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UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q

(Mark One)

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

For the quarterly period ended March 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 001-36253

EP Energy Corporation

(Exact Name of Registrant as Specified in Its Charter)

Telephone Number: (713) 997-1200

Internet Website: www.epenergy.com

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.  Yes x  No o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).  Yes x  No o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.:

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

Indicate the number of shares outstanding of each of the registrant’s classes of common stock, as of the latest practicable date.

Class A Common Stock, par value $0.01 per share. Shares outstanding as of May 2, 2014: 244,979,094

Class B Common Stock, par value $0.01 per share. Shares outstanding as of May 2, 2014: 872,586

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EP ENERGY CORPORATION

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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 Corporation and/or our subsidiaries.

All references to “common stock” herein refer to Class A common stock.

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

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

·                  capital and other expenditures;

·                  financing plans;

·                  capital structure;

·                  liquidity and cash flow;

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

·                  future economic and operating performance;

·                  operating income;

·                  management’s plans; and

·                  goals and objectives for future operations.

Forward-looking statements are subject to risks and uncertainties. While we believe the assumptions or bases underlying the forward-looking statements are reasonable and are made in good faith, we caution that assumed facts or bases almost always vary from actual results, and these variances can be material, depending upon the circumstances. We cannot assure you that the statements of expectation or belief contained in our forward-looking statements will result or be achieved or accomplished. Important factors that could cause actual results to differ materially from estimates or projections contained in our forward-looking statements are described in our 2013 Annual Report on Form 10-K. There have been no material changes to the risk factors described in the Form 10-K.

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PART I — FINANCIAL INFORMATION

Item 1. Financial Statements

EP ENERGY CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF INCOME

(In millions, except per common share amounts)

(Unaudited)

See accompanying notes.

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EP ENERGY CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS

(In millions)

(Unaudited)

See accompanying notes.

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EP ENERGY CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS

(In millions)

(Unaudited)

See accompanying notes.

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EP ENERGY CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(In millions)

(Unaudited)

See accompanying notes

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EP ENERGY CORPORATION

CONDENSED CONSOLIDATED STATEMENT OF CHANGES IN EQUITY

(In millions)

(Unaudited)

See accompanying notes.

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EP ENERGY CORPORATION

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

1. Basis of Presentation and Significant Accounting Policies

Basis of Presentation

We prepared this Quarterly Report on Form 10-Q under the rules and regulations of the United Stated Securities and Exchange Commission (SEC) and in accordance with United States generally accepted accounting principles as it applies to interim condensed consolidated financial statements. Because this is an interim period report presented using a condensed format, it does not include all of the disclosures required by United States generally accepted accounting principles and should be read along with our 2013 Annual Report on Form 10-K. The condensed consolidated financial statements as of March 31, 2014 and 2013 are unaudited. The consolidated balance sheet as of December 31, 2013 has been derived from the audited consolidated balance sheet included in our 2013 Annual Report on Form 10-K.  In our opinion, all adjustments which are of a normal, recurring nature are reflected to fairly present these interim period results. The results for any interim period are not necessarily indicative of the expected results for the entire year.

Significant Accounting Policies

There were no changes in significant accounting policies as described in the 2013 Annual Report on Form 10-K.

New Accounting Pronouncements Issued But Not Yet Adopted

The following accounting standard has been issued but not yet been adopted.

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

2. Acquisitions and Divestitures

Discontinued Operations. We have reflected as discontinued operations certain domestic natural gas assets sold in 2013 (including CBM properties located in the Raton, Black Warrior and Arkoma basins; Arklatex conventional natural gas assets located in East Texas and North Louisiana and legacy South Texas conventional natural gas assets) and our Brazilian operations which are under contract to be sold.  We expect to complete the sale in 2014 which is awaiting Brazilian regulatory approval as well as certain other customary closing conditions.  In the first quarter of 2014, we completed the sale of certain additional domestic natural gas assets in our Arklatex area for approximately $16 million and recorded a gain on the sale of approximately $13 million, which is reflected in income from discontinued operations.

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

(1)                                     During the quarter ended March 31, 2014, we recorded $3 million in impairment charges to impair earnings subsequent to entering into a Quota Purchase Agreement to sell our Brazil operations in 2013.

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

On April 30, 2014, we announced the acquisition of approximately 37,000 net acres of certain producing properties and undeveloped acreage in the Southern Midland Basin adjacent to our existing Wolfcamp Shale position. The acquisition represents an approximate 25 percent expansion of our current Wolfcamp acreage. We also entered into an agreement to divest certain non-core assets in the Arklatex and South Louisiana Wilcox areas (approximately 78,000 net acres).  The aggregate cash purchase price for the acquired properties is $153 million, while the divested properties will generate $150 million of cash proceeds, with the buyer also assuming a transportation liability of approximately $20 million.  The assets to be sold will be presented as discontinued operations beginning in the second quarter.

3. Income Taxes

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

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Effective Tax Rate. Interim period income taxes are computed by applying an anticipated annual effective tax rate to year-to-date income or loss, except for significant unusual or infrequently occurring items, which are recorded in the period in which they occur. Changes in tax laws or rates are recorded in the period they are enacted.

For the quarter ended March 31, 2014, we recorded an income tax benefit of $56 million (deferred income tax benefit of $57 million and current tax expense of $1 million) resulting in an effective tax rate of 36%.  Our effective tax rate for the quarter ended March 31, 2014 includes the effects of state income taxes and non-deductible compensation expense, substantially offset by the tax effects of discrete adjustments for certain transaction costs related to our initial public offering.  For the quarter ended March 31, 2013, we were a partnership not subject to federal and state income taxes.  If we had recorded income taxes effective January 1, 2013, through March 31, 2013, pro forma loss from continuing operations would have been approximately $91 million based on applying a federal statutory tax rate of 35%.

4. Earnings Per Share

On January 2, 2014, we completed a 62.553-for-1 stock split of our common stock. For the quarter ended March 31, 2013, we retrospectively reflected earnings per common share/earnings per member unit (each member unit was converted into an equivalent common share in connection with the August 2013 Corporate Reorganization), giving effect to the stock split. On January 23, 2014, we completed a public offering of 35.2 million shares of Class A Common Stock, $0.01 par value per share.  For each financial statement period presented, there were no dilutive securities for purposes of calculating diluted earnings per share.

5. Financial Instruments

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

As of March 31, 2014 and December 31, 2013, the carrying amount of cash and cash equivalents, accounts receivable and accounts payable represent fair value because of the short-term nature of these instruments. We hold long-term debt obligations (see Note 7) with various terms. We estimated the fair value of debt (representing a Level 2 fair value measurement) primarily based on quoted market prices for the same or similar issuances, including consideration of our credit risk related to those instruments.

Oil, Natural Gas and NGLs Derivative Instruments.  We attempt to mitigate a portion of our commodity price risk and stabilize cash flows associated with forecasted sales of oil, natural gas and NGLs through the use of fixed price hedges.  As of March 31, 2014 and December 31, 2013, we had total derivative contracts on 49 MMBbls and 47 MMBbls of oil and 123 TBtu and 135 TBtu of natural gas, respectively.  As of March 31, 2014, we also had derivative contracts on 35 MMGal of propane. None of these contracts are designated as accounting hedges.  As of May 6, 2014, we added 1.5 MMBbls of LLS fixed price oil swaps to our anticipated 2016 production and 3.7 TBtu of fixed price natural gas swaps to our anticipated 2015 production.

Interest Rate Derivative Instruments.  We have interest rate swaps with a notional amount of $600 million that extend through April 2017 and are intended to reduce variable interest rate risk. As of March 31, 2014 and December 31, 2013, we had a net asset of $4 million related to interest rate derivative instruments included in our consolidated balance sheets.  For each of the quarters ended March 31, 2014 and 2013, we recorded $1 million in interest expense related to the change in fair market value and cash settlements of our interest rate derivative instruments.

Fair Value Measurements.  We use various methods to determine the fair values of our financial instruments. The fair value of a financial instrument depends on a number of factors, including the availability of observable market data over the contractual term of the underlying instrument. We separate the fair values of our financial instruments into three levels (Levels 1, 2 and 3) based on our assessment of the availability of observable market data and the significance of non-observable data used to determine fair value.  As of March 31, 2014 and December 31, 2013, all financial instruments were classified as Level 2. Our assessment of an instrument within a level can change over time based on the maturity or liquidity of the instrument, which could result in a change in the classification of our financial instruments between other levels.

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Financial Statement Presentation.  The following table presents the fair value associated with derivative financial instruments as of March 31, 2014 and December 31, 2013. All of our derivative instruments are subject to master netting arrangements which provide for the unconditional right of offset for all derivative assets and liabilities with a given counterparty in the event of default. We present assets and liabilities related to these instruments in our balance sheets as either current or non-current assets or liabilities based on their anticipated settlement date, net of the impact of master netting agreements.  On derivative contracts recorded as assets in the table below, we are exposed to the risk that our counterparties may not perform.

(1)                                     Gross derivative assets are comprised primarily of $103 million of oil, natural gas and NGLs derivatives as of March 31, 2014 and $157 million of oil and natural gas derivatives as of December 31, 2013 and $7 million of interest rate derivatives for each of the periods ended March 31, 2014 and December 31, 2013.  Gross derivative liabilities are comprised primarily of $109 million of oil, natural gas and NGLs derivatives as of March 31, 2014 and $52 million of oil and natural gas derivatives as of December 31, 2013 and $3 million of interest rate derivatives for each of the periods ended March 31, 2014 and December 31, 2013.

Losses on oil, natural gas and NGLs financial derivative instruments presented in operating revenues were $135 million for the quarter ended March 31, 2014.  Losses on oil and natural gas financial derivative instruments were $131 million for the quarter ended March 31, 2013.

6.  Property, Plant and Equipment

General.  As of March 31, 2014 and December 31, 2013, we had $1.2 billion and $1.4 billion of unproved oil and natural gas properties on our balance sheet.  During the first quarter of 2014, we transferred approximately $0.2 billion from unproved properties to proved properties.  For the quarters ended March 31, 2014 and 2013 we recorded $7 million and $12 million of amortization of unproved leasehold costs in exploration expense in our income statement.  Suspended well costs were not material as of March 31, 2014 or December 31, 2013.  For a discussion of our impairment assessment of oil and natural gas properties see Note 3 to our Annual Report on Form 10-K.

Asset Retirement Obligations. We have legal asset retirement obligations associated with the retirement of our oil and natural gas wells and related infrastructure. We incur these obligations when production on those wells is exhausted, when we no longer plan to use them or when we abandon them. We accrue these obligations when we can estimate the timing and amount of their settlement. In estimating the liability associated with our asset retirement obligations, we utilize several assumptions, including a credit-adjusted risk-free rate of 7 percent and a projected inflation rate of 2.5 percent. The net asset retirement liability as of March 31, 2014 on our consolidated balance sheet in other current and non-current liabilities and the changes in the net liability from January 1 through March 31, 2014 were as follows:

(1)                                     Amount does not include $37 million as of March 31, 2014 of net asset retirement liability associated with our Brazil operations classified as discontinued operations.

Capitalized Interest.  Interest expense is reflected in our financial statements net of capitalized interest. Capitalized interest for each of the quarters ended March 31, 2014 and 2013 was approximately $5 million.

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7. Long-Term Debt

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

(1)     The term loan was issued at 99 percent of par and carries interest at a specified margin over the LIBOR of 4.00%, with a minimum LIBOR floor of 1.00%. As of March 31, 2014, the effective interest rate of the term loan was 3.50%.

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

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

As of March 31, 2014 and December 31, 2013, we had $106 million and $116 million, respectively, in deferred financing costs on our consolidated balance sheets. During each of the quarters ended March 31, 2014 and 2013, we amortized $5 million of deferred financing costs. These costs are included in interest expense.  During the first quarter of 2014, we repaid and retired our senior PIK toggle note with a portion of the proceeds from our initial public offering.  During the quarters ended March 31, 2014 and 2013, we recorded $17 million and $1 million in losses on the extinguishment of debt in our consolidated income statement as a result of the retirement of the PIK toggle note in 2014 and to reflect the pro-rata portion of deferred financing costs written off in conjunction with the semi-annual redetermination of our RBL Facility in March 2013.

$2.5 Billion Reserve-based Loan (RBL). Under the RBL Facility, we can borrow funds or issue letters of credit and as of March 31, 2014, we had a $2.5 billion RBL borrowing base, $275 million of outstanding borrowings and approximately $8 million of letters of credit issued under the facility, leaving $2.2 billion of remaining capacity. As of May 6, 2014, we had $700 million in outstanding borrowings under the facility.

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

Restrictive Provisions/Covenants.  The availability of borrowings under our credit agreements and our ability to incur additional indebtedness is subject to various financial and non-financial covenants and restrictions. There have been no significant changes to our restrictive covenants, and as of March 31, 2014, we were in compliance with all of our debt covenants. For a further discussion of our debt agreements and restrictive covenants, see our 2013 Annual Report on Form 10-K.

8. Commitments and Contingencies

Legal Matters

We and our subsidiaries and affiliates are parties to various legal actions and claims that arise in the ordinary course of our business. For each of these matters, we evaluate the merits of the case or claim, our exposure to the matter, possible legal or settlement strategies and the likelihood of an unfavorable outcome. If we determine that an unfavorable outcome is probable and can be estimated, we establish the necessary accruals. While the outcome of our current matters cannot be predicted with certainty and there are still uncertainties related to the costs we may incur, based upon our evaluation and experience to date, we believe we have established appropriate reserves for these matters. It is possible, however, that new information or future developments could require us to reassess our potential exposure related to these matters and adjust our accruals accordingly, and these adjustments could be material. As of March 31, 2014, we had approximately $1 million accrued for all outstanding legal matters.

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

Indemnifications and Other Matters. We periodically enter into indemnification arrangements as part of the divestitures of assets or businesses. These arrangements include, but are not limited to, indemnifications for income taxes, the resolution of existing disputes, environmental and other contingent matters. In addition, under various laws or regulations, we could be subject to the imposition of certain liabilities, for example, plugging and abandonment obligations for assets no longer owned or operated by us. As of March 31, 2014, we had approximately $5 million accrued related to these indemnifications and other matters.

Environmental Matters

We are subject to existing federal, state and local laws and regulations governing environmental quality, pollution control and greenhouse gas (GHG) emissions.  The environmental laws and regulations to which we are subject also require us to remove or remedy the effect on the environment of the disposal or release of specified substances at current and former operating sites. As of March 31, 2014, we had accrued approximately $1 million for related environmental remediation costs associated with onsite, offsite and groundwater technical studies and for related environmental legal costs. Our accrual represents a combination of two estimation methodologies. First, where the most likely outcome can be reasonably estimated, that cost has been accrued. Second, where the most likely outcome cannot be estimated, a range of costs is established and if no one amount in that range is more likely than any other, the lower end of the expected range has been accrued. Our exposure could be as high as $3 million.  Our environmental remediation projects are in various stages of completion. The liabilities we have recorded reflect our current estimates of amounts that we will expend to remediate these sites. However, depending on the stage of completion or assessment, the ultimate extent of contamination or remediation required may not be known. As additional assessments occur or remediation efforts continue, we may incur additional liabilities.

Climate Change and Other Emissions.  The Environmental Protection Agency (EPA) and several state environmental agencies have adopted regulations to regulate GHG emissions. Although the EPA has adopted a “tailoring” rule to regulate GHG emissions, at this time we do not expect a material impact to our existing operations. There have also been various legislative and regulatory proposals and final rules at the federal and state levels to address emissions from power plants and industrial boilers. Although such rules and proposals will generally favor the use of natural gas over other fossil fuels such as coal, it remains uncertain what regulations will ultimately be adopted and when they will be adopted. As part of the White House’s Climate Action Plan, the EPA intends to examine technical white papers about methane emissions in the oil and gas industry and may propose additional regulations in 2016.  Further, the Bureau of Land Management may propose additional regulations for public lands in 2014.  Any regulations regarding GHG emissions would likely increase our costs of compliance by potentially delaying the receipt of permits and other regulatory approvals; requiring us to monitor emissions, install additional equipment or modify facilities to reduce GHG and other emissions; purchase emission credits; and utilize electric-driven compression at facilities to obtain regulatory permits and approvals in a timely manner.

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

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

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

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

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

Comprehensive Environmental Response, Compensation and Liability Act (CERCLA) Matters. As part of our environmental remediation projects, we are or have received notice that we could be designated as a Potentially Responsible Party (PRP) with respect to one active site under the CERCLA or state equivalents. As of March 31, 2014, we have estimated our share of the remediation costs at this site to be less than $1 million. Because the clean-up costs are estimates and are subject to revision as more information becomes available about the extent of remediation required, and because in some cases we have asserted a defense to any liability, our estimates could change. Moreover, liability under the federal CERCLA statute may be joint and several, meaning that we could be required to pay in excess of our pro rata share of remediation costs. Our understanding of the financial strength of other PRPs has been considered, where appropriate, in estimating our liabilities. Accruals for these matters are included in the reserve for environmental matters discussed above.

It is possible that new information or future developments could require us to reassess our potential exposure related to environmental matters. We may incur significant costs and liabilities in order to comply with existing environmental laws and regulations. It is also possible that other developments, such as increasingly strict environmental laws, regulations, and orders of regulatory agencies, as well as claims for damages to property and the environment or injuries to employees and other persons resulting from our current or past operations, could result in substantial costs and liabilities in the future. As this information becomes available, or other relevant developments occur, we will adjust our accrual amounts accordingly. While there are still uncertainties related to the ultimate costs we may incur, based upon our evaluation and experience to date, we believe our reserves are adequate.

9. Long-Term Incentive Compensation

Our long-term incentive (LTI) awards currently include a cash-based incentive award and certain equity-based programs.  Each of these awards are further described in our 2013 Annual Report on Form 10-K.

Compensation expense (recorded as general and administrative expense on our income statement) related to all of our long-term incentive awards was approximately $9 million and $13 million during the quarters ended March 31, 2014 and 2013, respectively. As of March 31, 2014, we had unrecognized compensation expense of $50 million.  We will recognize an additional $14 million related to outstanding awards as of March 31 during the rest of 2014, $17 million over the remaining requisite service periods subsequent to 2014 and $19 million upon a specified capital transaction when the right to such amounts become non-forfeitable.

10. Investment in Unconsolidated Affiliate

In September 2013, we sold our equity investment in Four Star Oil & Gas Company (Four Star) for net proceeds of $183 million. For the quarter ended March 31, 2013, we recorded $2 million in earnings from unconsolidated affiliate reflecting $5 million for our share of net equity earnings directly attributable to Four Star and $3 million of amortization of the excess of the carrying value of our investment relative to the underlying equity in the net assets of the entity.  Total operating revenues, operating expenses and net income of Four Star for the quarter ended March 31, 2013 were $49 million, $33 million, and $9 million, respectively.  For the quarter ended March 31, 2013, we received dividends from Four Star of approximately $8 million.

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11. Related Party Transactions

Management Fee Agreement. In January 2014, we paid a quarterly management fee of $6.25 million to our private equity investors (affiliates of Apollo Global Management LLC, Riverstone Holdings LLC, Access Industries and Korea National Oil Corporation, collectively the Sponsors). Additionally, subject to the terms and conditions of the amended and restated Management Fee Agreement, upon the closing of our initial public offering in January 2014, we paid the Sponsors an additional transaction fee equal to approximately $83 million (the lesser of (i) 1% of the aggregate enterprise value paid or provided by the Company Group and (ii) $100,000,000).  We recorded both of these fees in general and administrative expense for the quarter ended March 31, 2014. The amended and restated Management Fee Agreement, including the obligation to pay the quarterly management fee, terminated automatically in accordance with its terms upon the closing of our initial public offering.

Affiliate Supply Agreement.  As of March 31, 2014, we have recorded approximately $160 million, cumulatively, in capital expenditures for amounts provided under a supply agreement with an Apollo affiliate through October 2014 to provide certain fracturing materials for our Eagle Ford drilling operations.

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

Our Management’s Discussion and Analysis of Financial Condition and Results of Operations (“MD&A”) should be read in conjunction with the financial statements and the accompanying notes presented in Item 1 of Part I of this Quarterly Report on Form 10-Q. This discussion contains forward-looking statements and involves numerous risks and uncertainties, including, but not limited to, those described in the “Risk Factors” section of our 2013 Annual Report on Form 10-K. Actual results may differ materially from those contained in any forward-looking statements.  All periods included in these interim financial statements present our Brazil operations and certain domestic natural gas assets sold noted below as discontinued operations. Unless otherwise indicated or the context otherwise requires, references in this MD&A section to “we”, “our”, “us” and “the Company” refer to EP Energy Corporation and each of its consolidated subsidiaries.

Our Business

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

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

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

·                  Altamont.  In Altamont, we are gaining operational efficiencies as we develop this oil-based field. Most of our acreage in this area is held-by-production.  At the end of April 2014, we released the fourth rig and are currently running three rigs in this program.

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

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

On April 30, 2014, we announced the acquisition of approximately 37,000 net acres of certain producing properties and undeveloped acreage in the Southern Midland Basin adjacent to our existing Wolfcamp Shale position for an aggregate cash purchase price of $153 million. The acquisition represents an approximate 25 percent expansion of our current Wolfcamp acreage.  The acquired properties are 100 percent operated with net production of approximately 1,000 Boe/d which is 75 percent liquids.  We expect to integrate the acquired properties into our existing development program with minimal 2014 capital.

Additionally, we also entered into an agreement to divest certain non-core assets in the Arklatex and South Louisiana Wilcox areas (approximately 78,000 net acres) for $150 million of cash proceeds with the buyer also assuming a transportation liability of approximately $20 million.  Net estimated annual production associated with the divested properties is approximately 21 MMcfe/d, approximately 85 percent of which is natural gas. We expect to complete the sale in the second quarter of 2014 and use the proceeds to offset the funds used for the acquisition noted above.  We will present these assets to be sold as discontinued operations beginning in the second quarter.

We have reflected as discontinued operations certain domestic natural gas assets sold in 2013 (including CBM properties located in the Raton, Black Warrior and Arkoma basins; Arklatex conventional natural gas assets located in East Texas and North Louisiana and legacy South Texas conventional natural gas assets) and our Brazilian operations which are under contract to be sold.  We expect the sale (which represents the sale of all of our remaining international assets) to close in 2014, subject to Brazilian regulatory approval and certain other customary closing conditions.  During the first quarter of 2014, we sold additional domestic natural gas assets in our Arklatex area for approximately $16 million and recorded a gain on sale of approximately $13 million, which is reflected in income from discontinued operations.

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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, or domestic or international regulatory issues or other third party actions outside of our control (e.g., oil spills).

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

Derivative Instruments.  Our realized prices from the sale of our oil, natural gas and NGLs are affected by (i) commodity price movements, including locational or basis price differences that exist between the commodity index price (e.g., WTI) and the actual price at which we sell our oil, natural gas, or NGLs, and (ii) other contractual pricing adjustments contained in the underlying sales contract.  In order to stabilize cash flows and protect the economic assumptions associated with our capital investment programs, we enter into financial derivative contracts to reduce the financial impact of unfavorable commodity price movements and locational price differences. During the quarter ended March 31, 2014, we (i) settled commodity index hedges on approximately 94% of our liquids (oil and NGLs) production and 96% of our natural gas production at average floor prices of $98.11 per barrel and $4.02 per MMBtu, respectively and (ii) settled basis hedges on approximately 53% of our estimated Eagle Ford oil production.  To the extent our oil, natural gas, and NGL production is unhedged, either from a commodity index price or locational price perspective, our financial results will be impacted from period to period.  See Operating Revenues discussion for more information. The following table reflects the contracted volumes and the prices we will receive under derivative contracts we held as of March 31, 2014.

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

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

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

(4)             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.

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

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

(7)             Represents an effective floor price on the hedged production of $100.70 per Bbl for 2014, $96.24 per Bbl for 2015 and $93.40 per Bbl for 2016. Floor prices do not include customary refinery and contract deductions.

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

As of May 6, 2014, we added LLS fixed price oil swaps of 1.5 MMBbls to our anticipated 2016 production with an average price of $89.08 per Bbl and 3.7 TBtu of fixed price natural gas swaps to our anticipated 2015 production with an average price of $4.37 per MMBtu.  These derivative instruments are not included in the table above.

Summary of Liquidity and Capital Resources.  As of March 31, 2014, we had available liquidity, including existing cash, of approximately $2.3 billion. We believe we have sufficient liquidity for 2014 from our cash flows from operations, combined with the availability under our RBL Facility and available cash, to fund our current obligations, projected working capital requirements and capital spending plan.  In April 2014, we completed our semi-annual redetermination maintaining the borrowing base of our RBL Facility at $2.5 billion. Additionally, the earliest maturity date of our debt obligations is in 2017. See “Liquidity and Capital Resources” for more information.

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

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

·                  Twenty percent increase in well completions from 2013 to between 265 and 290.

·                  Average daily production volumes for the year of approximately 93.5 MBoe/d to 99.5 MBoe/d, including average daily oil production volumes of approximately 52 MBbls/d to 55 MBbls/d.

·                  Per unit adjusted cash operating costs for the year of approximately $12.25 to $14.25 per Boe, and transportation costs of $3.00 to $3.50 per Boe.

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

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Production Volumes and Drilling Summary

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