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UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K

(Mark One)

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

For the fiscal year ended December 31, 2014

OR

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

For the transition period from                  to                  .

Commission File Number 333-183815

EP Energy LLC

(Exact Name of Registrant as Specified in Its Charter)

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):

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

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EP ENERGY LLC

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*                 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.

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

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.

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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;

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

·                  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;

·                  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;

·                  competition; and

·                  the other factors described under Item 1A, “Risk Factors,” on pages 3 through 20 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 Reports 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.

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PART I

ITEM 1.                         BUSINESS

EP Energy LLC (EP Energy), a wholly-owned subsidiary of EP Energy Corporation, is a Delaware limited liability company formed on March 23, 2012.  On May 24, 2012, Apollo Global Management LLC (together with its subsidiaries, Apollo), Riverstone Holdings LLC (Riverstone), Access Industries (Access) and Korea National Oil Corporation (KNOC) (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 a merger agreement among El Paso Corporation (El Paso) and Kinder Morgan, Inc. (KMI).  Hereinafter, this acquisition 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 operate through a large and diverse base of producing assets located predominantly in four operating areas: the Eagle Ford Shale (South Texas), the Wolfcamp Shale (Permian Basin in West Texas), the Altamont field in the Uinta Basin (Northeastern Utah) and the Haynesville Shale (North Louisiana).  In our operating areas, we have identified approximately 5,670 drilling locations (including 979 drilling locations to which we have attributed proved undeveloped reserves as of December 31, 2014, of which approximately 92% are oil wells). At 2014 activity levels, this represents approximately 21 years of drilling inventory (more than 30 years of drilling inventory at 2015 activity levels). As of December 31, 2014, we had proved reserves of 622.2 MMBoe (52% oil and 67% liquids) and for the year ended December 31, 2014, we had average production of 97,734 Boe/d (56% oil and 68% liquids).

Each of our operating 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 477,000 net (647,000 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 production growth of 10% and 51%, respectively, from December 31, 2013 to December 31, 2014.

During 2014, we acquired producing properties and undeveloped acreage in the Southern Midland Basin, of which 37,000 net acres are adjacent to our existing Wolfcamp Shale position, for an aggregate cash purchase price of $152 million. The acquisition represents an approximate 25% expansion of our Wolfcamp acreage.  Additionally, we completed the sale of (i) non-core assets in our Arklatex area and South Louisiana Wilcox area (approximately 78,000 net acres, excluding Haynesville and Bossier rights) for approximately $150 million of cash proceeds, with the buyer also assuming a transportation commitment of approximately $20 million, (ii) our Brazilian operations and (iii) certain non-core acreage in Atascosa County in Eagle Ford for approximately $28 million of cash proceeds.

Prior to 2014, we divested of non-core domestic natural gas assets and an equity investment for a total consideration of approximately $1.5 billion. As a result of these asset sales, we became a higher-growth, 100% onshore, oil-weighted company with a large inventory of low-risk drilling locations. We intend to continue to principally focus on the development of our oil-weighted assets, but depending on commodity prices and rates of return our Haynesville Shale position gives us the flexibility to allocate capital to this natural gas asset.

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The following table provides a summary of our oil, natural gas and NGLs reserves as of December 31, 2014 and production data for the year ended December 31, 2014 for each of our areas of operation.

(1)                                     Proved reserves were evaluated using first day 12-month prices of $94.99 per barrel of oil (WTI) and $4.34 per MMBtu of natural gas (Henry Hub).

(2)                                     Comprised of outside operated overriding interests in the Gulf of Mexico and Rockies.

Approximately 223 MMBoe, or 36%, of our total proved reserves are proved developed producing assets, which generated an average production of 97.7 MBoe/d in 2014 from approximately 1,325 wells. As of December 31, 2014, we had approximately 321 MMBbls of proved oil reserves, 94 MMBbls of proved NGLs reserves and 1,243 Bcf of proved natural gas reserves in the United States, representing 52%, 15% and 33%, respectively, of our total proved reserves. For the year ended December 31, 2014, 68% of our production and 86% of our revenues (excluding realized and unrealized gains on financial derivatives) were related to oil and NGLs versus 53% and 82% in 2013, respectively, and over that same period and on that same basis, our oil production has grown by approximately 51%.  Based on our announced guidance, a substantial portion of our 2015 capital expenditures will be allocated to our oil programs.

We operate 85% of our producing wells and have operational control over approximately 97% of our operating area drilling inventory as of December 31, 2014. 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 drilling and completion structure to accelerate our internal knowledge transfer around the execution of our drilling and completion programs. In 2014, we drilled 273 wells with a success rate of 100%, adding approximately 101 MMBoe of proved reserves (77% of which were liquids), excluding divested assets. Our reserve replacement cost as of December 31, 2014 was $16.93 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.

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 Board members, each of the Board’s standing committee charters, and the Corporate Governance Guidelines 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.

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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:

·                  the oversupply of oil, natural gas and/or NGLs;

·                  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;

·                  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;

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

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

·                  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;

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

·                  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 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;

·                  adoption of various energy efficiency and conservation measures;

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

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

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. During the second half of 2014, NYMEX-WTI oil prices fell from in excess of $100 per Bbl to below $50 per Bbl, the lowest price since 2009. There is a risk that commodity prices could remain depressed for sustained periods.  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;

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·                  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 and weather patterns;

·                  technological advances affecting energy consumption and energy supply;

·                  domestic 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.

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.

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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;

·                  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.

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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 decline in commodity prices and 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.

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

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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. In 2014, we spent total capital including acquisitions of $2.2 billion. We have established a capital budget for 2015 of approximately $1.2 billion to $1.3 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 non-core asset sale transactions 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,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 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

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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 stockholders’ 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 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. Declines in commodity prices can also impact the number of service providers for such drilling rigs, equipment, supplies or qualified personnel, contributing to or also resulting in the shortages. During periods of high prices, the cost of rigs, equipment, supplies and personnel can fluctuate widely and availability may be limited. These services may not be available on commercially

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reasonable terms or at all. We cannot predict the extent to which these conditions will exist in the future or their timing or duration. 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 remediation costs. Any of these results could cause us to suffer substantial losses.

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

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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, 2014, four 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;

·                  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 and emissions, 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.

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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 triggered by a low commodity price environment 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.

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.

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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, Dane E. Whitehead, our Executive Vice President and Chief Financial Officer and Clayton A.Carrell, our Executive Vice President and Chief Operating 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 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

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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 a number of 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 where a final investment decision has been made to drill 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 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, at least one local water district has begun restricting the use of water subject to its 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.

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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;

·                  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.

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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 allocate sufficient capital to meet these obligations in a declining commodity price environment given capital reductions, there is a risk that some of our existing proved reserves and some of our unproved inventory/acreage could be subject to lease expiration or a requirement to incur additional leasehold costs to extend the lease. This could result in impairment of existing costs, 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.

Given the decline in commodity prices, especially oil, 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. Currently, our reserves are based on the first day 12-month average prices of $94.99 per barrel of oil and $4.34 per MMBtu of natural gas, which are above the current strip price. Additionally, we could incur significant impairment charges of our unproved property should oil prices not justify sufficient capital allocation to the continued development of our unproved properties, among other factors. 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.

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. 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.

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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 the 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 the U.S. Supreme Court partially invalidated the rule in an opinion issued in June 2014.  The Tailoring Rule remains applicable for those facilities considered major sources of six other “criteria” pollutants.  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 includes certain of our facilities, beginning in 2012 for emissions occurring in 2011.  Amendments to the GHG reporting rule, revising certain calculation methods and clarifying certain terms, became final in early 2015.  The EPA has also recently proposed amendments to include reporting of emissions from completions and workovers of oil wells using hydraulic fracturing, as well as emissions from gathering and boosting systems.  This proposed amendment is open for public comment through February 24, 2015.  Additionally, the EPA announced in January 2015 that it will initiate rulemaking to encompass further segments of industry in GHG reporting, as well as explore regulatory opportunity to require use of new measurement and monitoring technology.  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 March 2014, the White House announced a Climate Action Plan Strategy to Reduce Methane Emissions, and in support the EPA released five technical white papers focusing on emissions in the oil and gas industry.  Subsequently, in January 2015 the White House announced that rulemaking will be initiated by several federal agencies to further reduce emissions of methane and VOCs in the oil and gas sector, including the EPA, the BLM, and the Pipeline and Hazardous Materials Safety Administration (PHMSA).  From the EPA, such rulemaking may address green completions for hydraulically-fractured oil wells, emissions from pneumatic devices, and fugitive emissions at new or modified sources.  The EPA is also expected to propose new guidelines in summer 2015 to reduce ozone precursors from oil and gas sources in nonattainment areas, in addition to already-proposed changes to the National Air Quality Ambient Standards for ozone.  The BLM is expected to propose updated standards for venting and flaring in spring 2015.  Similarly in 2015, the PHMSA is expected to propose natural gas pipeline safety standards that will concurrently reduce methane emissions.  Finally, the White House has proposed funding for the Department of Energy (DOE) aimed at quantifying emissions from natural gas infrastructure and development of leak detection and control technology.

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, 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.

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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. It is possible that more stringent regulations might be enacted or delays in receiving permits may occur in other areas, such as our 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.

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

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propose federal Clean Water Act regulations governing wastewater discharges from hydraulic fracturing and certain other natural gas operations. Such regulations are expected to be issued in draft form in early 2015.  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, though a final rule has not been released.

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 was anticipated by 2014 for peer review and public comment, but has not yet been released. 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, the 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 were to 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, the EPA announced its intention to issue revised rules in 2013.  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.  Additional revisions became effective December 31, 2014, primarily defining two stages of well completion operations.

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 Occupational Safety and Health Administration (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 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.

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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.

Tax laws and regulations may change over time, including the elimination of federal income tax deductions currently available with respect to oil and gas exploration and development.

Tax laws and regulations are highly complex and subject to interpretation, and the tax laws and regulations to which we are subject may change over time. Our tax filings are based upon our interpretation of the tax laws in effect in various jurisdictions at the time that the filings were made. If these laws or regulations change, or if the taxing authorities do not agree with our interpretation of the effects of such laws and regulations, it could have a material adverse effect on our business and financial condition. Legislation has been proposed that would eliminate certain U.S. federal income tax provisions currently available to oil and gas exploration and production companies. Such changes include, but are not limited to:

·                  the repeal of the percentage depletion allowance for oil and gas properties;

·                  the elimination of current expensing of intangible drilling and development costs;

·                  the elimination of the deduction for certain U.S. production activities; and

·                  an extension of the amortization period for certain geological and geophysical expenditures.

It is unclear whether any such changes will be enacted or how soon such changes could be effective. The elimination of such U.S. federal tax deductions, as well as any other changes to or the imposition of new federal, state, local or non-U.S. taxes (including the imposition of, or increases in production, severance or similar taxes) could have a material adverse effect on our business, results of operations and financial condition.

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 7 to our consolidated financial statements and elsewhere in this 10-K. In addition, the positions taken in our federal, state, local and previously in 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.

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.

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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 various assets and either retained certain liabilities or indemnified certain purchasers against future liabilities relating to businesses and assets 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.  For example, the recent decline in commodity prices may create an environment where there is an increased risk that owners and/or operators of assets purchased from us may no longer be able to satisfy plugging or abandonment obligations that attach to such assets. In that event, due to operation of law, we may be required to assume these plugging or abandonment obligations on assets no longer owned and operated by us. 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;

·                  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 6 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 7, and is incorporated herein by reference.

ITEM 4.                         MINE SAFETY DISCLOSURES

Not applicable.

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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, 2014 and December 31, 2013 and the statements of income data and statements of cash flow data for the years ended December 31, 2014 and December 31, 2013 and for the period from March 23 to December 31, 2012 and the period from January 1, 2012 through May 24, 2012, 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, 2012 from the consolidated financial statements of EP Energy LLC, and the selected historical consolidated balance sheet as of December 31, 2011 and 2010, and the statements of income data and statements of cash flow data for the years ended December 31, 2011 and 2010 from the consolidated historical predecessor financial statements of EP Energy LLC, which are also 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.

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 year ended December 31, 2014, we recorded realized and unrealized gains on financial derivatives of $985 million.  For the year 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, 2011 and 2010, we recorded realized and unrealized gains on financial derivatives included in operating revenues of $365 million, $284 million and $390 million, and non-cash ceiling test and other impairment charges of $62 million, $6 million and $25 million, 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 South Louisiana Wilcox, CBM, South Texas and 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, year-over-year results may not be comparable.  Unless otherwise indicated or the context otherwise requires, references in this MD&A section to “we”, “our”, “us” and “the Company” refer to EP Energy LLC (the “Successor”) and EP Energy Global LLC (the “Predecessor” for accounting purposes), and each of their consolidated subsidiaries.

Our Business

Overview.  We are an independent exploration and production company engaged in the acquisition and development of unconventional onshore oil and natural gas properties in the United States. We are focused on creating shareholder value through the development of our low-risk drilling inventory located in four areas. Below are summary descriptions of each of our operating programs:

·                  Eagle Ford Shale. The Eagle Ford Shale in South Texas continues to provide the highest economic returns in our portfolio.

·                  Wolfcamp Shale. In our Wolfcamp Shale program, located in the Permian Basin in West Texas, we are focused on optimizing our drilling, completion and artificial lift systems.

·                  Altamont.  In the Altamont Field in the Uinta Basin in northeastern Utah, we are gaining operational efficiencies as we develop this oil field. Most of our acreage in this area is held-by-production.

·                  Haynesville Shale.  The Haynesville Shale in north Louisiana generates positive cash flow, and our acreage in the Haynesville Shale is held-by-production, giving us the flexibility to allocate capital to this natural gas asset based on returns available in the commodity price environment.

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

During 2014, we acquired producing properties and undeveloped acreage in the Southern Midland Basin, of which 37,000 net acres are adjacent to our existing Wolfcamp Shale position, for an aggregate cash purchase price of $152 million. The acquisition represents an approximate 25% expansion of our current Wolfcamp acreage.

Additionally, we completed the sale of (i) non-core assets in our Arklatex area and South Louisiana Wilcox area (approximately 78,000 net acres, excluding Haynesville and Bossier rights) for approximately $150 million of cash proceeds, with the buyer also assuming a transportation commitment of approximately $20 million (ii) our Brazilian operations and (iii) certain non-core acreage in Atascosa County in Eagle Ford for approximately $28 million of cash proceeds. We recorded a $10 million loss on the sale of our Arklatex and South Louisiana Wilcox assets and no gain or loss on the other sales.

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

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

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

·                  managing cash costs; and

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

In addition to these factors, our future profitability and performance will be affected by volatility in the financial and commodity markets, changes in the cost of drilling and oilfield services, operating and capital costs, and our debt level and related interest costs. Additionally, we may be impacted by weather events, 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.  Our realized prices from the sale of our oil and natural gas are affected by (i) commodity price movements, including locational or basis price differences that exist between the commodity index price (e.g., WTI) and the actual price at which we sell our oil and natural gas, and (ii) other contractual pricing adjustments contained in the underlying sales contract.  In order to stabilize cash flows and protect the economic assumptions associated with our capital investment programs, we enter into financial derivative contracts to reduce the financial impact of unfavorable commodity price movements and locational price differences. Certain derivative contracts, usually short term in nature (less than one year), involve the receipt or payment of premiums. During 2014, we received approximately $1 million in premiums on such derivative contracts, all of which settled during 2014.

During 2014, we (i) settled commodity index hedges on approximately 97% of our oil production (84% of our total liquids production) and 100% of our natural gas production at average floor prices of $97.99 per barrel of oil and $4.02 per MMBtu, respectively and (ii) hedged basis risk on approximately 60% of our 2014 Eagle Ford oil production. To the extent our oil and natural gas production is unhedged, either from a commodity index price or locational price perspective, our financial results will be impacted from period to period as further described in Operating Revenues. The following table reflects the contracted volumes and the prices we will receive under derivative contracts we held as of December 31, 2014.

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

(2)                                     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.

(3)                                     If market prices settle at or below $76.54 in 2016, we will receive a “locked-in” cash settlement of the market price plus $13.65 per Bbl.

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

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

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

(7)                                     EP Energy receives the basis spread listed and pays TGP, CIG and Waha basis.

The following table reflects the volumes and the prices associated with derivative contracts entered into between January 1,2015 and February 16, 2015, which are not reflected in the table above.

(1)                                   Volumes presented are MBbls. Prices presented are per Bbl.

(2)                                   In February 2015, we unwound 3,294 MBbls of 2016 LLS three way collars in exchange for 3,294 MBbls of 2016 WTI fixed price swaps. No cash or other consideration was included as part of this exchange.

(3)                                   In February 2015, we unwound 1,830 MBbls of 2016 LLS vs. Brent basis swaps in exchange for 1,830 MBbls of 2016 LLS vs. WTI basis swaps. No cash or other consideration was included as part of this exchange.

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Summary of Liquidity and Capital Resources.  As of December 31, 2014, we had available liquidity, including existing cash, of approximately $1.84 billion. We believe we have sufficient liquidity for 2015 from our cash flows from operations (including our hedging program), combined with the availability under our RBL Facility and available cash, to fund our current obligations, projected working capital requirements and our capital spending plan.  Additionally, the earliest maturity date of our debt obligations is in 2017 when amounts outstanding under our RBL Facility mature. Finally, given recent declines in oil prices, we believe our oil and natural gas hedge positions also provide significant price protection to our near-term revenues and cash flows. See “Liquidity and Capital Resources” for more information.

Outlook. For 2015, we expect the following:

·                  Capital expenditures of approximately $1.2 billion to $1.3 billion, allocated primarily to our oil programs: $825 million for Eagle Ford, $190 million for Wolfcamp, $140 million for Altamont and $100 million for Haynesville.

·                  Well completions between 160 and 190.

·                  Average daily production volumes for the year of approximately 94.5 MBoe/d to 109.5 MBoe/d, including average daily oil production volumes of approximately 56 MBbls/d to 64 MBbls/d.

·                  Per unit adjusted cash operating costs for the year of approximately $10.50 to $13.50 per Boe, and transportation costs of $2.90 to $3.35 per Boe.

·                  Per unit depreciation, depletion and amortization rate for the year of approximately $25.00 to $27.00 per Boe.

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Production Volumes and Drilling Summary

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

(1)                                     2013 volumes include 6 MBoe/d, 1 MBbls/d of oil, 28 MMcf/d of natural gas and 1 MBbls/d of NGLs from Four Star Oil & Gas Company (Four Star), our equity investment sold in September 2013. 2012 volumes include 9 MBoe/d, 1 MBbls/d of oil, 42 MMcf/d of natural gas and 1 MBbls/d of NGLs from Four Star. Remaining volumes are from our Arklatex and South Louisiana Wilcox areas sold in 2014, CBM and South Texas assets sold in 2013, and our Gulf of Mexico assets, which were sold in 2012. For periods after May 24, 2012, Arklatex, South Louisiana Wilcox, CBM and South Texas 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.

·                  Eagle Ford Shale—Our Eagle Ford Shale equivalent volumes and oil production increased 14 MBoe/d (approximately 38%) and 11 MBbls/d (45%), respectively, for the year ended December 31, 2014 compared to 2013 due to the success of our drilling program in the area.  During 2014, we completed 136 additional operated wells in the Eagle Ford, and we had a total of 399 net operated wells as of December 31, 2014. With a majority of our acreage located in the core of the oil window, primarily in LaSalle county, we continue to grow our oil and NGLs production in the area. We closed the sale of certain non-core acreage in Atascosa county for approximately $28 million in December 2014.

·                  Wolfcamp Shale—Our Wolfcamp Shale equivalent volumes increased 10 MBoe/d (approximately 200%) for the year ended December 31, 2014 compared to 2013 as we continued to progress the development of the program. During 2014, we completed 90 additional operated wells, for a total of 201 net operated wells as of December 31, 2014 (which includes wells acquired in April 2014).

·                  Altamont—Our Altamont equivalent volumes increased 4 MBoe/d (approximately 33%) for the year ended December 31, 2014 compared to 2013. Altamont produced an average of 12 MBbls/d of oil during 2014, and we completed an additional 47 operated oil wells for a total of 356 net operated wells at December 31, 2014.  In October 2014, the Utah Board of Oil, Gas and Mining provisionally approved 80-acre well density on approximately 50,000 of our Altamont net acreage.

·                  Haynesville Shale—Our Haynesville Shale equivalent volumes decreased 11 MMcf/d (approximately 41%) for the year ended December 31, 2014 compared to 2013, due to natural production declines. As of December 31, 2014, we had 99 net operated wells in the Haynesville Shale, and our total natural gas production for 2014 was approximately 96 MMcf/d. We have allocated a portion of our capital budget in 2015 to our Haynesville drilling program based on its returns in the forecasted commodity price environment

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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:

(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, 2014, proved developed reserves represented approximately 38% 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.

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

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

(2)                  For the year ended December 31, 2014, reserve replacement ratio and reserve replacement costs including acquisitions and price revisions were 363% and $16.90 per Boe, and excluding price revisions were 274% and $22.37 per Boe. No acquisitions are included in our reserve replacement ratio or reserve replacement costs for the years ended December 31, 2013 and 2012, 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.

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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, 2014.

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Results of Operations

The information below reflects financial results for EP Energy LLC for the years ended December 31, 2014 and 2013, for the period from March 23 (inception) to December 31, 2012, and for the period from January 1 to May 24, 2012. Our financial results, beginning with the Acquisition on May 24, 2012, 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 2014 and 2013 and the 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 periods after the Acquisition and future periods may be 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, 2014 with results for the year ended December 31, 2013 and (ii) 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”).  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.

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