated affiliate	—		832		—		(832		)	—
Unamortized debt issue cost	111		—		—		—			111
Other	—		7		—		—			7
	8,350		839		—		(8,974		)	215
Total assets	$	8,418	$	8,791	$	118	$	(9,001	)	$	8,326

79

EP ENERGY LLC

CONSOLIDATING BALANCE SHEET

AS OF DECEMBER 31, 2013

(In millions)

	Issuer		GuarantorSubsidiaries		Non- GuarantorSubsidiaries		Eliminations			Consolidated
LIABILITIES AND EQUITY
Current liabilities
Accounts payable
Trade	$	2	$	138	$	—	$	—		$	140
Other	—		387		—		—			387
Derivative instruments	35		—		—		—			35
Accrued interest	54		—		—		—			54
Asset retirement obligations	—		3		—		—			3
Liabilities of discontinued operations	—		—		91		—			91
Other accrued liabilities	1		64		—		—			65
Total current liabilities	92		592		91		—			775
Long-term debt	4,039		—		—		—			4,039
Notes payable to consolidated affiliate	832		—		—		(832		)	—
Other long-term liabilities
Derivative instruments	—		—		—		—			—
Liabilities of discontinued operations	—		—		—		—			—
Asset retirement obligations	—		50		—		—			50
Other	—		7		—		—			7
Total non-current liabilities	4,871		57		—		(832		)	4,096
Commitments and contingencies
Member’s equity	3,455		8,142		27		(8,169		)	3,455
Total liabilities and equity	$	8,418	$	8,791	$	118	$	(9,001	)	$	8,326

80

EP ENERGY LLC

CONSOLIDATING BALANCE SHEET

AS OF DECEMBER 31, 2012

(In millions)

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

81

EP ENERGY LLC

CONSOLIDATING BALANCE SHEET

AS OF DECEMBER 31, 2012

(In millions)

	Successor
	Issuer		GuarantorSubsidiaries		Non- GuarantorSubsidiaries		Eliminations			Consolidated
LIABILITIES AND EQUITY
Current liabilities
Accounts payable
Trade	$	—	$	98	$	—	$	—		$	98
Other accrued liabilities	—		302		—		—			302
Derivative instruments	10		7		—		—			17
Accrued interest	57		—		—		—			57
Asset retirement obligations	—		4		—		—			4
Liabilities of discontinued operations	—		156		58		(3		)	211
Other accrued liabilities	—		74		—		—			74
Total current liabilities	67		641		58		(3		)	763
Long-term debt	4,346		—		—		—			4,346
Notes payable to consolidated affiliate	—		45		—		(45		)	—
Other long-term liabilities
Derivative instruments	7		7		—		—			14
Liabilities of discontinued operations	—		—		42		—			42
Asset retirement obligations	—		40		—		—			40
Other	—		3		—		—			3
Total non-current liabilities	4,353		95		42		(45		)	4,445
Commitments and contingencies
Member’s equity	3,085		7,124		46		(7,170		)	3,085
Total liabilities and equity	$	7,505	$	7,860	$	146	$	(7,218	)	$	8,293

82

EP ENERGY LLC

CONSOLIDATING STATEMENT OF CASH FLOWS

FOR THE YEAR ENDED DECEMBER 31, 2013

(In millions)

	Successor
	Issuer			GuarantorSubsidiaries			Non- GuarantorSubsidiaries			Eliminations			Consolidated
Cash flows from operating activities
Net income (loss)	$	549		$	984		$	(5	)	$	(979	)	$	549
Adjustments to reconcile net income (loss) to net cash (used in) provided by operating activities
Depreciation, depletion and amortization	—			659			7			—			666
Gain on sale of assets	—			(468		)	—			—			(468		)
Loss from unconsolidated affiliate, net of cash distributions	—			37			—			—			37
Deferred income taxes	—			—			1			—			1
Earnings from consolidated affiliates	(984		)	5			—			979			—
Impairment and ceiling test charges	—			12			34			—			46
Loss on extinguishment of debt	9			—			—			—			9
Amortization of equity compensation expense	22			—			—			—			22
Non-cash portion of exploration expense	—			39			—			—			39
Equity distributions from consolidated affiliate	—			15			—			(15		)	—
Other non-cash income items	22			—			—			—			22
Asset and liability changes
Accounts receivable	—			(58		)	10			(3		)	(51		)
Accounts payable	1			85			(9		)	3			80
Derivative instruments	56			—			—			—			56
Accrued interest	(3		)	—			—			—			(3		)
Other asset changes	—			(8		)	(2		)	—			(10		)
Other liability changes	—			(18		)	(2		)	—			(20		)
Net cash (used in) provided by operating activities	(328		)	1,284			34			(15		)	975
Cash flows from investing activities
Capital expenditures	(19		)	(1,905		)	—			—			(1,924		)
Net proceeds from the sale of assets and investments	—			1,451			—			—			1,451
Cash paid for acquisitions, net of cash acquired	—			(2		)	—			—			(2		)
Change in note receivable with affiliate	45			(832		)	—			787			—
Net cash provided by (used in) investing activities	26			(1,288		)	—			787			(475		)
Cash flows from financing activities
Proceeds from long-term debt	1,880			—			—			—			1,880
Repayment of long-term debt	(2,190		)	—			—			—			(2,190		)
Distributions to member	(200		)	—			—			—			(200		)
Dividends to affiliate	—			—			(15		)	15			—
Change in note payable with affiliate	832			(45		)	—			(787		)	—
Debt issuance costs	(5		)	—			—			—			(5		)
Net cash provided by (used in) financing activities	317			(45		)	(15		)	(772		)	(515		)
Change in cash and cash equivalents	15			(49		)	19			—			(15		)
Cash and cash equivalents
Beginning of period	—			49			14			—			63
End of period	$	15		$	—		$	33		$	—		$	48

83

EP ENERGY LLC

CONSOLIDATING STATEMENT OF CASH FLOWS

FOR THE PERIOD FROM MARCH 23, 2012 (INCEPTION) TO DECEMBER 31, 2012

(In millions)

	Successor
	Issuer			GuarantorSubsidiaries			Non- GuarantorSubsidiaries			Eliminations			Consolidated
Cash flows from operating activities
Net (loss) income	$	(255	)	$	232		$	12		$	(244	)	$	(255	)
Adjustments to reconcile net (loss) income to net cash (used in) provided by operating activities
Depreciation, depletion and amortization	—			260			8			—			268
Deferred income tax expense	—			—			1			—			1
Loss from unconsolidated affiliates, net of cash distributions	—			15			—			—			15
Earnings from consolidated affiliates	(232		)	(12		)	—			244			—
Equity distributions from consolidated affiliates	—			15			—			(15		)	—
Impairment and ceiling test charges	—			1			—			—			1
Loss on extinguishment of debt	14			—			—			—			14
Amortization of equity compensation expense	17			—			—			—			17
Non-cash portion of exploration expense	—			23			—			—			23
Amortization of debt issuance costs	13			—			—			—			13
Asset and liability changes
Accounts receivable	(6		)	(59		)	(11		)	3			(73		)
Accounts payable	1			55			13			(3		)	66
Derivative instruments	131			150			—			—			281
Accrued Interest	57			—			—			—			57
Other asset changes	—			(17		)	(1		)	—			(18		)
Other liability changes	—			35			4			—			39
Net cash (used in) provided by operating activities	(260		)	698			26			(15		)	449
Cash flows from investing activities
Capital expenditures	(12		)	(860		)	(5		)	—			(877		)
Net proceeds from the sale of assets	—			110			—			—			110
Cash paid for acquisitions, net of cash acquired	(7,213		)	—			—			87			(7,126		)
Change in note receivable with affiliate	(23		)	4			—			19			—
Net cash (used in) provided by investing activities	(7,248		)	(746		)	(5		)	106			(7,893		)
Cash flows from financing activities
Proceeds from long-term debt	5,477			—			—			—			5,477
Repayment of long-term debt	(1,138		)	(1		)	—			—			(1,139		)
Dividends paid to affiliate	—			—			(15		)	15			—
Contributed member equity	3,323			—			—			—			3,323
Change in note payable with affiliate	—			23			(4		)	(19		)	—
Debt issuance costs	(154		)	—			—			—			(154		)
Net cash provided by (used in) financing activities	7,508			22			(19		)	(4		)	7,507
Change in cash and cash equivalents	—			(26		)	2			87			63
Cash and cash equivalents
Beginning of period	—			75			12			(87		)	—
End of period	$	—		$	49		$	14		$	—		$	63

84

EP ENERGY LLC

CONSOLIDATING STATEMENT OF CASH FLOWS

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

(In millions)

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

85

EP ENERGY LLC

CONSOLIDATING STATEMENT OF CASH FLOWS

FOR THE YEAR ENDED DECEMBER 31, 2011

(In millions)

	Predecessor
	GuarantorSubsidiaries			Non- GuarantorSubsidiaries			Eliminations			Consolidated
Cash flows from operating activities
Net income (loss)	$	262		$	(123	)	$	123		$	262
Adjustments to reconcile net income (loss) to net cash provided by operating activities
Depreciation, depletion and amortization	581			31			—			612
Deferred income tax expense	303			1			—			304
Earnings from unconsolidated affiliates, net of cash distributions	53			—			—			53
Earnings from consolidated affiliates	123			—			(123		)	—
Impairment and ceiling test charges	30			128			—			158
Amortization of debt issuance costs	3			—			—			3
Other non-cash income items	1			—			—			1
Asset and liability changes
Accounts receivable	(18		)	(2		)	—			(20		)
Accounts payable	(61		)	(6		)	—			(67		)
Affiliate income taxes	83			—			—			83
Derivative instruments	47			—			—			47
Accrued interest	(1		)	—			—			(1		)
Other asset changes	7			5			—			12
Other liability changes	(14		)	(7		)	—			(21		)
Net cash provided by operating activities	1,399			27			—			1,426
Cash flows from investing activities
Capital expenditures	(1,555		)	(36		)	—			(1,591		)
Net proceeds from the sale of assets	612			—			—			612
Cash paid for acquisitions, net of cash acquired	(21		)	(1		)	—			(22		)
Investment in subsidiary	(6		)	—			6			—
Change in note receivable with affiliates	(252		)	—			16			(236		)
Net cash used in investing activities	(1,222		)	(37		)	22			(1,237		)
Cash flows from financing activities
Proceeds from long-term debt	2,030			—			—			2,030
Repayment of long-term debt	(1,480		)	—			—			(1,480		)
Contribution from parent	—			6			(6		)	—
Change in note payable with affiliate	(781		)	16			(16		)	(781		)
Debt issuance costs	(7		)	—			—			(7		)
Net cash (used in) provided by financing activities	(238		)	22			(22		)	(238		)
Change in cash and cash equivalents	(61		)	12			—			(49		)
Cash and cash equivalents
Beginning of period	67			7			—			74
End of period	$	6		$	19		$	—		$	25

86

Supplemental Selected Quarterly Financial Information (Unaudited)

Financial information by quarter is summarized below (in millions).

	Successor
2013	March 31		June 30	September 30		December 31
Operating revenues
Physical sales	363		408	471		450
Financial derivatives	(131	)	166	(142	)	55
Operating (loss) income	(49	)	272	(2	)	160
Income taxes	—		—	—		—
(Loss) income from continuing operations	(132	)	197	(110	)	84
Net (loss) income	(106	)	209	348		98

	Predecessor		Successor
	Quarters Ended
		June 30
2012	March 31	April 1 to May 24	April 1 to June 30		September 30		December 31
Operating revenues
Physical sales	375	192	108		326		355
Financial derivatives	76	289	57		(181	)	62
Operating income (loss)	56	282	(104	)	(105	)	143
Income taxes	38	96	—		—		—
Income (loss) from continuing operations	11	176	(158	)	(205	)	64
Net income (loss)	15	163	(150	)	(196	)	91

Below are additional significant items affecting comparability of amounts reported in the respective periods of 2013 and 2012:

June 30, 2012. For the successor period from April 1 to June 30 we recorded $173 million of transaction costs related to the Acquisition.

March 31, 2012. We recorded a $62 million non-cash charge related to the unevaluated costs in Egypt based on a decision to exit activities in that area.

87

Supplemental Oil and Natural Gas Operations (Unaudited)

We are engaged in the exploration for, and the acquisition, development and production of oil, natural gas and NGLs, in the United States (U.S.).  We also have operations in Brazil that are currently under contract to be sold.

All periods included for capitalized costs, total costs incurred and results in operations present our Brazil operations as discontinued operations. The successor periods (periods after May 25, 2012) also present domestic natural gas assets sold, including the CBM, South Texas and the majority of our Arklatex assets as discontinued operations.  Predecessor periods do not present these domestic sales as discontinued operations due to the application of the full cost method of accounting prior to the Acquisition.  In addition, we sold our approximate 49 percent equity interest in Four Star in September 2013.

Capitalized Costs. Capitalized costs relating to oil and natural gas producing activities and related accumulated depreciation, depletion and amortization were as follows at December 31 (in millions):

	U.S.
2013 Consolidated:
Oil and natural gas properties	$	8,370
Less accumulated depreciation, depletion and amortization	840
Net capitalized costs	$	7,530
2012 Consolidated:
Oil and natural gas properties	$	6,513
Less accumulated depreciation, depletion and amortization	203
Net capitalized costs	$	6,310
2012 Unconsolidated Affiliate — Four Star(1):
Oil and natural gas properties	$	627
Less accumulated depreciation, depletion and amortization	510
Net capitalized costs	$	117

(1)       Amounts represent our approximate 49 percent equity interest in the underlying oil and gas assets of Four Star. We sold our interest in Four Star in September 2013.

88

Total Costs Incurred. Costs incurred in oil and natural gas producing activities, whether capitalized or expensed, were as follows for the successor periods for the year ended December 31, 2013 and the period from March 23, 2012 (inception) to December 31, 2012 and the predecessor periods from January 1, 2012 to May 24, 2012 and the year ended December 31, 2011 (in millions):

	U.S.		Egypt(1)		Worldwide
Successor
2013 Consolidated:
Property acquisition costs
Proved properties	$	2	$	—	$	2
Unproved properties	20		—		20
Exploration costs (capitalized and expensed)	95		—		95
Development costs	1,783		—		1,783
Costs expended	1,900		—		1,900
Asset retirement obligation costs	7		—		7
Total costs incurred	$	1,907	$	—	$	1,907
Consolidated from March 23, 2012 (inception) to December 31, 2012:
Property acquisition costs
Proved properties	$	—	$	—	$	—
Unproved properties	19		—		19
Exploration costs (capitalized and expensed)	107		—		107
Development costs	792		—		792
Costs expended	918		—		918
Asset retirement obligation costs	10		—		10
Total costs incurred	$	928	$	—	$	928
Unconsolidated Affiliate from March 23, 2012 (inception) to December 31, 2012:
Development costs expended	$	2	$	—	$	2
Predecessor
Consolidated from January 1, 2012 to May 24, 2012:
Property acquisition costs
Proved properties	$	—	$	—	$	—
Unproved properties	31		—		31
Exploration costs	79		2		81
Development costs	503		—		503
Costs expended	613		2		615
Asset retirement obligation costs	21		—		21
Total costs incurred	$	634	$	2	$	636
Unconsolidated Affiliate from January 1, 2012 to May 24, 2012:
Development costs expended	$	3	$	—	$	3
2011 Consolidated:
Property acquisition costs
Proved properties	$	—	$	—	$	—
Unproved properties	45		—		45
Exploration costs	873		8		881
Development costs	685		—		685
Costs expended	1,603		8		1,611
Asset retirement obligation costs	25		—		25
Total costs incurred	$	1,628	$	8	$	1,636
2011 Unconsolidated Affiliate:
Development costs expended	$	12	$	—	$	12

(1)       In June of 2012 we sold our Egyptian oil and gas properties.

(2)       Amounts represent our approximate 49 percent equity interest in the underlying costs incurred by Four Star.  We sold our interest in Four Star in September 2013.

89

We capitalize salaries and benefits that we determine are directly attributable to our oil and natural gas activities. The table above includes capitalized labor costs of $37 million and $25 million for the year ended December 31, 2013 and for the period from March 23, 2012 to December 31, 2012, and capitalized interest of $19 million and $12 million for the same periods.

Pursuant to the full cost method of accounting, the predecessor capitalized certain general and administrative expenses directly related to property acquisition, exploration and development activities and interest costs incurred and attributable to unproved oil and natural gas properties and major development projects of oil and natural gas properties. The table above includes capitalized internal general and administrative costs incurred in connection with the acquisition, development and exploration of oil and natural gas reserves of $31 million for the period from January 1, 2012 to May 24, 2012 and $81 million for the year ended December 31, 2011. The predecessor also capitalized interest of $4 million and $13 million for the period from January 1, 2012 to May 24, 2012 and the year ended December 31, 2011.

Oil and Natural Gas Reserves. Net quantities of proved developed and undeveloped reserves of natural gas, oil and condensate and NGLs and changes in these reserves at December 31, 2013 presented in the tables below are based on our internal reserve report. Net proved reserves exclude royalties and interests owned by others and reflect contractual arrangements and royalty obligations in effect at the time of the estimate. Our 2013 consolidated proved reserves were consistent with estimates of proved reserves filed with other federal agencies in 2013 except for differences of less than five percent resulting from actual production, acquisitions, property sales, necessary reserve revisions and additions to reflect actual experience.

Ryder Scott Company, L.P. (Ryder Scott), conducted an audit of the estimates of the proved reserves that we prepared as of December 31, 2013.  In connection with its audit, Ryder Scott reviewed 94% (by volume) of our total proved reserves (or 96% not including proved reserves associated with our Brazil assets classified as discontinued operations) on a barrel of oil equivalent basis, representing 96% of the total discounted future net cash flows of these proved reserves. For the audited properties, 98% of our total proved undeveloped (PUD) reserves were evaluated.  As of December 31, 2013, we did not have PUD reserves associated with our Brazil assets.  Ryder Scott concluded the overall procedures and methodologies that we utilized in preparing our estimates of proved reserves as of December 31, 2013 complied with current SEC regulations and the overall proved reserves for the reviewed properties as estimated by us are, in aggregate, reasonable within the established audit tolerance guidelines of 10% as set forth in the Society of Petroleum Engineers (SPE) auditing standards.  Ryder Scott’s report is included as an exhibit to this Annual Report on Form 10-K.

90

	Year Ended December 31, 2013
	U.S.								Brazil						Total
	Natural Gas(in Bcf)		Oil and Condensate (in MBbls)		NGLs(in MBbls)		Equivalent Volumes(in MMBoe)		Natural Gas(in Bcf)		Oil and Condensate (in MBbls)		Equivalent Volumes(in MMBoe)		Equivalent Volumes(in MMBoe)
Consolidated
Proved developed and undeveloped reserves
Beginning of year	1,727		256,242		34,331		578.5		68		2,152		13.4		591.9
Revisions due to prices	84		599		235		14.7		—		5		—		14.7
Revisions other than prices	129		(36,322	)	20,458		5.6		—		(17	)	—		5.6
Extensions and discoveries(1)	231		88,174		28,583		155.3		—		—		—		155.3
Sales of reserves in place	(965	)	(1,642	)	(5,108	)	(167.6	)	—		—		—		(167.6	)
Production	(135	)	(13,627	)	(2,826	)	(39.0	)	(9	)	(305	)	(1.8	)	(40.8	)
End of year	1,071		293,424		75,673		547.5		59		1,835		11.6		559.1
Proved developed reserves:
Beginning of year	1,189		55,924		9,080		263.2		68		2,152		13.3		276.5
End of year	484		84,034		17,715		182.4		59		1,835		11.6		194.0
Proved undeveloped reserves:
Beginning of year	538		200,318		25,251		315.2		—		—		—		315.2
End of year	586		209,391		57,958		365.1		—		—		—		365.1
Unconsolidated Affiliate — Four Star
Proved developed and undeveloped reserves
Beginning of year	150		2,148		5,967		33.1		—		—		—		33.1
Revisions due to prices	5		66		191		1.1		—		—		—		1.1
Revisions other than prices	11		128		348		2.3		—		—		—		2.3
Sales of reserves in place	(156	)	(2,145	)	(6,179	)	(34.3	)	—		—		—		(34.3	)
Production	(10	)	(197	)	(327	)	(2.2	)	—		—		—		(2.2	)
End of year	—		—		—		—		—		—		—		—
Proved developed reserves:
Beginning of year	140		2,111		5,289		30.9		—		—		—		30.9
End of year	—		—		—		—		—		—		—		—
Proved undeveloped reserves:
Beginning of year	10		37		678		2.4		—		—		—		2.4
End of year	—		—		—		—		—		—		—		—
Total Combined
Proved developed reserves:
Beginning of year	1,329		58,035		14,369		294.1		68		2,152		13.3		307.4
End of year	484		84,034		17,715		182.4		59		1,835		11.6		194.0
Proved undeveloped reserves:
Beginning of year	548		200,355		25,929		317.6		—		—		—		317.6
End of year	586		209,391		57,958		365.1		—		—		—		365.1

(1)Of the 155 MMBoe of combined extensions and discoveries, including assets sold, 5 MMBoe are in the Altamont area, 91 MMBoe are in the Eagle Ford Shale and 51 MMBoe are in the Wolfcamp Shale.  There were no extensions or discoveries in Brazil.  Of the 155 MMBoe of extensions and discoveries, 117 MMBoe were liquids representing 75% of EP Energy’s total extensions and discoveries.

91

	Year Ended December 31, 2012
	U.S.								Brazil						Total
	Natural Gas (in Bcf)		Oil and Condensate (in MBbls)		NGLs (in MBbls)		Equivalent Volumes (in MMBoe)		Natural Gas (in Bcf)		Oil and Condensate (in MBbls)		Equivalent Volumes (in MMBoe)		Equivalent Volumes (in MMBoe)
Consolidated
Proved developed and undeveloped reserves
Beginning of year	2,566		177,801		14,245		619.7		81		2,269		15.8		635.5
Revisions due to prices	(718	)	(604	)	(371	)	(120.6	)	—		1		—		(120.6	)
Revisions other than prices	55		(18,451	)	10,267		1.1		(3	)	288		(0.3	)	0.8
Extensions and discoveries(1)	119		109,125		13,450		142.4		—		—		—		142.4
Purchases of reserves in place	—		3		2		—		—		—		—		—
Sales of reserves in place	(72	)	(2,501	)	(1,358	)	(15.9	)	—		—		—		(15.9	)
Production	(223	)	(9,131	)	(1,904	)	(48.2	)	(10	)	(406	)	(2.1	)	(50.3	)
End of year	1,727		256,242		34,331		578.5		68		2,152		13.4		591.9
Proved developed reserves:
Beginning of year	1,488		46,797		5,168		300.0		81		2,269		15.8		315.8
End of year	1,189		55,924		9,080		263.2		68		2,152		13.3		276.5
Proved undeveloped reserves:
Beginning of year	1,078		131,004		9,077		319.7		—		—		—		319.7
End of year	538		200,318		25,251		315.2		—		—		—		315.2
Unconsolidated Affiliate — Four Star
Proved developed and undeveloped reserves
Beginning of year	135		1,569		4,908		29.0		—		—		—		29.0
Revisions due to prices	(13	)	(37	)	(310	)	(2.5	)	—		—		—		(2.5	)
Revisions other than prices	19		803		1,710		5.8		—		—		—		5.8
Extensions and discoveries(1)	25		95		137		4.3		—		—		—		4.3
Production	(16	)	(282	)	(478	)	(3.5	)	—		—		—		(3.5	)
End of year	150		2,148		5,967		33.1		—		—		—		33.1
Proved developed reserves:
Beginning of year	116		1,519		4,066		24.9		—		—		—		24.9
End of year	140		2,111		5,289		30.9		—		—		—		30.9
Proved undeveloped reserves:
Beginning of year	19		49		842		4.0		—		—		—		4.0
End of year	10		37		678		2.4		—		—		—		2.4
Total Combined
Proved developed reserves:
Beginning of year	1,604		48,316		9,234		324.9		81		2,269		15.8		340.7
End of year	1,329		58,035		14,369		294.1		68		2,152		13.3		307.4
Proved undeveloped reserves:
Beginning of year	1,097		131,053		9,919		323.7		—		—		—		323.7
End of year	548		200,355		25,929		317.6		—		—		—		317.6

(1)Of the 146.7 MMBoe of combined extensions and discoveries, 6.2 MMBoe are in the Altamont area, 110.7 MMBoe are in the Eagle Ford Shale and 23.5 MMBoe are in the Wolfcamp Shale.  There were no extensions or discoveries in Brazil.  Of the 146.7 MMBoe of extensions and discoveries, 122.8 MMBoe were liquids representing 84% of EP Energy’s total extensions and discoveries.

92

	Year Ended December 31, 2011
	U.S.								Brazil						Total
	Natural Gas (in Bcf)		Oil and Condensate (in MBbls)		NGLs(in MBbls)		Equivalent Volumes(in MMBoe)		Natural Gas (in Bcf)		Oil and Condensate (in MBbls)		Equivalent Volumes(in MMBoe)		Equivalent Volumes(in MMBoe)
Consolidated
Proved developed and undeveloped reserves
Beginning of year	2,396		103,240		9,051		511.5		85		2,654		16.8		528.3
Revisions due to prices	(9	)	713		—		(0.8	)	—		3		—		(0.8	)
Revisions other than prices	44		(1,630	)	(1,124	)	4.6		6		(34	)	1.1		5.7
Extensions and discoveries(1)	519		90,128		7,525		184.1		—		—		—		184.1
Purchases of reserves in place	—		13		—		—		—		—		—		—
Sales of reserves in place	(153	)	(8,983	)	(139	)	(34.5	)	—		—		—		(34.5	)
Production	(231	)	(5,680	)	(1,068	)	(45.2	)	(10	)	(354	)	(2.1	)	(47.3	)
End of year	2,566		177,801		14,245		619.7		81		2,269		15.8		635.5
Proved developed reserves:
Beginning of year	1,559		38,278		6,096		304.2		75		2,403		14.9		319.1
End of year	1,488		46,797		5,168		300.0		81		2,269		15.8		315.8
Proved undeveloped reserves:
Beginning of year	837		64,962		2,955		207.3		10		251		1.9		209.2
End of year	1,078		131,004		9,077		319.7		—		—		—		319.7
Unconsolidated Affiliate — Four Star
Proved developed and undeveloped reserves
Beginning of year	155		1,623		4,458		31.9		—		—		—		31.9
Revisions due to prices	(5	)	31		(28	)	(0.9	)	—		—		—		(0.9	)
Revisions other than prices	2		221		1,034		1.6		—		—		—		1.6
Production	(17	)	(306	)	(556	)	(3.6	)	—		—		—		(3.6	)
End of year	135		1,569		4,908		29.0		—		—		—		29.0
Proved developed reserves:
Beginning of year	129		1,574		3,483		26.6		—		—		—		26.6
End of year	116		1,519		4,066		24.9		—		—		—		24.9
Proved undeveloped reserves:
Beginning of year	26		49		975		5.4		—		—		—		5.4
End of year	19		49		842		4.0		—		—		—		4.0
Total Combined
Proved developed reserves:
Beginning of year	1,688		39,852		9,579		330.8		75		2,403		14.9		345.7
End of year	1,604		48,316		9,234		324.9		81		2,269		15.8		340.7
Proved undeveloped reserves:
Beginning of year	863		65,011		3,930		212.7		10		251		1.9		214.6
End of year	1,097		131,053		9,919		323.7		—		—		—		323.7

(1)Of the 184.1 MMBoe of extensions and discoveries, 64.8 MMBoe are in the Haynesville Shale area, 10.8 MMBoe are in the Altamont area, 79.8 MMBoe are in the Eagle Ford Shale and 18.8 MMBoe are in the Wolfcamp Shale. There were no extensions or discoveries in Brazil.

93

In accordance with SEC Regulation S-X, Rule 4-10 as amended, we use the 12-month average price calculated as the unweighted arithmetic average of the spot price on the first day of each month preceding the 12-month period prior to the end of the reporting period. The first day 12-month average U.S. price used to estimate our proved reserves at December 31, 2013 was $96.94 per barrel of oil (WTI) and $3.67 per MMBtu for natural gas (Henry Hub). The prices used for our International assets were contractually defined. The aggregate International price used to estimate our proved reserves at December 31, 2013 was $108.02 per barrel of oil and $6.31 per MMBtu for natural gas.

All estimates of proved reserves are determined according to the rules prescribed by the SEC in existence at the time estimates were made. These rules require that the standard of “reasonable certainty” be applied to proved reserve estimates, which is defined as having a high degree of confidence that the quantities will be recovered. A high degree of confidence exists if the quantity is much more likely to be achieved than not, and, as more technical and economic data becomes available, a positive or upward revision or no revision is much more likely than a negative or downward revision. Estimates are subject to revision based upon a number of factors, including many factors beyond our control such as reservoir performance, prices, economic conditions and government restrictions. In addition, as a result of drilling, testing and production subsequent to the date of an estimate may justify revision of that estimate.

Reserve estimates are often different from the quantities of oil and natural gas that are ultimately recovered. Estimating quantities of proved oil and natural gas reserves is a complex process that involves significant interpretations and assumptions and cannot be measured in an exact manner. It requires interpretations and judgment of available technical data, including the evaluation of available geological, geophysical, and engineering data. The accuracy of any reserve estimate is highly dependent on the quality of available data, the accuracy of the assumptions on which they are based upon economic factors, such as oil and natural gas prices, production costs, severance and excise taxes, capital expenditures, workover and remedial costs, and the assumed effects of governmental regulation. In addition, due to the lack of substantial, if any, production data, there are greater uncertainties in estimating proved undeveloped reserves, proved developed non-producing reserves and proved developed reserves that are early in their production life. As a result, our reserve estimates are inherently imprecise.

The meaningfulness of reserve estimates is highly dependent on the accuracy of the assumptions on which they were based. In general, the volume of production from oil and natural gas properties we own declines as reserves are depleted. Except to the extent we conduct successful exploration and development activities or acquire additional properties containing proved reserves, or both, our proved reserves will decline as reserves are produced. Subsequent to December 31, 2013, there have been no major discoveries, favorable or otherwise, that may be considered to have caused a significant change in our estimated proved reserves at December 31, 2013.

94

Results of Operations. Results of operations for oil and natural gas producing activities for the successor periods for the year ended December 31, 2013 and from March 23, 2012 (inception) to December 31, 2012 and the predecessor periods from January 1, 2012 to May 24, 2012 and year ended December 31, 2011 (in millions):

	U.S.			Egypt			Worldwide
Successor
2013 Consolidated:
Net Revenues(1) — Sales to external customers	$	1,692		$	—		$	1,692
Costs of products and services	(159		)	—			(159		)
Production costs(2)	(254		)	—			(254		)
Depreciation, depletion and amortization(3)	(605		)	—			(605		)
Exploration expense	(45		)	—			(45		)
Results of operations from producing activities	$	629		$	—		$	629
2013 Unconsolidated Affiliate — Four Star (4):
Net Revenues — Sales to external customers	$	69		$	—		$	69
Costs of products and services	(6		)	—			(6		)
Production costs(2)	(19		)	—			(19		)
Depreciation, depletion and amortization(5)	(18		)	—			(18		)
	26			—			26
Income tax expense	(8		)	—			(8		)
Results of operations from producing activities	$	18		$	—		$	18
Consolidated from March 23, 2012 (inception) to December 31, 2012:
Net Revenues(1) — Sales to external customers	$	789		$	—		$	789
Costs of products and services	(85		)	—			(85		)
Production costs(2)	(111		)	—			(111		)
Depreciation, depletion and amortization(3)	(202		)	—			(202		)
Exploration expense	(43		)	—			(43		)
Results of operations from producing activities	$	348		$	—		$	348
Unconsolidated Affiliate — Four Star from March 23, 2012 (inception) to December 31, 2012(4):
Net Revenues — Sales to external customers	$	52		$	—		$	52
Costs of products and services	(3		)	—			(3		)
Production costs(2)	(24		)	—			(24		)
Depreciation, depletion and amortization(5)	(16		)	—			(16		)
	9			—			9
Income tax expense	(3		)	—			(3		)
Results of operations from producing activities	$	6		$	—		$	6
Predecessor
Consolidated from January 1, 2012 to May 24, 2012:
Net Revenues(1)
Sales to external customers	$	424		$	—		$	424
Affiliated sales	143			—			143
Total	567			—			567
Costs of products and services	(49		)	—			(49		)
Production costs(2)	(115		)	—			(115		)
Impairments and ceiling test charges	—			(60		)	(60		)
Depreciation, depletion and amortization(3)	(301		)	—			(301		)
	102			(60		)	42
Income tax expense	(37		)	—			(37		)
Results of operations from producing activities	$	65		$	(60	)	$	5
Unconsolidated Affiliate — Four Star from January 1, 2012 to May 24, 2012(4):
Net Revenues — Sales to external customers	$	35		$	—		$	35
Costs of products and services	(1		)	—			(1		)
Production costs(2)	(15		)	—			(15		)
Depreciation, depletion and amortization(5)	(11		)	—			(11		)
	8			—			8
Income tax expense	(3		)	—			(3		)
Results of operations from producing activities	$	5		$	—		$	5
2011 Consolidated:
Net Revenues(1)
Sales to external customers	$	837		$	—		$	837
Affiliated sales	634			—			634
Total	1,471			—			1,471
Costs of products and services	(91		)	—			(91		)
Production costs(2)	(245		)	—			(245		)
Depreciation, depletion and amortization(3)	(563		)	—			(563		)
	572			—			572
Income tax expense	(207		)	—			(207		)
Results of operations from producing activities	$	365		$	—		$	365
2011 Unconsolidated Affiliate — Four Star(4):
Net Revenues — Sales to external customers	$	123		$	—		$	123
Costs of products and services	(4		)	—			(4		)
Production costs(2)	(49		)	—			(49		)
Depreciation, depletion and amortization(5)	(27		)	—			(27		)
	43			—			43
Income tax expense	(15		)	—			(15		)
Results of operations from producing activities	$	28		$	—		$	28

(1)Excludes the effects of oil and natural gas derivative contracts.

(2)Production costs include lease operating costs and production related taxes, including ad valorem and severance taxes.

(3)Includes accretion expense on asset retirement obligations of $4 million and $9 million for the year ended December 31, 2013 and the period from March 23, 2012 to December 31, 2012, $5 million and $13 million for the predecessor periods from January 1, 2012 to May 24, 2012 and the year ended December 31, 2011, respectively.

(4)Results for 2013 are reported as of September 10, 2013 (the date the investment was sold). Results do not include amortization of $8 million for the year ended December 31, 2013, $7 million for the period from March 23, 2012 to December 31, 2012 and $12 million and $34 million for the predecessor periods from January 1, 2012 to May 24, 2012 and year ended December 31, 2011 related to cost in excess of our equity interest in the underlying net assets of Four Star.  In addition, in 2013 we recorded an impairment of $20 million, not included in the table above.

(5)Includes accretion expense on asset retirement obligations of $1 million for the period from March 23, 2012 to December 31, 2012 and $1 million and $2 million for the predecessor periods from January 1, 2012 to May 24, 2012 and the year ended December 31, 2011, respectively.

95

Standardized Measure of Discounted Future Net Cash Flows. The standardized measure of discounted future net cash flows relating to our consolidated proved oil and natural gas reserves at December 31 is as follows (in millions):

	U.S.			Brazil			Worldwide
2013 Consolidated:
Future cash inflows(1)	$	33,719		$	615		$	34,334
Future production costs	(9,187		)	(365		)	(9,552		)
Future development costs	(6,789		)	(71		)	(6,860		)
Future income tax expenses(2)	—			(18		)	(18		)
Future net cash flows	17,743			161			17,904
10% annual discount for estimated timing of cash flows	(8,812		)	(32		)	(8,844		)
Standardized measure of discounted future net cash flows	$	8,931		$	129		$	9,060
2012 Consolidated:
Future cash inflows(1)	$	28,488		$	701		$	29,189
Future production costs	(7,487		)	(415		)	(7,902		)
Future development costs	(6,189		)	(71		)	(6,260		)
Future income tax expenses(2)	—			(14		)	(14		)
Future net cash flows	14,812			201			15,013
10% annual discount for estimated timing of cash flows	(7,913		)	(39		)	(7,952		)
Standardized measure of discounted future net cash flows	$	6,899		$	162		$	7,061
2012 Unconsolidated Affiliate — Four Star(3):
Future cash inflows(1)	$	828		$	—		$	828
Future production costs	(392		)	—			(392		)
Future development costs	(54		)	—			(54		)
Future income tax expenses	(139		)	—			(139		)
Future net cash flows	243			—			243
10% annual discount for estimated timing of cash flows	(107		)	—			(107		)
Standardized measure of discounted future net cash flows	$	136		$	—		$	136
2011 Consolidated:
Future cash inflows(1)	$	26,079		$	768		$	26,847
Future production costs	(5,840		)	(415		)	(6,255		)
Future development costs	(6,343		)	(34		)	(6,377		)
Future income tax expenses	(4,086		)	(23		)	(4,109		)
Future net cash flows	9,810			296			10,106
10% annual discount for estimated timing of cash flows	(4,793		)	(97		)	(4,890		)
Standardized measure of discounted future net cash flows	$	5,017		$	199		$	5,216
2011 Unconsolidated Affiliate — Four Star(3):
Future cash inflows(1)	$	938		$	—		$	938
Future production costs	(348		)	—			(348		)
Future development costs	(66		)	—			(66		)
Future income tax expenses	(201		)	—			(201		)
Future net cash flows	323			—			323
10% annual discount for estimated timing of cash flows	(129		)	—			(129		)
Standardized measure of discounted future net cash flows	$	194		$	—		$	194

(1)The company had no commodity-based derivative contracts designated as accounting hedges at December 31, 2013, 2012 and 2011. Amounts also exclude the impact on future net cash flows of derivatives not designated as accounting hedges.

(2)For the years ended December 31, 2013 and 2012, there were no U.S. future income taxes because the company is not subject to federal income taxes.

(3)Amounts represent our approximate 49 percent equity interest in Four Star which was sold in September 2013.

96

Changes in Standardized Measure of Discounted Future Net Cash Flows. The following are the principal sources of change in our consolidated worldwide standardized measure of discounted future net cash flows (in millions):

	Years Ended December 31,(1)
	2013			2012			2011
Consolidated:
Sales and transfers of oil and natural gas produced net of production costs	$	(1,493	)	$	(1,433	)	$	(1,200	)
Net changes in prices and production costs	(417		)	(871		)	1,057
Extensions, discoveries and improved recovery, less related costs	2,801			2,539			2,140
Changes in estimated future development costs	(10		)	978			(415		)
Previously estimated development costs incurred during the period	679			587			601
Revision of previous quantity estimates	473			(1,863		)	49
Accretion of discount	796			731			430
Net change in income taxes	(3		)	1,683			(599		)
Sales of reserves in place	(909		)	(296		)	(587		)
Change in production rates, timing and other	82			(210		)	(261		)
Net change	$	1,999		$	1,845		$	1,215
Unconsolidated Affiliate — Four Star:
Sales and transfers of oil and natural gas produced net of production costs	$	(41	)	$	(48	)	$	(74	)
Net changes in prices and production costs	6			(112		)	62
Extensions, discoveries and improved recovery, less related costs	—			25			—
Changes in estimated future development costs	25			5			(14		)
Revision of previous quantity estimates	10			19			6
Accretion of discount	18			22			22
Net change in income taxes	68			39			(9		)
Sales of reserves in place	(260		)	—			—
Change in production rates, timing and other	38			(8		)	19
Net change	(136		)	$	(58	)	$	12
Representative NYMEX prices:(2)
Oil (Bbl)	$	96.94		$	94.61		$	96.19
Natural gas (MMBtu)	$	3.67		$	2.76		$	4.12
Aggregate International prices:(2)
Oil (Bbl)	$	108.02		$	111.21		$	109.29
Natural gas (MMBtu)	$	6.31		$	6.55		$	5.31

(1)This disclosure reflects changes in the standardized measure calculation excluding the effects of hedging activities.

(2)First day 12-month historical average U.S. price and an aggregate international price before price differentials and deducts. Price differentials and deducts were applied when the estimated future cash flows from estimated production from proved reserves were calculated.

97

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

ITEM 9A. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

As of December 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 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 December 31, 2013.  See Item 8, “Financial Statements and Supplementary Data” under Management’s Annual Report on Internal Control over Financial Reporting.

Changes in Internal Control over Financial Reporting

There were no changes in our internal control over financial reporting during the fourth quarter of 2013 that have materially affected or are reasonably likely to materially affect our internal control over financial reporting.

ITEM 9B. OTHER INFORMATION

None.

98

PART III

Item 10, “Directors, Executive Officers and Corporate Governance;” Item 11, “Executive Compensation;” Item 12, “Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters;” and Item 13, “Certain Relationships and Related Transactions, and Director Independence” have been omitted from this report pursuant to the reduced disclosure format permitted by General Instruction I to Form 10-K.

ITEM 14.  PRINCIPAL ACCOUNTANT FEES AND SERVICES

Ernst & Young LLP audited our financial statements for fiscal year 2013, including the audit of EP Energy LLC.  Included in the table below are the aggregate fees for professional services rendered to us by Ernst & Young LLP for the year ended December 31, 2013.

Principal Accountant Fees and Services

Aggregate fees for professional services rendered to us by Ernst & Young LLP for the years ended December 31 were (in thousands):

	2013		2012
Audit	$	2,931	$	2,982
Audit Related	180		2
Tax	202		160
Total	$	3,313	$	3,144

Audit Fees for the year ended December 31, 2013 were primarily for professional services rendered for the audit of consolidated financial statements of EP Energy LLC; the review of documents filed with the SEC; consents; the issuance of comfort letters; and certain financial accounting and reporting consultations.

Audit Related Fees for the year ended December 31, 2013 were primarily for professional services and other advisory services rendered not included in Audit fees above.

Tax Fees for the year ended December 31, 2013 were for professional services related to tax compliance, tax planning and advisory services.

The audit committee of the board of directors of our parent has adopted a pre-approval policy for audit and non-audit services and the fees set forth above are consistent with such pre-approvals.  The audit committee’s current practice is to consider for pre-approval annually all categories of audit and permitted non-audit services proposed to be provided by our independent auditors for a fiscal year.  Pre-approval of tax services requires the principal independent auditor provide the audit committee with written documentation of the scope and fee structure of the proposed tax services and discuss with the audit committee the potential effects, if any, of providing such services on the independent auditor’s independence.  The audit committee will also consider for pre-approval annually the maximum amount of fees and the manner in which the fees are determined for each type of pre-approved audit and non-audit services proposed to be provided by the independent auditors for the fiscal year.  The audit committee must separately pre-approve any service that is not included in the approved list of services or any proposed services exceeding the pre-approved cost levels.

99

PART IV

ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

(a) The following documents are filed as a part of this report:

1. Financial statements: Refer to Item 8. “Financial Statements and Supplementary Data” in this Annual Report on Form 10-K.

	Page
2. and (b). Exhibits	102

The Exhibit Index, which follows the signature page to this report and is hereby incorporated herein by reference, sets forth a list of those exhibits filed herewith, and includes and identifies management contracts or compensatory plans or arrangements required to be filed as exhibits to this Form 10-K by Item 601 (b)(10)(iii) of Regulation S-K.

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 agreements 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.

100

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, EP Energy LLC has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized on the 27th day of February 2014.

EP ENERGY LLC
By:	/s/ Brent J. Smolik
	Brent J. Smolik
	President and Chief Executive Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of EP Energy LLC and in the capacities and on the dates indicated:

Signature	Title	Date
/s/ Brent J. Smolik	President and Chief Executive Officer (Principal Executive Officer)	February 27, 2014
Brent J. Smolik
/s/ Dane E. Whitehead	Executive Vice President and Chief Financial Officer (Principal Financial Officer)	February 27, 2014
Dane E. Whitehead
/s/ Francis C. Olmsted III	Vice President and Controller (Principal Accounting Officer)	February 27, 2014
Francis C. Olmsted III
/s/ Ralph Alexander	Director, EP Energy Corporation	February 27, 2014
Ralph Alexander
/s/ Gregory A. Beard	Director, EP Energy Corporation	February 27, 2014
Gregory A. Beard
/s/ Wilson B. Handler	Director, EP Energy Corporation	February 27, 2014
Wilson B. Handler
/s/ John J. Hannan	Director, EP Energy Corporation	February 27, 2014
John J. Hannan
/s/ Michael S. Helfer	Director, EP Energy Corporation	February 27, 2014
Michael S. Helfer
/s/ Sam Oh	Director, EP Energy Corporation	February 27, 2014
Sam Oh
/s/ Ilrae Park	Director, EP Energy Corporation	February 27, 2014
Ilrae Park
/s/ Brent J. Smolik	Director, EP Energy Corporation	February 27, 2014
Brent J. Smolik
/s/ Robert M. Tichio	Director, EP Energy Corporation	February 27, 2014
Robert M. Tichio
/s/ Donald A. Wagner	Director, EP Energy Corporation	February 27, 2014
Donald A. Wagner
/s/ Rakesh Wilson	Director, EP Energy Corporation	February 27, 2014
Rakesh Wilson

101

SUPPLEMENTAL INFORMATION TO BE FURNISHED WITH REPORTS FILED PURSUANT TO SECTION

15(d) OF THE ACT BY REGISTRANTS WHICH HAVE NOT REGISTERED SECURITES PURSUANT TO

SECTION 12 OF THE ACT

The Company has not sent to any security holders an annual report covering the 2013 fiscal year or proxy statement, form of proxy or other proxy soliciting material with respect to any annual or other meeting of security holders.

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. Exhibits designated with a “+” constitute a management contract or compensatory plan or arrangement. Exhibits designated with a “†” indicate that a confidential treatment has been requested with respect to certain portions of the exhibit. Omitted portions have been filed separately with the SEC.

Exhibit No.	Exhibit Description
2.1	Purchase and Sale Agreement among EP Energy Corporation, EP Energy Holding Company and El Paso Brazil, L.L.C., as sellers, and EPE Acquisition, LLC, as purchaser, dated as of February 24, 2012 (Exhibit 2.1 to the Company’s Registration Statement on Form S-4, filed with the SEC on September 11, 2012).
2.2	Amendment No. 1 to Purchase and Sale Agreement, dated as of April 16, 2012, among EP Energy, L.L.C. (f/k/a EP Energy Corporation), EP Energy Holding Company, El Paso Brazil, L.L.C. and EPE Acquisition, LLC (Exhibit 2.2 to the Company’s Registration Statement on Form S-4, filed with the SEC on September 11, 2012).
2.3	Amendment No. 2 to Purchase and Sale Agreement, dated as of May 24, 2012, among EP Energy, L.L.C. (f/k/a EP Energy Corporation), EP Energy Holding Company, El Paso Brazil, L.L.C., EP Production International Cayman Company, EPE Acquisition, LLC and solely for purposes of Sections 2 and 5 thereunder, El Paso LLC (Exhibit 2.3 to the Company’s Registration Statement on Form S-4, filed with the SEC on September 11, 2012).
2.4	Purchase and Sale Agreement, dated as of June 9, 2013, by and among EP Energy E&P Company, L.P., EPE Nominee Corp. and Atlas Resource Partners, L.P. (Exhibit 2.1 to the Company’s Current Report on Form 8-K, filed with the SEC on June 13, 2013).
3.1	Certificate of Formation of EP Energy LLC (Exhibit 3.1 to our Registration Statement on Form S-4, filed with the SEC on September 11, 2012).
3.2	Limited Liability Company Agreement of EP Energy LLC (Exhibit 3.2 to our Registration Statement on Form S-4, filed with the SEC on September 11, 2012).
4.1	Indenture, dated as of April 24, 2012, between EP Energy LLC (f/k/a Everest Acquisition LLC) and Everest Acquisition Finance Inc., as Co-Issuers, and Wilmington Trust, National Association, as Trustee, in respect of 6.875% Senior Secured Notes due 2019 (Exhibit 4.1 to the Company’s Registration Statement on Form S-4, filed with the SEC on September 11, 2012).
4.2	Indenture, dated as of April 24, 2012, between EP Energy LLC (f/k/a Everest Acquisition LLC) and Everest Acquisition Finance Inc., as Co-Issuers, and Wilmington Trust, National Association, as Trustee, in respect of 9.375% Senior Notes due 2020 (Exhibit 4.2 to the Company’s Registration Statement on Form S-4, filed with the SEC on September 11, 2012).
4.3	Indenture, dated as of August 13, 2012, between EP Energy LLC and Everest Acquisition Finance Inc., as Co-Issuers, and Wilmington Trust, National Association, as Trustee, in respect of 7.750% Senior Notes due 2022 (Exhibit 4.3 to the Company’s Registration Statement on Form S-4, filed with the SEC on September 11, 2012).
4.4	Indenture, dated as of December 21, 2012, between EPE Holdings LLC and EP Energy Bondco Inc., as Co-Issuers, and Wilmington Trust, National Association, as Trustee, in respect of 8.125%/8.875% Senior PIK Toggle Notes due 2017 (Exhibit 4.4 to EP Energy Corporation’s Registration Statement on Form S-1, filed with the SEC on September 4, 2013).

102

Exhibit No.	Exhibit Description
4.5	Registration Rights Agreement, dated as of April 24, 2012, between EP Energy LLC (f/k/a Everest Acquisition LLC), Everest Acquisition Finance Inc. and Citigroup Global Markets Inc. and J.P. Morgan Securities LLC, as representatives of the several initial purchasers, in respect of 6.875% Senior Secured Notes due 2019 (Exhibit 4.4 to the Company’s Registration Statement on Form S-4, filed with the SEC on September 11, 2012).
4.6	Registration Rights Agreement, dated as of April 24, 2012, between EP Energy LLC (f/k/a Everest Acquisition LLC), Everest Acquisition Finance Inc. and Citigroup Global Markets Inc. and J.P. Morgan Securities LLC, as representatives of the several initial purchasers, in respect of 9.375% Senior Notes due 2020 (Exhibit 4.5 to the Company’s Registration Statement on Form S-4, filed with the SEC on September 11, 2012).
4.7	Registration Rights Agreement, dated as of August 13, 2012, between EP Energy LLC, Everest Acquisition Finance Inc. and Citigroup Global Markets Inc., as representative of the several initial purchasers, in respect of 7.750% Senior Notes due 2022 (Exhibit 4.6 to the Company’s Registration Statement on Form S-4, filed with the SEC on September 11, 2012).
4.8	Registration Rights Agreement, dated as of August 30, 2013, between EP Energy Corporation and the stockholders party thereto (Exhibit 4.8 to EP Energy Corporation’s Registration Statement on Form S-1, filed with the SEC on September 4, 2013).
10.1	Credit Agreement, dated as of May 24, 2012, by and among EPE Holdings, LLC, as Holdings, EP Energy LLC (f/k/a Everest Acquisition LLC), as the Borrower, the Lenders party thereto, JPMorgan Chase Bank, N.A., as Administrative Agent and Collateral Agent, and the other parties party thereto (Exhibit 10.1 to the Company’s Registration Statement on Form S-4, filed with the SEC on September 11, 2012).
10.2	Guarantee Agreement, dated as of May 24, 2012, by and among EPE Holdings LLC, the Domestic Subsidiaries of the Borrower signatory thereto and JPMorgan Chase Bank, N.A., as collateral agent for the Secured Parties referred to therein (Exhibit 10.2 to the Company’s Registration Statement on Form S-4, filed with the SEC on September 11, 2012).
10.3	Collateral Agreement, dated as of May 24, 2012, by and among EPE Holdings LLC, EP Energy LLC (f/k/a Everest Acquisition LLC), each Subsidiary of EP Energy LLC identified therein and JPMorgan Chase Bank, N.A., as Collateral Agent (Exhibit 10.3 to the Company’s Registration Statement on Form S-4, filed with the SEC on September 11, 2012).
10.4	Pledge Agreement, dated as of May 24, 2012, by and among EP Energy LLC (f/k/a Everest Acquisition LLC), each Subsidiary of EP Energy LLC identified therein and JPMorgan Chase Bank, N.A., as Collateral Agent (Exhibit 10.4 to the Company’s Registration Statement on Form S-4, filed with the SEC on September 11, 2012).
10.5	Pledge Agreement, dated as of May 24, 2012, by and among El Paso Brazil, L.L.C., as Pledgor, and JPMorgan Chase Bank, N.A., as Collateral Agent (Exhibit 10.5 to the Company’s Registration Statement on Form S-4, filed with the SEC on September 11, 2012).
10.6	Amendment, dated as of August 17, 2012, 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 (Exhibit 10.15 to the Company’s Registration Statement on Form S-4, filed with the SEC on September 11, 2012).
10.7	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 (Exhibit 10.1 to the Company’s Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2013, filed with the SEC on May 9, 2013).

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Exhibit No.	Exhibit Description
10.8	Consent and Agreement to Credit Agreement, dated as of June 7, 2013, among EPE Holdings LLC, EP Energy LLC, the lenders party thereto and JPMorgan Chase Bank, N.A., as administrative agent and collateral agent (Exhibit 10.3 to the Company’s Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2013, filed with the SEC on August 14, 2013).
10.9	Senior Lien Intercreditor Agreement, dated as of May 24, 2012, among JPMorgan Chase Bank, N.A., as RBL Facility Agent and Applicable First Lien Agent, Citibank, N.A., as Term Facility Agent, Senior Secured Notes Collateral Agent and Applicable Second Lien Agent, Wilmington Trust, National Association, as Trustee under the Senior Secured Notes Indenture, EP Energy LLC and the Subsidiaries of EP Energy LLC named therein (Exhibit 10.6 to the Company’s Registration Statement on Form S-4, filed with the SEC on September 11, 2012).
10.10	Term Loan Agreement, dated as of April 24, 2012, by and among EP Energy LLC (f/k/a Everest Acquisition LLC), as Borrower, the Lenders party thereto, Citibank, N.A., as Administrative Agent and Collateral Agent, and Citigroup Global Markets Inc. and J.P. Morgan Securities LLC, as Co-Lead Arrangers (Exhibit 10.7 to the Company’s Registration Statement on Form S-4, filed with the SEC on September 11, 2012).
10.11	Guarantee Agreement, dated as of April 24, 2012, by and between Everest Acquisition Finance Inc., as Guarantor, and Citibank, N.A., as collateral agent for the Secured Parties referred to therein (Exhibit 10.8 to the Company’s Registration Statement on Form S-4, filed with the SEC on September 11, 2012).
10.12	Collateral Agreement, dated as of May 24, 2012, by and among EP Energy LLC (f/k/a Everest Acquisition LLC), each Subsidiary of EP Energy LLC identified therein and Citibank, N.A., as Collateral Agent (Exhibit 10.9 to the Company’s Registration Statement on Form S-4, filed with the SEC on September 11, 2012).
10.13	Pledge Agreement, dated as of May 24, 2012, by and among EP Energy LLC (f/k/a Everest Acquisition LLC), each Subsidiary of EP Energy LLC identified therein and Citibank, N.A., as Collateral Agent (Exhibit 10.10 to the Company’s Registration Statement on Form S-4, filed with the SEC on September 11, 2012).
10.14	Pledge Agreement, dated as of May 24, 2012, by and among EP Energy Brazil, L.L.C. (f/k/a El Paso Brazil, L.L.C.), as Pledgor, and Citibank, N.A., as Collateral Agent (Exhibit 10.11 to the Company’s Registration Statement on Form S-4, filed with the SEC on September 11, 2012).
10.15	Amendment No. 1, dated as of August 21, 2012, to the Term Loan Agreement, dated as of April 24, 2012, among EP Energy LLC, the lenders party thereto and Citibank, N.A., as administrative agent and collateral agent (Exhibit 10.16 to the Company’s Registration Statement on Form S-4, filed with the SEC on September 11, 2012).
10.16	Joinder Agreement, dated as of August 21, 2012, among Citibank, N.A., as Additional Tranche B-1 Lender, EP Energy LLC and Citibank, N.A., as administrative agent (Exhibit 10.17 to the Company’s Registration Statement on Form S-4, filed with the SEC on September 11, 2012).
10.17	Incremental Facility Agreement, dated October 31, 2012, to the Term Loan Agreement, dated as of April 24, 2012 and amended by that certain Amendment No. 1 dated as of August 21, 2012, among EP Energy LLC, the lenders from time to time party thereto and Citibank, N.A., as administrative agent and collateral agent. (Exhibit 10.1 to the Company’s Current Report on Form 8-K, filed with the SEC on October 31, 2012).
10.18	Reaffirmation Agreement, dated as of October 31, 2012, among EP Energy LLC, each Subsidiary Party party thereto and Citibank, N.A., as administrative agent and collateral agent (Exhibit 10.2 to the Company’s Current Report on Form 8-K, filed with the SEC on October 31, 2012).
10.19	Amendment No. 2, dated as of May 2, 2013, to the Term Loan Agreement, dated as of April 24, 2012, among EP Energy LLC, the lenders party thereto and Citibank, N.A., as administrative agent and collateral agent (Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the SEC on May 28, 2013).

104

Exhibit No.	Exhibit Description
10.20	Joinder Agreement, dated as of May 2, 2013, among Citibank, N.A., as Additional Tranche B-1 Lender, EP Energy LLC and Citibank, N.A., as administrative agent (Exhibit 10.2 to the Company’s Current Report on Form 8-K filed with the SEC on May 28, 2013).
10.21	Pari Passu Intercreditor Agreement, dated as of May 24, 2012, among Citibank, N.A., as Second Lien Agent, Citibank, N.A., as Authorized Representative for the Term Loan Agreement, Wilmington Trust, National Association, as the Initial Other Authorized Representative and each additional Authorized Representative from time to time party hereto (Exhibit 10.12 to the Company’s Registration Statement on Form S-4, filed with the SEC on September 11, 2012).
10.22	Amended and Restated Transaction Fee Agreement, dated as of December 20, 2013, among EP Energy Corporation, EP Energy Global LLC, EPE Acquisition, LLC, Apollo Global Securities, LLC, Riverstone V Everest Holdings, L.P., Access Industries, Inc. and Korea National Oil Corporation (Exhibit 10.22 to Amendment No. 4 to EP Energy Corporation’s Registration Statement on Form S-1, filed with the SEC on January 6, 2014).
10.23	Amended and Restated Management Fee Agreement, dated as of December 20, 2013, among EP Energy Corporation, EP Energy Global LLC, EPE Acquisition, LLC, Apollo Management VII, L.P., Apollo Commodities Management, L.P., With Respect to Series I, Riverstone V Everest Holdings, L.P., Access Industries, Inc. and Korea National Oil Corporation (Exhibit 10.23 to Amendment No. 4 to EP Energy Corporation’s Registration Statement on Form S-1, filed with the SEC on January 6, 2014).
10.24+	Employment Agreement dated May 24, 2012 for Clayton A. Carrell (Exhibit 10.18 to the Company’s Registration Statement on Form S-4, filed with the SEC on September 11, 2012).
10.25+	Employment Agreement dated May 24, 2012 for John D. Jensen (Exhibit 10.19 to the Company’s Registration Statement on Form S-4, filed with the SEC on September 11, 2012).
10.26+	Employment Agreement dated May 24, 2012 for Brent J. Smolik (Exhibit 10.20 to the Company’s Registration Statement on Form S-4, filed with the SEC on September 11, 2012).
10.27+	Employment Agreement dated May 24, 2012 for Dane E. Whitehead (Exhibit 10.21 to the Company’s Registration Statement on Form S-4, filed with the SEC on September 11, 2012).
10.28+	Employment Agreement dated May 24, 2012 for Marguerite N. Woung-Chapman (Exhibit 10.22 to the Company’s Registration Statement on Form S-4, filed with the SEC on September 11, 2012).
10.29+	Senior Executive Survivor Benefit Plan adopted as of May 24, 2012 (Exhibit 10.23 to the Company’s Registration Statement on Form S-4, filed with the SEC on September 11, 2012).
10.30+	2012 Omnibus Incentive Plan (Exhibit 10.24 to the Company’s Registration Statement on Form S-4, filed with the SEC on September 11, 2012).
10.31+	Management Incentive Plan Agreement, dated as of August 30, 2013, between EP Energy Corporation and EPE Employee Holdings, LLC (Exhibit 10.31 to Amendment No. 2 to EP Energy Corporation’s Registration Statement on Form S-1, filed with the SEC on November 1, 2013).†
10.32+	Form of EPE Employee Holdings, LLC Management Incentive Unit Agreement (Exhibit 10.26 to the Company’s Registration Statement on Form S-4 filed with the SEC on September 11, 2012).
10.33+	Form of Notice to MIPs Holders regarding Corporate Reorganization (Exhibit 10.33 to EP Energy Corporation’s Registration Statement on Form S-1, filed with the SEC on September 4, 2013).
10.34+	Third Amended and Restated Limited Liability Company Agreement of EPE Employee Holdings, LLC dated as of August 30, 2013 (Exhibit 10.34 to Amendment No. 2 to EP Energy Corporation’s Registration Statement on Form S-1, filed with the SEC on November 1, 2013).†

105

Exhibit No.	Exhibit Description
10.35+	Third Amended and Restated Limited Liability Company Agreement of EPE Management Investors, LLC dated as of August 30, 2013 (Exhibit 10.35 to Amendment No. 2 to EP Energy Corporation’s Registration Statement on Form S-1, filed with the SEC on November 1, 2013).†
10.36+	Subscription Agreement, dated as of August 30, 2013, between EP Energy Corporation and EPE Management Investors, LLC (Exhibit 10.36 to EP Energy Corporation’s Registration Statement on Form S-1, filed with the SEC on September 4, 2013).
10.37+	Form of EP Energy Employee Holdings II, LLC Class B Incentive Pool Program Award Agreement (Exhibit 10.37 to Amendment No. 1 to EP Energy Corporation’s Registration Statement on Form S-1, filed with the SEC on October 11, 2013).
10.38+	EP Energy Corporation 2014 Omnibus Incentive Plan (Exhibit 10.1 to EP Energy Corporation’s Current Report on Form 8-K, filed with the SEC on January 23, 2014).
10.39+	Form of Notice Stock Option Grant and Stock Option Award Agreement under EP Energy Corporation 2014 Omnibus Incentive Plan (Exhibit 10.39 to EP Energy Corporation’s Annual Report on Form 10-K filed with the SEC on February 27, 2014).
10.40+	Form of Notice Restricted Stock Grant and Restricted Stock Award Agreement under EP Energy Corporation 2014 Omnibus Incentive Plan (Exhibit 10.40 to EP Energy Corporation’s Annual Report on Form 10-K filed with the SEC on February 27, 2014).
10.41	Stockholders Agreement, dated as of August 30, 2013, between EP Energy Corporation and the stockholders party thereto (Exhibit 10.39 to Amendment No. 1 to EP Energy Corporation’s Registration Statement on Form S-1, filed with the SEC on October 11, 2013).
10.42	Addendum Agreement, dated as of September 18, 2013, to the Stockholders Agreement, between EP Energy Corporation and EP Energy Employee Holdings II, LLC (Exhibit 10.40 to Amendment No. 1 to EP Energy Corporation’s Registration Statement on Form S-1, filed with the SEC on October 11, 2013).
10.43	Form of Director and Officer Indemnification Agreement between EP Energy Corporation and each of the officers and directors thereof (Exhibit 10.41 to Amendment No. 4 to EP Energy Corporation’s Registration Statement on Form S-1, filed with the SEC on January 6, 2014).
23.1*	Consent of Ryder Scott Company, L.P.
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.
99.1*	Ryder Scott Company, L.P. reserve audit report for EP Energy Corporation as of December 31, 2013.
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.

106