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TABLE OF CONTENTS
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

Table of Contents

As filed with the Securities and Exchange Commission on September 4, 2013

Registration No. 333-        

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549



FORM S-1
REGISTRATION STATEMENT
UNDER
THE SECURITIES ACT OF 1933



EP ENERGY CORPORATION
(Exact name of registrant as specified in its charter)



Delaware
(State or other jurisdiction of
incorporation or organization)
  1311
(Primary Standard Industrial
Classification Code Number)
  46-3472728
(I.R.S. Employer
Identification Number)



1001 Louisiana Street
Houston, Texas 77002
713-997-1200

(Address, including zip code, and telephone number, including
area code, of registrants' principal executive offices)



Marguerite N. Woung-Chapman
Senior Vice President, General Counsel and Corporate Secretary
EP Energy Corporation
1001 Louisiana Street
Houston, Texas 77002
713-997-1200

(Name, address, including zip code, and telephone number, including area code, of agent for service)



With copies to:


Rosa A. Testani
John Goodgame
Akin Gump Strauss Hauer & Feld LLP
One Bryant Park
New York, NY 10036
212-872-8115

 

Gregory A. Ezring
Paul, Weiss, Rifkind, Wharton & Garrison LLP
1285 Avenue of the Americas
New York, NY 10019-6064
212-373-3458

 

Sean T. Wheeler
Latham & Watkins LLP
811 Main Street, Suite 3700
Houston, TX 77002
713-546-7418



Approximate date of commencement of proposed sale of the securities to the public:
As soon as practicable after this Registration Statement becomes effective.

          If any of the securities being registered on this form are to be offered on a delayed or continuous basis pursuant to Rule 415 under the Securities Act of 1933, check the following box.    o

          If this Form is filed to register additional securities for an offering pursuant to Rule 462(b) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.    o

          If this Form is a post-effective amendment filed pursuant to Rule 462(c) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.    o

          If this Form is a post-effective amendment filed pursuant to Rule 462(d) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.    o

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

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

CALCULATION OF REGISTRATION FEE

       
 
Title of each class of securities
to be registered

  Proposed maximum
aggregate offering
price(1)

  Amount of
registration fee

 

Class A Common Stock, $0.01 par value per share

  $100,000,000   $13,640

 

(1)
Estimated solely for the purpose of calculating the registration fee pursuant to Rule 457(o) under the Securities Act of 1933, as amended.



          The Registrant hereby amends this Registration Statement on such date or dates as may be necessary to delay its effective date until the Registrant shall file a further amendment which specifically states that this Registration Statement shall thereafter become effective in accordance with Section 8(a) of the Securities Act of 1933, as amended, or until this Registration Statement shall become effective on such date as the Commission, acting pursuant to said Section 8(a), may determine.

   


Table of Contents

The information in this prospectus is not complete and may be changed. We may not sell these securities until the registration statement filed with the Securities and Exchange Commission is effective. This preliminary prospectus is not an offer to sell securities and it is not soliciting an offer to buy these securities in any state where the offer or sale is not permitted.

Subject to completion, dated September 4, 2013

PRELIMINARY PROSPECTUS

                        Shares

GRAPHIC

EP Energy Corporation

Common Stock

$            per share



        This is our initial public offering. We are selling          shares of Class A common stock, $0.01 par value per share. All references to common stock herein refer to Class A common stock.

        We expect the public offering price to be between $            and $            per share. Currently, no public market exists for our common stock. We intend to apply to list our common stock on the New York Stock Exchange under the symbol "EPE." Following the completion of this offering, we will remain a "controlled company" as defined under the NYSE listing rules because the group consisting of our Sponsors, which is comprised of affiliates of Apollo Global Management, LLC, Riverstone Holdings LLC, Access Industries and Korea National Oil Corporation, will beneficially own        % of our shares of outstanding common stock, assuming the underwriters do not exercise their option to purchase up to            additional shares from us. See "Principal Stockholders."



        Investing in our common stock involves risks that are described in the "Risk Factors" section beginning on page 19 of this prospectus.



           
 
 
  Price to Public
  Underwriting
Discounts and
Commissions

  Proceeds to
EP Energy
Corporation

 

Per Share

  $             $             $          
 

Total

  $             $             $          

 

        We have granted the underwriters an option for a period of 30 days from the date of this prospectus to purchase up to an additional            shares of our common stock at the initial public offering price less the underwriting discount.

        Delivery of the shares of common stock will be made on or about                      , 2013.

        Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved of these securities or passed upon the adequacy or accuracy of this prospectus. Any representation to the contrary is a criminal offense.



   

The date of this prospectus is                      , 2013.


Table of Contents

GRAPHIC


Table of Contents


TABLE OF CONTENTS

 
  Page  

SUMMARY

    1  

RISK FACTORS

   
19
 

CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

   
51
 

USE OF PROCEEDS

   
52
 

DIVIDEND POLICY

   
53
 

CAPITALIZATION

   
54
 

DILUTION

   
55
 

SELECTED HISTORICAL CONSOLIDATED FINANCIAL DATA

   
57
 

MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

   
60
 

BUSINESS

   
89
 

MANAGEMENT

   
121
 

PRINCIPAL STOCKHOLDERS

   
156
 

CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

   
159
 

CORPORATE REORGANIZATION

   
166
 

DESCRIPTION OF CAPITAL STOCK

   
168
 

DESCRIPTION OF CERTAIN INDEBTEDNESS

   
178
 

SHARES ELIGIBLE FOR FUTURE SALE

   
184
 

MATERIAL U.S. FEDERAL INCOME TAX CONSEQUENCES TO NON-U.S. HOLDERS

   
186
 

UNDERWRITING

   
190
 

LEGAL MATTERS

   
195
 

EXPERTS

   
195
 

WHERE YOU CAN FIND MORE INFORMATION

   
196
 

GLOSSARY OF OIL AND NATURAL GAS TERMS

   
A-1
 

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

   
F-1
 

        You should rely only on the information contained in this prospectus. We have not authorized any person to provide you with any information or represent anything about us or this offering that is not contained in this prospectus. If given or made, any such other information or representation should not be relied upon as having been authorized by us. We are not making an offer in any jurisdiction where an offer or sale is not permitted. The information contained in this prospectus is current only as of its date.

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MARKET AND INDUSTRY DATA

        This prospectus includes statements regarding factors that have impacted our and our customers' industries, such as our customers' access to capital. Such statements regarding our and our customers' industries and market share or position are statements of belief and are based on market share and industry data and forecasts that we have obtained from industry publications and surveys, as well as internal company sources. Industry publications, surveys and forecasts generally state that the information contained therein has been obtained from sources believed to be reliable, but there can be no assurance as to the accuracy or completeness of such information. Although we believe that the third party sources are reliable, we have not independently verified any of the data from third-party sources, nor have we ascertained the underlying economic assumptions relied upon therein. In addition, while we believe that the market share, market position and other industry information included herein is generally reliable, such information is inherently imprecise. While we are not aware of any misstatements regarding our industry data presented herein, our estimates involve risks and uncertainties and are subject to change based on various factors, including those discussed under "Risk Factors."


PRESENTATION OF RESERVES INFORMATION

        The Securities and Exchange Commission (the "SEC") permits oil and gas companies, in their filings with the SEC, to disclose only estimated proved, probable and possible reserves that meet the SEC's definitions of such terms. We disclose estimated proved reserves in this prospectus. Our estimates of proved reserves contained in this prospectus were estimated by our internal staff of engineers and comply with the rules and definitions promulgated by the SEC. For the year ended December 31, 2012 and the six months ended June 30, 2013, we engaged Ryder Scott Company, L.P., an independent petroleum engineering consultant firm, to perform reserve audit services with respect to a substantial portion of our proved reserves.


EQUIVALENCY

        This prospectus presents certain production and reserves-related information on an "equivalency" basis. 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. These conversions are based on energy equivalency conversion methods primarily applicable at the burner tip and do not represent value equivalencies at the wellhead. Although these conversion factors are industry accepted norms, they are not reflective of price or market value differentials between product types.


USE OF NON-GAAP FINANCIAL INFORMATION

        In this prospectus, we use certain non-GAAP financial measures. We believe these supplemental measures provide meaningful information to our investors. Below are the non-GAAP measures used along with reference to where they are defined and reconciled with their comparable GAAP measures:

    EBITDAX—please see "Management's Discussion and Analysis of Financial Condition and Results of Operations—Supplemental Non-GAAP Measures;"

    Adjusted EBITDAX—please see "Management's Discussion and Analysis of Financial Condition and Results of Operations—Supplemental Non-GAAP Measures;"

    Pro Forma Adjusted EBITDAX—please see "Management's Discussion and Analysis of Financial Condition and Results of Operations—Supplemental Non-GAAP Measures;"

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    Cash Operating Costs—please see "Management's Discussion and Analysis of Financial Condition and Results of Operations—Results of Operations—Cash Operating Costs and Adjusted Cash Operating Costs;"

    Adjusted Cash Operating Costs—please see "Management's Discussion and Analysis of Financial Condition and Results of Operations—Results of Operations—Cash Operating Costs and Adjusted Cash Operating Costs;"

    Reserve Replacement Ratio—please see "Management's Discussion and Analysis of Financial Condition and Results of Operations—Reserve Replacement Ratio/Reserve Replacement Costs;"

    Reserve Replacement Costs—please see "Management's Discussion and Analysis of Financial Condition and Results of Operations—Reserve Replacement Ratio/Reserve Replacement Costs;" and

    PV-10—please see "Summary—Summary Operating and Reserve Information."

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SUMMARY

        This summary highlights information appearing elsewhere in this prospectus. This summary is not complete and does not contain all of the information that may be important to you. You should carefully read the entire prospectus, including the information presented under "Risk Factors" and the pro forma and historical financial statements and related notes included elsewhere in this prospectus. Certain oil and gas industry terms used in this prospectus are defined in the "Glossary of Oil and Natural Gas Terms" beginning on page A-1 of this prospectus.

        Except as otherwise indicated or unless the context otherwise requires, the terms "EP Energy," "we," "us," "our," "the Company" and "our company" refer to (i) EP Energy Corporation and its subsidiaries on a consolidated basis for periods following the completion of the Corporate Reorganization on August 30, 2013 and (ii) EPE Acquisition, LLC and its predecessor entities and their subsidiaries on a consolidated basis for periods prior to the Corporate Reorganization (including the operations of predecessor entities prior to the Acquisition (as defined below)).

        Except as otherwise indicated, all of the information in this prospectus assumes (i) no exercise of the underwriters' option to purchase up to                         additional shares of common stock from us, (ii) an initial offering price of $            per share, the midpoint of the range set forth on the cover page of this prospectus, and (iii) a        for one stock split will be effected as of the effective date of the registration statement of which this prospectus forms a part. The number of shares of common stock to be outstanding after completion of this offering is based on                        shares of our common stock to be sold by us in this offering and, except where indicated otherwise, does not give effect to                        shares of common stock reserved for future issuance under the Omnibus Incentive Plan (as defined in "Management—Executive Compensation").

        Estimates of our oil, natural gas and NGLs reserves, related future net cash flows and the present values thereof as of June 30, 2013 included in this prospectus were prepared by our internal staff of engineers and audited by the independent petroleum engineering firm of Ryder Scott Company, L.P. ("Ryder Scott").

        Unless we indicate otherwise, all production, reserve and operating data in this prospectus give effect to our pending and recently completed divestitures described in "—Recent Divestitures."


Our Company

        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 core areas: the Eagle Ford Shale (South Texas), the Wolfcamp Shale (Permian Basin in West Texas), the Uinta Basin (Utah) and the Haynesville Shale (North Louisiana). In our core areas, we have identified in excess of 5,200 drilling locations, of which approximately 96% are oil wells. At current activity levels, this represents approximately 24 years of drilling inventory. As of June 30, 2013, we had proved reserves of 501 MMBoe (57% oil and 66% liquids) and for the three months ended June 30, 2013, we had average net daily production of 93,674 Boe/d (37% oil and 46% liquids).

        Our management team has a proven track record of identifying, acquiring and developing unconventional oil and natural gas assets. The majority of our senior management team has worked together for over a decade and the team has significant experience at prominent oil and gas companies that have included El Paso Corporation, ConocoPhillips and Burlington Resources. We believe our management's experience in both acquiring resource-rich leasehold positions and efficiently developing those properties will enable us to generate attractive rates of return on our capital programs.

        Each of our core areas is characterized by a favorable operating environment, long-lived reserve base and high drilling success rates. We have established significant contiguous leasehold positions in

 

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each area, representing approximately 450,000 net (620,000 gross) acres in total. Beginning in 2012, our capital programs have focused predominantly on the Eagle Ford Shale, the Wolfcamp Shale and the Uinta Basin, three of the premier unconventional oil plays in the United States, resulting in oil reserve and production growth of 47% and 88%, respectively, from December 31, 2011 to December 31, 2012. In July and August 2013, we divested non-core domestic natural gas assets for a total consideration of approximately $1.3 billion. Additionally, in July 2013, we entered into a Quota Purchase Agreement relating to the sale of our Brazil operations, which is expected to close by the end of the first quarter of 2014. As a result of this strategic repositioning, we are a higher-growth, 100% onshore U.S., oil-weighted company with a large inventory of high-return, low-risk drilling locations. We intend to continue developing our oil-weighted assets, which offer the best rates of return in our portfolio in the current commodity price environment. In addition, our Haynesville Shale position is 100% held-by-production, which gives us the flexibility to allocate capital in the future to this natural gas-weighted asset.

        The following table provides a summary of oil, natural gas and NGLs reserve and production information for each of our areas of operation as of June 30, 2013. Our estimated proved reserves have been prepared by our internal reserve engineers and audited by Ryder Scott Company, L.P., our independent petroleum engineering consultants since 2004.

 
  Estimated Proved Reserves    
   
 
 
   
   
   
   
   
   
  PV-10(1)    
   
 
 
   
   
   
   
   
   
  Average
Net Daily
Production(2)
(MBoe/d)
   
 
 
  Oil
(MMBbls)
  NGL
(MMBbls)
  Natural Gas
(Bcf)
  Total
(MMBoe)
  Liquids
(%)
  Proved
Developed
(%)
  Value
($MM)
  % of Total
(%)
  R/P
(Years)(3)
 

Core Areas

                                                             

Eagle Ford Shale

    167.7     27.3     217.4     231.2     84 %   22 %   4,084     55 %   34.9     18.1  

Wolfcamp Shale

    43.4     8.6     58.3     61.7     84 %   22 %   711     10 %   4.4     38.6  

Uinta Basin

    71.9         148.4     96.6     74 %   35 %   1,765     24 %   11.4     23.2  

Haynesville Shale

            373.1     62.2     0 %   69 %   430     6 %   29.0     5.9  
                                                 

Total Core Areas

    283.1     35.8     797.2     451.7     71 %   31 %   6,991     95 %   79.7     15.5  

Other(4)

    2.0     1.0     71.7     14.9     20 %   83 %   135     2 %   5.3     7.7  
                                                 

Total Consolidated

    285.0     36.8     868.9     466.7     69 %   33 %   7,126     97 %   85.0     15.0  

Four Star

    2.1     6.2     155.9     34.3     24 %   93 %   260     3 %   8.7     10.8  
                                                 

Total Combined

    287.2     43.0     1,024.8     501.0     66 %   37 %   7,386     100 %   93.7     14.7  
                                                 

(1)
PV-10 is a non-GAAP measure and is derived from the standardized measure of discounted future net cash flows, which is the most directly comparable GAAP financial measure. To determine PV-10 we used SEC pricing, including the unweighted arithmetic average of the historical first-day-of-the-month prices for the prior 12 months, which were $91.60 per barrel of oil and $3.44 per MMBtu of natural gas as of June 30, 2013. Please see "—Summary Operating and Reserve Information."

(2)
Represents daily production for the three months ended June 30, 2013.

(3)
Calculated as total proved reserves divided by the annualized Average Net Daily Production for the three months ended June 30, 2013.

(4)
Comprised of South Louisiana Wilcox and Arklatex Tight Gas assets.


Operating Areas

Core Areas

        Eagle Ford Shale.    The Eagle Ford Shale, located in South Texas, is one of the premier unconventional oil plays in the United States, having produced over 750 MMBoe since 2008, including approximately 348 MMBoe in 2012. We were an early entrant into this play in late 2008, and since that time have acquired a leasehold position in the core of the oil window, primarily in La Salle and Atascosa counties. The Eagle Ford formation in La Salle county has up to 125 feet of net thickness (165 feet gross), which results in some of the most prolific acreage in the area. Due to its high carbonate content, the formation is also very brittle, and exhibits high productivity when fractured, with initial 30-day oil equivalent production rates up to 1,100 Boe/d. We currently have 97,689 net (105,416 gross) acres in the Eagle Ford, in which we have identified 983 drilling locations.

 

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        For the three months ended June 30, 2013, our average net daily production was 34,944 Boe/d, representing growth of 115% over the same period in 2012. As of June 30, 2013, we had five rigs running and plan to drill 126 wells in 2013 (of which 67 have been drilled through June 30, 2013), representing 58% of our total wells planned in 2013. For the six months ended June 30, 2013 our average cost per well was $7.5 million, representing an 11% decline from our average cost per well for the same period in 2012. We expect our average cost per well to continue to decline.

        Wolfcamp Shale.    The Wolfcamp Shale is located in the Permian Basin, which has produced more than 29 billion barrels of oil and 75 Tcf of gas over the past 90 years and is estimated by industry experts to contain remaining recoverable oil and natural gas reserves exceeding what has already been produced. With oil production of over 880 MBbls/d from over 80,000 wells during the six months ended June 30, 2013, the Permian Basin represented 51% of the crude oil produced in the State of Texas and approximately 17% of the crude oil and condensate produced onshore in the lower 48 United States. The basin is characterized by numerous, stacked oil reservoirs that provide excellent targets for horizontal drilling. We are currently targeting the Wolfcamp Shale in the Southern Midland Basin, where industry horizontal drilling has added over 50 MBoe/d to the basin's production since 2010.

        In 2009 and 2010, we leased 138,130 net (138,468 gross) acres on the University of Texas Land System in the Wolfcamp Shale, located primarily in Reagan, Crockett, Upton and Irion counties. Our large, contiguous acreage positions are characterized by stacked pay zones, including the Wolfcamp A, B, and C, which combine for over 750 feet of net (approximately 1,000 feet of gross) thickness. The Wolfcamp has high organic content and is composed of interbedded shale, silt, and fine-grained carbonate that respond favorably to fracture stimulation. Following our drilling results in 2012, we moved forward to full development of the Wolfcamp B, and began delineation of the Wolfcamp C. Our initial 30-day oil equivalent production rates are up to 600 Boe/d for the Wolfcamp B. As of June 30, 2013, we have identified 2,938 drilling locations in the Wolfcamp A, the Wolfcamp B and the Wolfcamp C across our acreage.

        The acreage is also prospective for the Cline Shale, which has approximately 100 feet of net (approximately 200 feet of gross) thickness, and potential vertical drilling locations in the Spraberry and other stacked formations.

        For the three months ended June 30, 2013, our average net daily production was 4,382 Boe/d, representing growth of 152% over the same period in 2012. As of June 30, 2013, we had three rigs running and plan to drill 65 wells in 2013 (of which 25 have been drilled through June 30, 2013), representing 30% of our total wells planned in 2013. For the six months ended June 30, 2013 our average cost per well was $5.9 million, representing a 24% decline from our average cost per well for the same period in 2012. Similar to the Eagle Ford Shale, we expect our average cost per well to continue to decline.

        Uinta Basin.    The Uinta Basin, located in northeastern Utah, has produced 577 MMbbls since its discovery in 1949 and is characterized by naturally fractured, tight oil sands with multiple zones. Our operations are primarily focused on developing the Altamont Field (including the Bluebell and Cedar Rim fields), which is the largest field in the basin. We own 172,293 net (318,568 gross) acres in Duchesne and Uinta Counties, making us the largest lease owner in the Altamont Field. Since their discovery, the Altamont, Bluebell and Cedar Rim fields have produced a combined total of over 300 MMBbls from the oil-rich Wasatch and Green River sandstones. With gross thicknesses over 4,300 feet across multiple sandstone and carbonate intervals, the Wasatch and Green River formations are ideal targets for low-risk, infill, vertical drilling and modern fracture stimulation techniques. The commingled production from over 1,500 feet of net stimulated rock results in initial 30-day oil production rates of up to 900 Boe/d. Our current activity is mainly focused on the development of our vertical inventory on 160-acre spacing. We have identified an inventory of 1,104 drilling locations (758 vertical and 346 horizontal). The industry is currently piloting 80-acre vertical downspacing programs in

 

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the Wasatch and Green River formations and horizontal development programs in the multiple shale and tight sand intervals. Due to the largely held-by-production nature of our acreage position, if these programs are successful, it will result in additional vertical and horizontal drilling opportunities that could be added to our inventory of drilling locations.

        For the three months ended June 30, 2013, our average net daily production was 11,433 Boe/d, representing growth of 14% over the same period in 2012. As of June 30, 2013, we had two rigs running and plan to drill 26 wells in 2013 (of which 13 have been drilled through June 30, 2013), representing 12% of our total wells planned in 2013. For the six months ended June 30, 2013 our average cost per well was $5.2 million, representing a 13% decline from our average cost per well for the same period in 2012.

        Haynesville Shale.    In addition to our key oil programs, we hold significant natural gas assets in the Haynesville Shale, located in East Texas and Northern Louisiana. Our operations are concentrated primarily in Desoto Parish, Louisiana in the Holly Field. This area is within the core of the Haynesville Shale with net thickness of 114 feet (210 feet gross), resulting in initial 30-day gas equivalent production rates up to 18 MMcfe/d. We currently have 40,029 net (59,210 gross) acres in this area. As of June 30, 2013, we have identified 190 drilling locations.

        For the three months ended June 30, 2013, our average net daily production was 174 MMcfe/d. As of June 30, 2013, we had 191 producing wells, which provide cash flow to fund the development of our core oil programs. We do not plan to drill any new wells in the Haynesville in 2013. Although we believe our wells generate attractive returns in the current natural gas price environment, we have chosen to allocate capital to our higher-return, oil-weighted areas. Our acreage in the Haynesville Shale is 100% held-by-production, giving us the flexibility to allocate capital in the future to this natural gas-weighted asset.

        The following table provides a summary of acreage and inventory data for our core areas as of June 30, 2013:

 
  Core Acreage and Inventory Summary as of June 30, 2013(1)  
 
  Acres    
  2013
Drilling
Locations(2)
(#)
   
   
 
 
  Drilling
Locations
(#)
  2010 - 2013
Drilling
Success Rate
  Inventory
Life
(Years)(3)
 
 
  Gross   Net  

Core Areas

                                     

Eagle Ford Shale

    105,416     97,689     983     126     100 %   7.8  

Wolfcamp Shale

    138,468     138,130     2,938     65     93 %   45.2  

Uinta Basin

    318,568     172,293     1,104     26     100 %   42.5  

Haynesville Shale

    59,210     40,029     190         100 %   NA  
                               

Total Core Areas

    621,662     448,141     5,215     217     99 %   24.0  
                               

(1)
For more information regarding our acreage and inventory data, see "Business—Our Properties and Core Areas."

(2)
Represents gross operated wells to be completed in 2013.

(3)
Calculated as Drilling Locations divided by 2013 Drilling Locations.

Other

        In addition to our core areas, we have other producing assets that contribute cash flow toward the development of our oil-focused core areas. These assets are comprised of our South Louisiana Wilcox assets, located primarily in Beauregard Parish, Louisiana, and our Arklatex Tight Gas assets located in Northern Louisiana that produce from reservoirs such as Travis Peak, Hosston, and Cotton Valley.

        We also have an approximate 49% equity interest in Four Star Oil & Gas Company ("Four Star"), an unconsolidated entity that operates primarily in the San Juan, Permian, Hugoton and South Alabama basins.

 

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Business Strategy

        We are a high-growth, 100% onshore U.S., oil-weighted company with a large inventory of high-return, low-risk drilling locations. We are focused on creating shareholder value by implementing the following strategies:

Grow Oil Production, Cash Flow and Reserves through the Development of our Extensive Drilling Inventory

        We have assembled a drilling inventory of over 5,200 drilling locations across approximately 450,000 net (620,000 gross) acres in the Eagle Ford Shale, the Wolfcamp Shale, the Uinta Basin and the Haynesville Shale. The concentration and scale of our core leasehold positions, coupled with our technical understanding of the reservoirs, should allow us to efficiently develop our core areas and allocate capital to maximize the value of our resource base. In 2012, we invested $1.5 billion (92% in our core oil areas) of capital expenditures and grew oil production by 11,511 Bbls/d, or 88%, from an average of 13,042 Bbls/d in 2011 to an average of 24,553 Bbls/d in 2012. Pro Forma Adjusted EBITDAX increased by 46% from 2011 to 2012. We also increased proved oil reserves by 82 MMBbls, or 47%, from 175 MMBbls at December 31, 2011 to 257 MMBbls at December 31, 2012. In 2013, we plan to invest approximately $1.9 billion of capital expenditures, of which 95% is dedicated to developing our core oil areas. For the six months ended June 30, 2013, our capital expenditures were $937 million. We believe that our extensive inventory of low-risk drilling locations, combined with our operating expertise, will enable us to continue to deliver production, cash flow and reserve growth and create shareholder value. We consider our inventory of drilling locations to be low risk because they are in areas where we (and other producers) have extensive drilling and production experience and success. For additional information regarding Adjusted EBITDAX, please read "Management's Discussion and Analysis of Financial Condition and Results of Operations—Supplemental Non-GAAP Measures."

Maintain an Extensive Low-Risk Drilling Inventory

        We have a demonstrated track record of identifying and cost effectively acquiring low-risk resource development opportunities. We follow a geologically driven strategy to establish large, contiguous leasehold positions in the core of prolific basins and opportunistically add to those positions through bolt-on acquisitions over time. We were an early entrant into the Eagle Ford and Wolfcamp Shales through grassroots leasing efforts, amassing average positions of over 100,000 net acres, and we methodically expanded our position in the Uinta Basin through targeted acquisitions. We will continue to identify and opportunistically acquire additional acreage and producing assets to add to our multi-year drilling inventory.

Enhance Returns by Continuously Improving Capital and Operating Efficiencies

        We maintain a disciplined, returns-focused approach to capital allocation. Our large and diverse portfolio of drilling locations allows us to conduct cost-efficient operations and allocate capital to our highest-margin assets in a variety of commodity price environments. We continuously monitor and adjust our development program in order to maximize the value of our extensive portfolio of drilling opportunities. In each of our core areas, we have realized improvements in EURs while delivering reductions in drilling and completion costs since 2011. We have reduced our average cost per well in the Wolfcamp by 40%, Eagle Ford by 24% and Uinta Basin by 22% from 2011 through the first half of 2013. These cost reductions have been due to many improvements, including substantial reductions in cycle times and successful negotiations for supplies and services. We expect further cost reductions going forward due to additional learning and efficiencies, including drilling wells from common pad sites, shared use of pre-existing central facilities and other economies of scale.

 

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Identify and Develop Additional Drilling Opportunities in our Portfolio

        Our existing asset base provides numerous opportunities for our highly experienced technical team to create shareholder value by increasing our inventory beyond our currently identified drilling locations. In the Permian Basin, we have evaluated multiple Wolfcamp horizons, and we are currently running pilot delineation programs in the Wolfcamp A and C horizons. Additionally, this acreage is prospective for the Cline Shale, the Spraberry and other stacked formations. The Uinta Basin has a significant inventory of low-risk, vertical infill drilling locations and is also currently being assessed for additional horizontal development potential in multiple shale and tight sands intervals. Our primary focus in the Eagle Ford Shale is increasing incremental returns through a reduction in drilling and completion costs. Our 3-D seismic programs in the Uinta and Permian Basins should further enhance our ability to increase the number of and high grade our drilling locations.

Maintain Liquidity and Financial Flexibility

        We intend to fund our organic growth predominantly with internally generated cash flows while maintaining ample liquidity. We will continue to maintain a disciplined approach to spending whereby we allocate capital in order to optimize returns and create shareholder value. Upon completion of this offering, we will have $2.5 billion available for borrowing under our reserve-based revolving credit facility (the "RBL Facility"). As we pursue our strategy of developing high-return opportunities in our core areas, we expect our cash flow and borrowing base to grow, thereby further enhancing our liquidity and financial strength. We protect these future cash flows and liquidity levels by maintaining a three year rolling hedge program. In general, we target hedging levels of over 50% of expected production on a rolling three year basis.


Competitive Strengths

        We believe the following strengths provide us with significant competitive advantages:

Large, Concentrated Operated Positions in the Core Areas of Prolific Oil Resource Plays

        We own and operate contiguous leasehold positions in the core areas of three of the premier North American oil resource plays: the Eagle Ford Shale, the Wolfcamp Shale and the Uinta Basin. We have approximately 410,000 net (560,000 gross) acres across these three plays that we have substantially de-risked through our ongoing drilling programs. Since 2010, we have drilled and completed 338 wells across these three plays with a success rate of approximately 99%. Based on our analysis of subsurface data and the production history of our wells and those of offset operators, we have confirmed high quality reservoir characteristics across a broad aerial extent with significant hydrocarbon resources in place. Based upon our well costs and production rates, we believe our core oil areas offer some of the best single well rates of return of all North American resource plays.

Multi-Year Inventory of Low-Risk Drilling Opportunities

        Our 5,215 low-risk drilling locations across our core areas as of June 30, 2013 provide us with approximately 24 years of drilling inventory, of which 96% are oil wells. We have used the subsurface data from our development programs to identify and prioritize our inventory. These drilling locations are included in our inventory after they have passed through a rigorous technical evaluation. In addition to our 5,215 identified drilling locations, we believe we have the potential to increase our multi-year drilling inventory with horizontal drilling locations in the Cline Shale and vertical drilling locations in the Spraberry and other stacked formations in the Permian Basin and vertical infill and horizontal drilling locations in the Wasatch and Green River formations in the Uinta Basin. Our ongoing technical assessment and development activities provide the potential for identification of additional drilling opportunities on our properties.

 

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High-Quality Proved Reserve Base with Substantial Current Production

        Our leasehold position and inventory of low-risk drilling locations is complemented by a substantial proved reserve base. As of June 30, 2013, we had proved reserves of 501 MMBoe (57% oil and 66% liquids) with a PV-10 of $7.4 billion (86% oil and 91% liquids). For the three months ended June 30, 2013, our average net daily production was 93,674 Boe/d, which was 37% oil and 46% liquids. Our current production provides a stable source of cash flow to fund the development of our core programs. This significantly reduces our reliance on outside sources of capital. In addition, our extensive inventory improves our ability to replace and grow proved reserves.

Significant Operational Control with Low Cost Operations

        Our significant operational control permits us to efficiently manage the amount and timing of our capital outflows, allowing us to continually improve our drilling and operating practices. We operate over 83% of our producing wells and have operational control of approximately 95% of our core area drilling inventory as of June 30, 2013. We employ a centralized operational structure to accelerate our internal knowledge transfer between our drilling and completion programs and to continually enhance our field operations and base production performance. We have decreased our average cost per well by 24%, 11% and 13% in the Wolfcamp Shale, Eagle Ford Shale and Uinta Basin, respectively, for the six months ended June 30, 2013, compared to our average cost per well for the same period in 2012.

Capital Allocation Flexibility and Scale across Multiple Basins

        Our existing assets are geographically diversified among many of the major basins of North America, which helps to insulate us from regional commodity pricing and cost dislocations that occur from time to time. While our existing producing assets are well diversified, they are also of a critical mass (on average over 100,000 net acres in each core area), which enables us to drive efficiencies and benefit from economies of scale across multiple basins. Furthermore, because of our centralized operational structure, we are able to quickly transfer operational efficiencies from one project to the next. From January 1, 2008 to June 30, 2013, we have drilled 386 horizontal shale wells. From this deep operational knowledge base and sizeable, concentrated positions in multiple basins, we have the flexibility to allocate significant amounts of capital across our properties in an efficient and value-maximizing manner.

Ability to Direct Capital to the Prolific Haynesville Shale

        The Haynesville Shale is a key asset for us and is likely to compete for development capital if natural gas prices improve. Because our operations are surrounded by existing infrastructure, future returns are primarily driven by drilling and completion costs and natural gas prices. Since our Haynesville wells have demonstrated high initial production rates and strong EURs, small movements in natural gas prices can drive significant incremental value creation. Since these leases are held-by-production, we have the ability to redirect capital to this prolific asset in the future.

Significant Liquidity and Financial Flexibility

        Upon completion of this offering, we will have $2.5 billion available for borrowing under our RBL Facility. We maintain a robust hedging program in order to protect our cash flows through commodity cycles. As of August 2, 2013, our hedged volumes for 2013, 2014, 2015 and 2016 represent 89%, 83%, 61% and 6%, respectively, based on our total equivalent production for the three months ended June 30, 2013. After the completion of this offering, we expect that liquidity provided by operating cash flow, availability under the RBL Facility and available cash will give us the financial flexibility to pursue our planned capital expenditures for the foreseeable future.

 

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Experienced Management Team with Proven Track Record

        With an average of 24 years of experience, our senior management team has a strong track record built at El Paso Corporation and in former leadership roles with Burlington Resources, ConocoPhillips and other leading energy companies. The majority of our senior management team has worked together for over a decade and has significant experience in identifying, acquiring and developing unconventional oil and natural gas assets, including experience in horizontal drilling and developing shales. Through a combination of invested equity and incentive programs, we believe our management is motivated to deliver high returns, create shareholder value and maintain safe and reliable operations.


2013 Capital Budget

        We have a projected 2013 capital program of approximately $1.9 billion. Our capital program will remain focused on continuing to grow production, cash flows, and reserves in our highest return oil programs. In particular, the Eagle Ford Shale currently generates the highest returns in our portfolio and, as a result we are investing the majority of our capital in this program. We expect that liquidity provided by operating cash flow, availability under the RBL Facility and available cash will be sufficient to fund the 2013 capital plan.

 
  2013 Capital Program    
   
  Six months ended
June 30, 2013
 
($ in Millions)
  Drilling &
Completion
  Facilities &
Other
  Total   % of
Total
  Active Rigs(2)   2013 Drilling
Locations(3)
  Capital
Expenditures
  Gross Wells
Drilled
 

Core Areas

                                                 

Eagle Ford Shale

  $ 897   $ 221   $ 1,118     58 %   5     126   $ 600     67  

Wolfcamp Shale

    447     54     501     26 %   3     65     236     25  

Uinta Basin

    137     58     195     10 %   2     26     94     13  

Haynesville Shale

        1     1     0 %           1      
                                   

Total Core Areas

  $ 1,481   $ 334   $ 1,815     95 %   10     217   $ 931     105  

Other(1)

    14     85     99     5 %       1     6      
                                   

Total

  $ 1,495   $ 419   $ 1,914     100 %   10     218   $ 937     105  
                                   

(1)
Consists of South Louisiana Wilcox, Arklatex Tight Gas and approximately $70 million of capitalized general and administrative, interest and other costs.

(2)
Active Rigs as of June 30, 2013.

(3)
Represents gross operated wells to be completed in 2013.

        In the beginning of the year, we projected a 2013 capital program of approximately $1.7 billion. Based on the results of the first half of the year and the results of our asset divestitures, we increased our 2013 capital program by up to $175 million for incremental drilling and completion activity. This incremental capital has added 36 wells to the original budget of 182 wells to be completed this year.


Recent Divestitures

        During the third quarter of 2013, we sold certain of our natural gas properties, including our CBM properties (Raton, Arkoma and Black Warrior Basin), the majority of our Arklatex natural gas properties and our natural gas properties in South Texas. The total consideration from these transactions was approximately $1.3 billion, and proceeds were used to repay outstanding borrowings under the RBL Facility and to fund capital expenditures.

        Additionally, in July 2013, certain of our subsidiaries entered into a Quota Purchase Agreement relating to the sale of all of our Brazil operations. Pursuant to the Quota Purchase Agreement, the subsidiaries have agreed to sell all of our equity interests in two Brazilian subsidiaries to a third party. The transaction is expected to close by the end of the first quarter of 2014, subject to Brazilian regulatory approval and certain other customary closing conditions.

 

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        As a result of these pending and completed divestitures, we are a higher-growth, 100% onshore U.S., oil-weighted company with a large inventory of high-return, low-risk drilling locations.


Risk Factors

        Investing in our common stock involves risks that include the speculative nature of oil and natural gas exploration, competition, volatile commodity prices and other material factors. For a discussion of these risks and other considerations that could negatively affect us, including risks related to this offering and our common stock, please read "Risk Factors" and "Cautionary Note Regarding Forward-Looking Statements."


Corporate History and Structure

        EP Energy Corporation, which was incorporated on August 8, 2013, is a holding company, and its sole asset is its direct and indirect ownership of EPE Acquisition, LLC ("EPE Acquisition") and EPE Acquisition's subsidiaries. On May 24, 2012, EPE Acquisition indirectly acquired all of the equity interests in various entities that collectively owned all of El Paso Corporation's exploration and production assets (the "Acquisition").

        Prior to our corporate reorganization (the "Corporate Reorganization") on August 30, 2013, affiliates of Apollo Global Management, LLC, Riverstone Holdings LLC, Access Industries and Korea National Oil Corporation (collectively, the "Sponsors"), other co-investors, members of our management team and certain of our employees directly and indirectly owned all of the Class A membership units and Class B membership units in EPE Acquisition. Class A membership units represented full value or capital interests and Class B membership units represented profits interests. Members of our management and certain employees held their Class B membership units through EPE Employee Holdings, LLC.

        As part of our Corporate Reorganization, through a series of contributions (i) all of the Class A membership units in EPE Acquisition were directly or indirectly exchanged for shares of common stock of EP Energy Corporation, which have substantially the same interests, rights and obligations as the Class A membership units and (ii) all of the Class B membership units in EPE Acquisition were exchanged for shares of Class B common stock of EP Energy Corporation, which have substantially the same interests, rights and obligations as the Class B membership units. We refer to (i) these direct and indirect holders of common stock and their permitted transferees as the "Legacy Class A Stockholders," (ii) the holder of the Class B common stock and its permitted transferees as the "Legacy Class B Stockholder" and (iii) the Legacy Class A Stockholders and the Legacy Class B Stockholder together as the "Legacy Stockholders." Please read "Corporate Reorganization."

 

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        The diagram below sets forth a simplified version of our organizational structure after giving effect to the Corporate Reorganization, our pending and completed divestitures and this offering. The diagram is provided for illustrative purposes only and does not represent all legal entities affiliated with us.

GRAPHIC


(1)
The Sponsors, the public stockholders and management will hold        %,        % and        % of                shares of common stock, respectively, if the underwriters exercise in full their option to purchase additional shares.

(2)
See "Description of Certain Indebtedness."

(3)
Co-Issuer of EP Energy LLC's senior secured notes and senior notes.

(4)
Guarantors of RBL Facility, senior secured term loans, senior secured notes and senior notes.

 

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Our Sponsors

        Apollo Global Management, LLC (together with its subsidiaries, "Apollo"), founded in 1990, is a leading global alternative investment manager with offices in New York, Los Angeles, Houston, London, Frankfurt, Luxembourg, Singapore, Mumbai and Hong Kong. As of June 30, 2013, Apollo had assets under management of approximately $113 billion in private equity, credit and real estate funds invested across a core group of nine industries, including natural resources, where Apollo has considerable knowledge and resources. Apollo's team of more than 250 seasoned investment professionals possesses a broad range of transactional, financial, managerial and investment skills, which has enabled the firm to deliver strong long-term investment performance throughout expansionary and recessionary economic cycles.

        Riverstone Holdings LLC (together with its affiliates, "Riverstone"), founded in 2000, is an energy and power-focused private equity firm with approximately $25 billion of equity capital raised across seven investment funds and co-investments. Riverstone conducts buyout and growth capital investments in the midstream, exploration & production, oilfield services, power and renewable sectors of the energy industry. With offices in New York, London and Houston, the firm has committed approximately $23.7 billion to 102 investments in North America, Latin America, Europe, Africa and Asia.

        Access Industries ("Access") is a privately held, U.S.-based industrial group with long-term holdings worldwide. Founded by industrialist Len Blavatnik, Access' focus spans three key sectors: natural resources and chemicals; telecommunications and media; and real estate. Access has offices in New York, London and Moscow.

        Korea National Oil Corporation ("KNOC") was incorporated in 1979 to engage in the development of oil fields, distribution of crude oil, maintenance of petroleum reserve stock and improvement of the petroleum distribution structure under the Korea National Oil Corporation Act. KNOC is wholly owned by the Korean government and located in Anyang, Gyeonggi-do in Korea. KNOC also has nine petroleum stockpile offices, one domestic gas field management office, 13 overseas offices in Vietnam and other countries and numerous overseas subsidiaries and affiliates in the United States and other countries.


Corporate Information

        Our principal executive offices are located at 1001 Louisiana Street, Houston, Texas 77002. Our telephone number is (713) 997-1000. Our website address is www.epenergy.com. We expect to make available our periodic reports and other information filed with or furnished to the SEC, free of charge through our website, as soon as reasonably practicable after those reports and other information are electronically filed with or furnished to the SEC. Information on our website or any other website is not incorporated by reference herein and does not constitute a part of this prospectus.

 

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The Offering

Issuer

  EP Energy Corporation

Common stock offered by us

 

            shares

Common stock to be outstanding immediately after the offering

 

            shares

Class B common stock to be outstanding immediately after the offering

 

            shares (see "Description of Capital Stock—Class B common stock").

Underwriters' option to purchase additional shares of common stock in this offering

 

We have granted to the underwriters a 30-day option to purchase up to            additional shares at the initial public offering price less underwriting discounts and commissions.

Common stock voting rights

 

Each share of our common stock will entitle its holder to one vote.

Dividend policy

 

We currently intend to retain all future earnings, if any, for use in the operation of our business and to fund future growth. The decision whether to pay dividends will be made by our board of directors (our "Board") in light of conditions then existing, including factors such as our financial condition, earnings, available cash, business opportunities, legal requirements, restrictions in our debt agreements and other contracts, including requirements under the Stockholders Agreement described elsewhere in this prospectus, and other factors our Board deems relevant. See "Dividend Policy."

Use of proceeds

 

We estimate that our net proceeds from this offering will be approximately $            million after deducting the estimated underwriting discounts and commissions and other expenses of $            million payable by us, assuming the shares are offered at $            per share, which represents the midpoint of the range set forth on the front cover of this prospectus. We intend to use the net proceeds (i) to redeem all of the outstanding 8.125%/8.875% Senior PIK Toggle Notes due 2017 issued by our subsidiaries, EPE Holdings LLC and EP Energy Bondco Inc., and pay the redemption premium and the accrued and unpaid interest on those notes, (ii) to repay outstanding borrowings under the RBL Facility, (iii) to pay an approximately $             million fee under the transaction fee agreement with certain affiliates of our Sponsors and (iv) for general corporate purposes. See "Use of Proceeds."

Listing

 

We intend to list our common stock on the New York Stock Exchange ("NYSE") under the trading symbol "EPE."

Risk factors

 

You should carefully read and consider the information set forth under "Risk Factors" beginning on page 19 of this prospectus and all other information set forth in this prospectus before deciding to invest in our common stock.

 

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Summary Historical and Pro Forma Consolidated Financial Data

        Set forth below is the summary historical consolidated financial data for the periods and as of the dates indicated for EPE Acquisition, LLC, the ultimate holding company prior to our Corporate Reorganization. Historical financial results of EPE Acquisition, LLC in this prospectus for the period before the Acquisition on May 24, 2012 are referred to as those of the predecessor and after the Acquisition are referred to as those of the successor in accordance with the required GAAP presentation. See "Management's Discussion and Analysis of Financial Condition and Results of Operations" and the historical consolidated financial statements and related notes appearing elsewhere in this prospectus.

        We have derived the summary historical consolidated balance sheet data as of December 31, 2012 (successor) and December 31, 2011 (predecessor), and the statements of income data and statements of cash flow data for the period from February 14, 2012 (inception) to December 31, 2012 (successor), the period from January 1, 2012 through May 24, 2012 (predecessor) and each of the two years in the period ended December 31, 2011 (predecessor), from the audited consolidated financial statements of EPE Acquisition, LLC appearing elsewhere in this prospectus. We have derived the summary historical consolidated balance sheet data as of December 31, 2010 from the audited consolidated financial statements not included herein of EP Energy Corporation, the predecessor of EPE Acquisition, LLC and referred to herein as Historical EP Energy Corporation. The summary unaudited historical consolidated financial data as of and for the six months ended June 30, 2013 have been derived from the unaudited consolidated financial statements of EPE Acquisition, LLC appearing elsewhere in this prospectus, which have been prepared on a basis consistent with the audited consolidated financial statements of EPE Acquisition, LLC. In the opinion of management, such unaudited financial data reflects all adjustments, consisting only of normal and recurring adjustments, necessary for a fair presentation of the results for such period. The results of operations for the interim periods are not necessarily indicative of the results to be expected for the full year or any future period.

        The table below also includes EP Energy Corporation's (issuer) unaudited pro forma condensed consolidated statement of income data, giving pro forma effect to the pending and recently completed divestitures, certain debt repayments, a distribution, the Corporate Reorganization, certain other adjustments in connection with the Acquisition and this offering, all as if they had occurred on January 1, 2012. The unaudited pro forma condensed consolidated balance sheet has been prepared as if these transactions had occurred on June 30, 2013. The pro forma adjustments are based upon available information and certain assumptions that we believe are reasonable. The summary unaudited pro forma condensed consolidated financial data are based upon available information and certain assumptions that management believes are factually supportable and that are reasonable under the circumstance. The pro forma financial data is provided for informational purposes only and do not purport to represent what our results of operations or financial position actually would have been if these transactions had occurred at any other date, and such data does not purport to project our results of operations for any future period.

        The following summary historical and pro forma financial data should be read in conjunction with the information included under the headings "—Recent Divestitures," "—Corporate History and Structure," "—The Offering," "Selected Historical Consolidated Financial Data," "Use of Proceeds," "Capitalization" and "Management's Discussion and Analysis of Financial Condition and Results of

 

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Operations" and the historical and pro forma consolidated financial statements and related notes included elsewhere in this prospectus.

 
   
   
   
   
   
   
   
   
 
 
  EP Energy
Corporation
Pro Forma
  EPE Acquisition, LLC
Historical
 
 
   
   
  Six months
ended
June 30,
(Successor)
  February 14
(inception) to
December 31,
(Successor)
   
   
   
   
 
 
  Six
months
ended
June 30,
2013
   
 




  January 1 to
May 24,
(Predecessor)
  Year ended
December 31,
(Predecessor)
 
 
  Year ended
December 31,
2012
 
 
  2013   2012    
  2012   2011   2010  
 
  (unaudited)
  (unaudited)
   
   
   
   
   
 

 


 

        (in millions)


 

Statement of income data

                                               

Operating revenues:

                                               

Oil and condensate

  $          $          $ 568   $ 555       $ 322   $ 552   $ 346  

Natural gas

                215     278         262     973     974  

NGL

                32     32         29     57     60  
                                   

Physical sales

                815     865         613     1,582     1,380  

Financial derivatives(1)

                35     (62 )       365     284     390  

Other

                                1     19  
                                   

Total operating revenues

                850     803         978     1,867     1,789  
                                   

Operating expenses:

                                               

Natural gas purchases

                10     19                  

Transportation costs

                46     51         45     85     73  

Lease operating expenses

                98     96         96     217     193  

General and administrative expenses

                118     371         75     201     190  

Depreciation, depletion and amortization            

                277     217         319     612     477  

Impairments/Ceiling test charges

                10     1         62     158     25  

Exploration expense

                27     50                  

Taxes, other than income taxes

                43     51         45     91     85  

Other

                                    15  
                                   

Total operating expenses

                629     856         642     1,364     1,058  
                                   

Operating income (loss)

                221     (53 )       336     503     731  

Income (loss) from unconsolidated affiliate(2)

                6     (1 )       (5 )   (7 )   (7 )

Other income (expense)

                (1 )   3         (3 )   (2 )   3  

Loss on extinguishment of debt

                (3 )   (14 )                

Interest expense, net of capitalized interest

                (178 )   (219 )       (14 )   (12 )   (21 )
                                   

Income (loss) from continuing operations before income taxes

                45     (284 )       314     482     706  

Income tax expense

                2     2         136     220     263  
                                   

Income (loss) from continuing operations            

                43   $ (286 )     $ 178   $ 262   $ 443  

Income from discontinued operations

                44     30                  
                                   

Net income (loss)

  $          $          $ 87   $ (256 )     $ 178   $ 262   $ 443  
                                   

Net income (loss) per common share—Basic and Diluted

                                               

Weighted Average common shares Outstanding—Basic and Diluted

                                               

Statement of cash flows data

                                               

Net cash provided by (used in):

                                               

Operating activities

              $ 450   $ 449       $ 580   $ 1,426   $ 1,067  

Investing activities

                (906 )   (7,893 )       (628 )   (1,237 )   (1,130 )

Financing activities

                670     7,513         110     (238 )   (46 )

Other financial data

                                               

Capital expenditures(3)

  $          $          $ 937   $ 941       $ 619   $ 1,644   $ 1,318  

Adjusted EBITDAX(4)

                574     782         533     1,391     1,205  

Pro forma Adjusted EBITDAX(4)

            563     751         458     832     505  

 

14


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  Pro Forma   Historical  
 
  EP Energy
Corporation
  EPE Acquisition, LLC   Historical EP
Energy
Corporation
 
 
   
   
  As of
June 30,
(Successor)
  As of
December 31,
(Successor)
   
  As of
December 31,
(Predecessor)
  As of
December 31,
(Predecessor)
 
 
   
   
   
 
 
  As of
June 30,
2013
  As of
December 31,
2012
 



 
 
  2013   2012   2011   2010  
 
  (in millions)
 

Balance sheet data

                                         

Cash and cash equivalents

  $                $ 283   $ 69       $ 25   $ 74  

Total assets

                9,181     8,306         5,099     4,942  

Total debt

                5,392     4,695         851     301  

Members'/stockholders' equity

                2,842     2,748         3,100     3,067  

(1)
Includes $5 million, $11 million and $11 million for the period from January 1 to May 24, 2012 and the years ended December 31, 2011 and 2010, respectively, reclassified from accumulated other comprehensive income associated with accounting hedges. No amount was reclassified for the period from February 14 (inception) to December 31, 2012 or thereafter.

(2)
Includes equity earnings from Four Star, our unconsolidated affiliate, net of amortization of the excess of our investment in Four Star over the underlying equity in its net assets.

(3)
Represent accrual based capital expenditures including acquisitions capital, and excludes asset retirement obligations.

(4)
Adjusted EBITDAX and Pro Forma Adjusted EBITDAX are non-GAAP measures and are not measurements of operating performance computed in accordance with GAAP and should not be considered as substitutes for operating income, income (loss) from continuing operations, net income or cash flows from operating activities computed in accordance with GAAP. These measures may not be comparable to similarly titled measures of other companies. See "Management's Discussion and Analysis of Financial Condition and Results of Operations—Supplemental Non-GAAP Measures."

 

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        The following table provides an unaudited reconciliation of income (loss) from continuing operations to Adjusted EBITDAX and Pro Forma Adjusted EBITDAX:

 
  EP Energy
Corporation
Pro Forma
  EPE Acquisition, LLC
Historical
 
 
   
   
  Six months
ended
June 30,
(Successor)
  February 14
(inception) to
December 31,
(Successor)
   
   
   
   
 
 
  Six
months
ended
June 30,
2013
   
   
  January 1 to
May 24,
(Predecessor)
  Years ended
December 31,
(Predecessor)
 
 
   
 


 
 
  Year ended
December 31,
2012
 
 
  2013   2012    
  2012   2011   2010  
 
  (in millions)
 
 
   
   
   
   
   
   
   
   
 

Income (loss) from continuing operations

  $     $       43   $ (286 )     $ 178   $ 262   $ 443  

Income tax expense

                2     2         136     220     263  

Interest expense, net of capitalized interest

                178     219         14     12     21  

Depreciation, depletion and amortization

                277     217         319     612     477  

Exploration expense

                27     50                  
                                   

EBITDAX

                527     202         647     1,106     1,204  

Net impact of financial derivatives(a)

                (12 )   285         (200 )   47     (99 )

Impairments and ceiling test charges

                10     1         62     158     25  

Transition and restructuring costs(b)

                8     215         5     6      

Dividends from unconsolidated affiliate(c)

                17     13         8     46     50  

(Income) loss from unconsolidated affiliate(d)

                (6 )   1         5     7     7  

Non-cash compensation expense(e)

                14     35         6     21     18  

Management fee(f)

                13     16                  

Loss on extinguishment of debt(g)

                3     14                  
                                   

Adjusted EBITDAX

                574     782         533     1,391     1,205  
                                   

Less: Adjusted EBITDAX—divested assets(h)

                11     31         75     559     700  
                                   

Pro Forma Adjusted EBITDAX

  $     $     $ 563   $ 751       $ 458   $ 832   $ 505  
                                   

(a)
Represents the non-cash net change in the fair value of derivatives, net of actual cash settlements received/(paid) related to these derivatives, including any related cash premiums.

(b)
Reflects the transaction costs paid as part of the Acquisition in 2012 and non-recurring severance costs incurred in connection with divested assets in 2013 and the closure of our office in Denver in 2011.

(c)
Represents cash dividends received from Four Star, our unconsolidated affiliate in which we hold an approximate 49% equity interest.

(d)
Reflects the elimination of non-cash equity income (losses) recognized from Four Star, net of amortization of our purchase cost in excess of our equity interest in the underlying net assets.

(e)
Represents the non-cash portion of compensation expense.

(f)
Represents the pro-rata portion of the annual management fee to be paid to affiliates of the Sponsors and other investors. The annual management fee of $25 million will terminate in connection with the closing of this offering.

(g)
Represents the loss on extinguishment of debt recorded related to re-pricing of the term loan and redetermination of the RBL Facility.

(h)
Consists of Adjusted EBITDAX contributions related to assets that have been or are in the process of being divested, including our (i) Brazil operations, (ii) CBM, South Texas and Arklatex assets, (iii) Gulf of Mexico assets, (iv) Blue Creek West, Minden and Powder River operations and (v) Catapult operations and Altamont processing plant and related gathering systems.

 

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Summary Pro Forma Operating and Reserve Information

Proved Reserves

        The following table summarizes our estimated net proved reserves and related PV-10 as of June 30, 2013, after giving effect to our pending and recently completed divestitures described in "—Recent Divestitures." The proved reserves as of June 30, 2013 are based on our internal reserve report. The reserve data represents only estimates, which are often different from the quantities of oil and natural gas that are ultimately recovered. The risks and uncertainties associated with estimating proved oil and natural gas reserves are discussed further in "Risk Factors." Net proved reserves exclude royalties and interests owned by others and reflect contractual arrangements and royalty obligations in effect at June 30, 2013. You should refer to "Risk Factors," "Management's Discussion and Analysis of Financial Condition and Results of Operations" and "Business" in evaluating the material presented below. The information in the following table does not give any effect to or reflect our commodity hedges.

        Ryder Scott conducted an audit of the estimates of the proved reserves that we prepared as of June 30, 2013 and concluded that the overall procedures and methodologies we utilized in preparing these estimates complied with current SEC regulations and the overall proved reserves for the reviewed properties as estimated by us are, in aggregate, reasonable within the established audit tolerance guidelines of 10% as set forth in the Society of Petroleum Engineers ("SPE") auditing standards.

 
  Pro Forma
as of
June 30, 2013
 

Proved reserves(1):

       

Natural gas (MMcf)

    1,024,768  

Oil/Condensate (MBbls)

    287,194  

NGLs (MBbls)

    42,972  

Total estimated net proved reserves (MBoe)

    500,960  

Proved developed producing (MBoe)

    167,425  

Proved developed non-producing (MBoe)

    18,752  

Proved undeveloped (MBoe)

    314,784  

Percent proved developed reserves (%)

    37%  

PV-10 (in millions)(2)

  $ 7,386  

(1)
Includes our approximate 49% equity interest in Four Star. Net proved reserves represented by our approximate 49% interest in Four Star as of June 30, 2013 were 34.3 MMBoe, consisting of 2.1 MMBbls of oil, 6.2 MMBbls of NGLs and 155.9 Bcf of natural gas.

(2)
PV-10 is a non-GAAP measure and is derived from the standardized measure of discounted future net cash flows, which is the most directly comparable GAAP financial measure. Our PV-10 differs from our standardized measure because our standardized measure reflects discounted future income taxes related to our investment in Four Star. For our domestic operations we were not subject to federal income taxes as of June 30, 2013. We believe that the presentation of PV-10 is relevant and useful to investors because it presents the relative monetary significance of our oil, natural gas and NGLs properties regardless of tax structure. Further, investors may utilize the measure as a basis for comparison of the relative size and value of our reserves to other companies. We use this measure when assessing the potential return on investment related to our oil, natural gas and NGLs properties. PV-10, however, is not a substitute for the standardized measure of discounted future net cash flows. Our PV-10 measure and the standardized measure of discounted future net cash flows do not purport to present the fair value of our oil (including NGLs) and natural gas reserves. The unweighted arithmetic average of the historical first-day-of-the-month prices for the prior 12 months was $91.60 per barrel of oil and $3.44 per MMBtu of natural gas as of June 30, 2013.

 

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        The following table provides a reconciliation of PV-10 to the standardized measure of discounted future net cash flows (in millions):

 
  Pro Forma
as of
June 30, 2013
 

PV-10

  $ 7,386  

Income taxes, discounted at 10%

    (99 )
       

Standardized measure of discounted future net cash flows

  $ 7,287  
       

Production, Revenues and Price History

        The following table sets forth information regarding net production and certain price and cost information for each of the periods indicated.

 
  Six months
ended June 30,
2013
  Year ended
December 31,
2012
  Year ended
December 31,
2011
 

Production data(1):

                   

Oil/Condensate (MBbls)

    6,015     8,986     4,760  

Natural gas (MMcf)

    57,179     150,409     136,750  

NGLs (MBbls)

    1,327     1,779     794  

Combined production (MBoe)

    16,873     35,833     28,345  

Average combined daily production (MBoe/d)

    93.2     97.9     77.7  

Average realized prices on physical sales(2):

                   

Oil (Bbl)

  $ 94.81   $ 92.02   $ 88.36  

Natural gas (Mcf)

    3.42     2.57     3.82  

NGLs (Bbl)

    28.68     36.93     52.39  

Average realized prices, including financial derivative settlements(2)(3):

                   

Oil (Bbl)

  $ 101.39   $ 97.61   $ 86.78  

Natural gas (Mcf)

    3.12     5.08     6.64  

NGLs (Bbl)

    28.68     36.93     52.39  

Average cash operating cost per Boe(4):

                   

Lease operating expenses

  $ 5.11   $ 3.49   $ 3.29  

Production taxes(5)

    3.01     2.04     1.38  

General and administrative expenses

    7.36     13.04     6.29  

Taxes other than production and income taxes

    (0.56 )   (0.10 )   0.20  
               

Total

  $ 14.92   $ 18.47   $ 11.16  
               

Depreciation, depletion and amortization

  $ 17.73   $ 12.25   $ 12.93  

(1)
Includes the production amounts represented by our approximate 49% equity interest in Four Star. Specifically, production amounts represented by our approximate 49% equity interest in Four Star (i) as of December 31, 2012 were 282 MBbls oil and condensate, 15,552 MMcf natural gas, 478 MBbls NGLs, 3,352 MBoe combined production and 9.2 MBoe/d average combined daily production and (ii) as of June 30, 2013 were 136 MBbls oil and condensate, 7,317 MMcf natural gas, 229 MBbls NGLs, 1,585 MBoe combined production and 8.8 MBoe/d.

(2)
Average prices shown in the table do not include Four Star production.

(3)
Amounts reflect settlements on derivative instruments, including cash premiums.

(4)
Total adjusted cash operating costs per unit for each period were $12.63/Boe, $9.94/Boe and $10.10/Boe. Adjusted cash operating cost is a non-GAAP measure. See "Management's Discussion and Analysis of Financial Condition and Results of Operations—Results of Operations—Year-to-Date Period Ended June 30, 2013 to Year-to-Date Period Ended June 30, 2012—Operating Expenses—Cash Operating Costs and Adjusted Cash Operating Costs" for a reconciliation of this measure to operating expenses, the most directly comparable GAAP measure.

(5)
Production taxes include ad valorem and severance taxes.

 

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RISK FACTORS

        Investing in our common stock involves a high degree of risk. You should carefully consider the risks and uncertainties described below, as well as other information contained in this prospectus, before investing in our common stock. If any of the following risks actually occur, our business, financial condition, operating results or cash flow could be materially and adversely affected. Additional risks and uncertainties not presently known to us or not believed by us to be material may also negatively impact us.

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 other factors outside of our control, including:

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

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

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

    adoption of various energy efficiency and conservation measures;

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

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

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

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

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

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

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

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

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

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

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

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

    natural gas inventory levels in the United States;

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

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

    volatile trading patterns in capital and commodity-futures markets;

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

    weather conditions;

    technological advances affecting energy consumption and energy supply;

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

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

    the price and availability of supplies of alternative energy sources;

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

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

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

        In addition to negatively impacting our cash flows, prolonged or substantial declines in commodity prices could negatively impact our proved oil and natural gas reserves and impact the amount of oil and natural gas production 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 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

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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.

        In addition, we have certain areas in which we have incurred material costs to explore for and develop reserves. These unproved property costs include non-producing leasehold, geological and geophysical costs associated with unevaluated leasehold or drilling interests, and exploration drilling costs in investments in unproved properties and major development projects in which we own a direct interest. If costs are determined to be impaired, we record in our income statement the amount of any impairment.

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

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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.

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 due to 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

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

        In addition, our commodity derivative activities could have the effect of reducing our revenue and net income. As of June 30, 2013, the net unrealized asset represented by our commodity hedging contracts was $186 million. We may continue to incur significant unrealized gains or losses in the future from our commodity derivative activities to the extent market prices increase or decrease and our hedging arrangements remain in place.

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 still ongoing, and we cannot yet predict the ultimate effect of the rules and regulations on our business.

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

        A rule adopted under the Dodd-Frank Act imposing position limits in respect of transactions involving certain commodities, including oil and natural gas was vacated and remanded to the CFTC for further proceedings by order of the United States District Court for the District of Columbia, U.S. District Judge Robert L. Wilkins on September 28, 2012. Although the CFTC is appealing that decision and, if unsuccessful, is likely to adopt a new rule, we cannot predict whether or when such a rule will be adopted or the effect of such a rule on our business. The Dodd-Frank Act and the rules promulgated thereunder could significantly increase the cost of derivative contracts (including through requirements to post collateral), materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks we encounter, reduce our ability to monetize or restructure our existing derivative contracts, and increase our exposure to less creditworthy counterparties. Finally, the Dodd-Frank Act was intended, in part, to reduce the volatility of oil and natural gas prices, which some legislators attributed to speculative trading in derivatives and commodity contracts related to oil and natural gas. Our revenues could therefore be adversely affected if a consequence of the Dodd-Frank Act and regulations is to lower commodity prices. Any of these consequences could have a material and adverse effect on our business, financial condition and results of operations.

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

        We require substantial capital expenditures to conduct our exploration, development and production operations, engage in acquisition activities and increase our proved reserves and production. We have established a capital budget for 2013 of approximately $1.9 billion and we intend to rely on cash flow from operating activities, available cash and borrowings under the RBL Facility as our primary sources of liquidity. We also may engage in asset sale transactions such as the pending and recently completed divestitures to, among other things, fund capital expenditures when market conditions permit us to complete transactions on terms we find acceptable. There can be no assurance that such sources will be sufficient to fund our exploration, development and acquisition activities. If our revenues and cash flows decrease in the future as a result of a decline in commodity prices or a reduction in production levels, however, and we are unable to obtain additional equity or debt financing in the capital markets or access alternative sources of funds, we may be required to reduce the level of our capital expenditures and may lack the capital necessary to increase or even maintain our reserves and production levels.

        Our future revenues, cash flows and spending levels are subject to a number of factors, including commodity prices, the level of production from existing wells and our success in developing and producing new wells. Further, our ability to access funds under the RBL Facility is based on a borrowing base, which is subject to periodic redeterminations based on our proved reserves and prices 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 equity and debt markets and complete future asset monetization transactions is also dependent upon oil, natural gas and NGLs prices, in addition to a number of other

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factors, some of which are outside our control. These factors include, among others, domestic and global economic conditions and conditions in the domestic and global financial markets.

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

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

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

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

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

        A portion of our proved reserves are undeveloped. Recovery of undeveloped reserves requires significant capital expenditures and successful drilling operations. In addition, because our proved

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

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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. Our offshore operations in Brazil which are in the process of being divested may encounter additional marine perils, including adverse weather conditions, damage from collisions with vessels, and governmental regulations (including interruption or termination of drilling rights by governmental authorities based on environmental, safety and other considerations).

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

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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.

        Some of our operations and interests are subject to joint ventures or are operated by other companies, including our approximate 49% equity interest in Four Star. Although we operate the substantial majority of the properties in our business, certain of our properties are operated by joint venture partners or other third-party working interest owners. In certain cases, (i) we have limited ability to influence or control the day-to-day operation of such properties, including compliance with environmental, safety and other regulations, (ii) we cannot control the amount of capital expenditures that we are required to fund with respect to properties, (iii) we are dependent on third parties to fund their required share of capital expenditures and (iv) we may have restrictions or limitations on our ability to sell our interests in these jointly owned assets.

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

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

        For the six months ended June 30, 2013, three purchasers accounted for more than 74% 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;

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    plugging and abandoning of wells;

    air quality, noise levels and related permits;

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

    taxation; and

    competitive bidding rules on federal and state lands.

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

        Also, some of our assets are located and operate on federal, state, local or tribal lands and are typically regulated by one or more federal, state or local agencies. For example, we have drilling and production operations that are located on federal lands, which are regulated by the U.S. Department of the Interior ("DOI"), particularly by the Bureau of Land Management. 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

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explore or analyze our prospects to determine a method in which the prospects may be developed in a cost-effective manner. There is a risk that such contractors and suppliers may experience credit and performance issues that could adversely impact their ability to perform their contractual obligations with us, including their performance and warranty obligations. This could result in delays or defaults in performing such contractual obligations and increased costs to seek replacement contractors, each of which could negatively impact us.

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

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

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

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

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

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

        Many of our operations involve utilizing the latest horizontal drilling and completion techniques in order to maximize cumulative recoveries and therefore optimize our returns. Drilling risks that we face 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

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

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

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

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

        The oil and natural gas industry is subject to rapid and significant advancements in technology, including the introduction of 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.

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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, some local water districts have begun restricting the use of water subject to their jurisdiction for hydraulic fracturing to protect local water supply. If we are unable to obtain water to use in our operations from local sources, we may be unable to economically produce our reserves, which could have an adverse effect on our financial condition, results of operations and cash flows.

We may face unanticipated water and other waste disposal costs.

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

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

    we cannot obtain future permits from applicable regulatory agencies;

    water of lesser quality or requiring additional treatment is produced;

    our wells produce excess water;

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

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

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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 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 and have a material adverse effect on our business, results of operations and financial condition.

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

        Although most of our reserves are located on leases that are held-by-production or held by continuous development, we do have provisions in many of our leases that provide for the lease to expire unless certain conditions are met, such as drilling having commenced on the lease or production in paying quantities having been obtained within a defined time period. If commodity prices remain low or we are unable to fund our anticipated capital program there is a risk that some of our existing

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proved reserves and some of our unproved inventory could be subject to lease expiration or a requirement to incur additional leasehold costs to extend the lease. This could result in a reduction in our reserves and our growth opportunities (or the incurrence of significant costs) and therefore could have a material adverse effect on our financial results.

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

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

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

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 Department of the Interior ("DOI"), the Bureau of Indian Affairs ("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

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penalties, the imposition of remedial obligations, the imposition of stricter conditions on or revocation of permits, the issuance of injunctions limiting or preventing some or all of our operations, delays in granting permits and cancellation of leases. Our exploration and production operations in Brazil (which we expect to be sold by the end of the first quarter of 2014) are subject to various types of regulations similar to those described above, which are imposed by the Brazilian government, and which may affect our operations and costs within that country. Liabilities, penalties, suspensions, terminations and increased costs resulting from any failure to comply with regulations and requirements of the type described above, or from the enactment of additional similar regulations or requirements in the future or a change in the interpretation or the enforcement of existing regulations or requirements of this type, could have a material adverse effect on our business, results of operations and financial condition.

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

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

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

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

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

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

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

        Partially as a result of an explosion on an offshore platform of a third party in 2010 and subsequent release of oil into the Gulf of Mexico, there have been various regulations proposed and implemented that could materially impact the costs of exploration and production operations, as well as cause substantial delays in the receipt of regulatory approvals from both an environmental and safety perspective in the Gulf of Mexico. Although we have sold our Gulf of Mexico assets, it is also possible that similar, more stringent, regulations might be enacted or delays in receiving permits may occur in other areas, such as in offshore regions of other countries (such as Brazil) and in other onshore regions of the United States (including drilling operations on other federal or state lands).

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

        Despite the existence of various procedures and plans, there is a risk that we could experience well control problems in our operations. As a result, we could be exposed to regulatory fines and penalties,

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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 propose federal Clean Water Act regulations by 2014 governing wastewater discharges from hydraulic fracturing and certain other natural gas operations. In addition, the DOI published a revised proposed rule on May 16, 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 is presently subject to an extended 90-day public comment period, which ended on August 23, 2013.

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

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        On August 16, 2012, the EPA published final regulations under the Clean Air Act ("CAA") that establish new air emission controls for oil and natural gas production and natural gas processing operations. Specifically, EPA promulgated New Source Performance Standards establishing emission limits for sulfur dioxide (SO2) and volatile organic compounds (VOCs). The final rule requires a 95% reduction in VOCs emitted by mandating the use of reduced emission completions or "green completions" on all hydraulically-fractured gas wells constructed or refractured after January 1, 2015. Until this date, emissions from fractured and refractured gas wells must be reduced through reduced emission completions or combustion devices. The rules also establish new requirements regarding emissions from compressors, controllers, dehydrators, storage tanks and other production equipment. In response to numerous requests for reconsideration of these rules from both industry and the environmental community and court challenges to the final rules, EPA announced its intention to issue revised rules in 2013. The EPA revised portions of these rules on August 2, 2013 (awaiting Federal Register publication) for VOCs emissions for production oil and gas storage tanks, in part phasing in emissions controls on storage tanks past October 15, 2013. The final revised rules could require modifications to our operations or increase our capital and operating costs without being offset by increased product capture. At this point, we cannot predict the final regulatory requirements or the cost to comply with such requirements with any certainty.

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

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consequences of any failure to comply by us could have a material adverse effect on our financial condition and results of operations. Until such regulations are finalized and implemented, it is not possible to estimate their impact on our business. At this time, no adopted regulations have imposed a material impact on our hydraulic fracturing operations.

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

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.

Our Brazilian operations involve special risks.

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

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

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

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

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

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

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

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

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

We have certain contingent liabilities that could exceed our estimates.

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

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

Our substantial indebtedness could adversely affect our ability to raise additional capital to fund our operations, limit our ability to react to changes in the economy or our industry and prevent us from making debt service payments.

        We are a highly leveraged company. As of June 30, 2013, after giving effect to our pending and recently completed divestitures and repayment of certain debt obligations, we had approximately $4.1 billion of outstanding indebtedness, and for the six months ended June 30, 2013, after giving effect to our pending and recently completed divestitures and repayment of certain debt obligations, we had total debt service payment obligations of $154 million.

        Our substantial indebtedness could have important consequences for you. For example, it could:

    limit our ability to borrow money for our working capital, capital expenditures, debt service requirements, strategic initiatives or other purposes;

    make it more difficult for us to satisfy our obligations with respect to our indebtedness, and any failure to comply with the obligations of any of our debt instruments, including restrictive covenants and borrowing conditions, could result in an event of default under the agreements governing our indebtedness;

    require us to dedicate a substantial portion of our cash flow from operations to the repayment of our indebtedness, thereby reducing funds available to us for other purposes;

    limit our flexibility in planning for, or reacting to, changes in our operations or business;

    make us more highly leveraged than some of our competitors, which may place us at a competitive disadvantage;

    make us more vulnerable to downturns in our business or the economy;

    restrict us from making strategic acquisitions, engaging in development activities, introducing new technologies or exploiting business opportunities;

    cause us to make non-strategic divestitures;

    limit, along with the financial and other restrictive covenants in our indebtedness, among other things, our ability to borrow additional funds or dispose of assets; or

    expose us to the risk of increased interest rates, as certain of our borrowings, including borrowings under the RBL Facility and our senior secured term loan, are at variable rates of interest.

In addition, the agreements governing our indebtedness contain restrictive covenants that limit our ability to engage in activities that may be in our long-term best interest. Our failure to comply with those covenants could result in an event of default which, if not cured or waived, could result in the acceleration of substantially all of our indebtedness.

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Despite our substantial indebtedness, we may still be able to incur significantly more debt, which could intensify the risks described above.

        We and our subsidiaries may be able to incur substantial indebtedness in the future. Although the terms of the agreements governing our indebtedness contain restrictions on our ability to incur additional indebtedness, these restrictions are subject to a number of important qualifications and exceptions, and the indebtedness incurred in compliance with these restrictions could be substantial. These restrictions also will not prevent us from incurring obligations that do not constitute indebtedness. After completion of this offering, we will have $2.5 billion available for borrowing under the RBL Facility, all of which would be secured. In addition, the covenants under any other existing or future debt instruments could allow us to incur a significant amount of additional indebtedness. The more leveraged we become, the more we, and in turn our investors, will be exposed to certain risks described above under "—Our substantial indebtedness could adversely affect our ability to raise additional capital to fund our operations, limit our ability to react to changes in the economy or our industry and prevent us from making debt service payments."

We may not be able to generate sufficient cash to service all of our indebtedness and may be forced to take other actions to satisfy our obligations under our indebtedness that may not be successful.

        Our ability to pay principal and interest on our debt obligations will depend upon, among other things:

    our future financial and operating performance, which will be affected by prevailing economic, industry and competitive conditions and financial, business, legislative, regulatory and other factors, many of which are beyond our control; and

    our future ability to borrow under the RBL Facility, which depends on, among other things, our compliance with the covenants in the credit agreement governing such facility.

        We cannot assure you that our business will generate cash flow from operations, or that we will be able to draw under the RBL Facility or otherwise, in an amount sufficient to fund our liquidity needs, including the payment of principal and interest on our debt obligations.

        If our cash flows and capital resources are insufficient to service our indebtedness, we may be forced to reduce or delay capital expenditures, sell assets, seek additional capital or restructure or refinance our indebtedness. These alternative measures may not be successful and may not permit us to meet our scheduled debt service obligations. Our ability to restructure or refinance our debt will depend on the condition of the capital markets and our financial condition at such time. Any refinancing of our debt could be at higher interest rates and may require us to comply with more onerous covenants, which could further restrict our business operations. In addition, the terms of existing or future debt agreements may restrict us from adopting some of these alternatives. If we are required to dispose of material assets or operations to meet our debt service and other obligations, we may not be able to consummate those dispositions for fair market value or at all. Furthermore, any proceeds that we could realize from any such dispositions may not be adequate to meet our debt service obligations then due. The Sponsors and their affiliates have no continuing obligation to provide us with debt or equity financing. Our inability to generate sufficient cash flow to satisfy our debt obligations, or to refinance our indebtedness on commercially reasonable terms or at all, could result in a material adverse effect on our business, results of operations and financial condition and could negatively impact our ability to satisfy our obligations under our indebtedness, which in turn could negatively impact your investment in our common stock.

        If we cannot make scheduled payments on our indebtedness, we will be in default and lenders could declare all outstanding principal and interest to be due and payable, terminate their commitments to loan money, foreclose against the assets securing their indebtedness and we could be

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forced into bankruptcy or liquidation. All of these events could cause you to lose all or part of your investment in our common stock.

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 significant 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 "Description of Certain Indebtedness—The RBL Facility."

        As a result of these covenants, we will 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.

        If any of our outstanding indebtedness under the RBL Facility or our other indebtedness were to be accelerated, there can be no assurance that our assets would be sufficient to repay such indebtedness in full. See "Description of Certain Indebtedness."

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Risks Related to This Offering and Our Common Stock

There is no existing market for our common stock, and we do not know if an active trading market will develop, which could impede your ability to sell your shares and may depress the market price of our common stock.

        There has not been a public market for our common stock prior to this offering. We cannot predict the extent to which investor interest in us will lead to the development of an active trading market or how liquid that market might become. If an active trading market does not develop, you may have difficulty selling any of our common stock that you buy. The initial public offering price for the common stock will be determined by negotiations between us and the underwriters and may not be indicative of prices that will prevail in the open market following this offering. See "Underwriting." Consequently, you may be unable to sell our common stock at prices equal to or greater than the price you pay in this offering.

The interests of our Sponsors may conflict with or differ from your interests as a stockholder.

        After the consummation of this offering, our Sponsors, as a group, will collectively own approximately        % of our common stock, assuming the underwriters do not exercise their option to purchase additional shares, or        % if the underwriters exercise their option in full. As a result, subject to the rights of the other Legacy Class A Stockholders contained in the Stockholders Agreement described in this prospectus, our Sponsors will continue to control all matters affecting us, including decisions regarding extraordinary business transactions, fundamental corporate transactions, appointment of members to our management, election of directors and our corporate and management policies. This concentration of ownership makes it unlikely that any other holder or group of holders of our common stock will be able to affect the way we are managed or the direction of our business. The interests of our Sponsors with respect to matters potentially or actually involving or affecting us, such as future acquisitions, financings and other corporate opportunities and attempts to acquire us, could conflict with your interests as a holder of our common stock. For example, the concentration of ownership held by our Sponsors could delay, defer or prevent a change of control of us or impede a merger, takeover or other business combination that you as a stockholder may otherwise view favorably. Further, a sale of a substantial number of shares of stock in the future by our Sponsors could cause our stock price to decline.

        In addition, the Stockholders Agreement that we have entered into with the Sponsors and the other Legacy Class A Stockholders provides that, except as otherwise required by applicable law, the Sponsors will have certain rights with respect to the designation of directors to serve on our Board. See "Certain Relationships and Related Party Transactions—Stockholders Agreement—Composition of the Board." In addition, the Stockholders Agreement provides that for so long as each Sponsor has the right to designate a director or an observer to the Board, we will cause any committee of our Board to include in its membership such number of members that are consistent with, and reflects, the right of each Sponsor to designate a director or observer to the Board, except to the extent that such membership would violate applicable securities laws or stock exchange or stock market rules. See "Certain Relationships and Related Party Transactions."

        Furthermore, the Sponsors and their respective affiliates either operate businesses, or may from time to time acquire businesses, that compete directly or indirectly with us, as well as businesses that represent major customers of our business, or are in the business of making investments, or managing funds that make investments, in companies and one or more of them may from time to time acquire and hold interests, or manage funds that acquire and hold interests, in businesses that compete directly or indirectly with us, as well as businesses that represent major customers of our business. The Sponsors and their affiliates, including funds managed by certain of the Sponsors and their respective affiliates, may also pursue acquisition opportunities that may be complementary to our business and, as a result, those acquisition opportunities may not be available to us.

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        Our Second Amended and Restated Certificate of Incorporation to be effective upon the completion of this offering (the "Second Amended and Restated Certificate of Incorporation") provides that we expressly renounce any interest or expectancy in any business opportunity in which any Legacy Class A Stockholder or any of our directors who is also, without limitation, an employee, partner, officer or director of a Legacy Class A Stockholder or any of their affiliates (each, a "Covered Person") participates or desires or seeks to participate in. See "Certain Relationships and Related Party Transactions—Stockholders Agreement" and "Description of Capital Stock—Corporate Opportunity."

We will be a "controlled company" within the meaning of the NYSE rules and, as a result, will qualify for, and intend to rely on, exemptions from certain corporate governance requirements.

        Upon the closing of this offering, our Sponsors and the other Legacy Class A Stockholders, as a group, will continue to control a majority of our voting common stock. As a result, we will be a "controlled company" within the meaning of applicable corporate governance standards. Under the NYSE rules, a company of which more than 50% of the voting power is held by an individual, group or another company is a "controlled company" and may elect not to comply with certain corporate governance requirements, including:

    the requirement that we have a majority of independent directors on our Board;

    the requirement that we have a nominating committee that is composed entirely of independent directors with a written charter addressing the committee's purpose and responsibilities;

    the requirement that we have a compensation committee that is composed entirely of independent directors; and

    the requirement for an annual performance evaluation of the nominating and compensation committees.

        Following this offering, we intend to utilize the foregoing exemptions from the applicable corporate governance requirements. As a result, we will not have a majority of independent directors. In addition, our compensation committee will not consist entirely of independent directors and we will not be required to have an annual performance evaluation of the compensation committee. See "Management." Accordingly, you will not have the same protections afforded to stockholders of companies that are subject to all of the NYSE's corporate governance requirements.

The price of our common stock may fluctuate significantly and you could lose all or part of your investment.

        Volatility in the market price of our common stock may prevent you from being able to sell your common stock at or above the price you paid for your common stock. The market price for our common stock could fluctuate significantly for various reasons, including:

    our operating and financial performance and prospects;

    changes in earnings estimates or recommendations by securities analysts who track our common stock or industry;

    market and industry perception of our success, or lack thereof, in pursuing our growth strategy; and

    sales of common stock by us, our stockholders, our Sponsors, or members of our management team.

        In addition, the stock market has experienced significant price and volume fluctuations in recent years. This volatility has had a significant impact on the market price of securities issued by many companies, including companies in our industry, and the changes frequently appear to occur without regard to the operating performance of the affected companies. Hence, the price of our common stock could fluctuate based upon factors that have little or nothing to do with us, and these fluctuations could materially reduce our share price.

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We currently have no plans to pay regular dividends on our common stock, so you may not receive funds without selling your common stock.

        We currently have no plans to pay regular dividends on our common stock. Any payment of future dividends will be at the discretion of our Board and will depend on, among other things, our earnings, financial condition, capital requirements, level of indebtedness, contractual restrictions applying to the payment of dividends, and other considerations that our Board deems relevant. The terms of the agreements governing our indebtedness include limitations on our ability to pay dividends and/or the ability of our subsidiaries to pay dividends to us. Accordingly, you may have to sell some or all of your common stock in order to generate cash flow from your investment.

We are a holding company and rely on dividends and other payments, advances and transfers of funds from our subsidiaries to meet our dividend and other obligations.

        We are a holding company and have no direct operations and no material assets other than our direct or indirect ownership of 100% of the equity interests of EPE Acquisition, our wholly owned holding company that holds our operating subsidiaries indirectly through its subsidiaries. Because we conduct our operations through our subsidiaries, we depend on those entities for dividends and other payments to generate the funds necessary to meet our financial obligations and to pay any dividends on our common stock and have no other means of generating revenue. Legal and contractual restrictions in the RBL Facility, our other existing debt agreements and other agreements that may govern future indebtedness of our subsidiaries, may limit our ability to obtain cash from our subsidiaries. The earnings from, or other available assets of, our subsidiaries may not be sufficient to pay dividends or make distributions or loans to enable us to pay any dividends on our common stock or other obligations. To the extent we need funds and EPE Acquisition or any of our other subsidiaries are restricted from making such distributions under applicable law or regulation or under the terms of their financing arrangements, or they are otherwise unable to provide such funds, it could materially adversely affect our liquidity and financial condition.

Future sales or the possibility of future sales of a substantial amount of our common stock may depress the price of shares of our common stock.

        We may sell additional shares of common stock in subsequent public offerings or otherwise, including to finance acquisitions. Our Second Amended and Restated Certificate of Incorporation authorizes us to issue                shares of common stock, of which                        shares will be outstanding upon completion of this offering (          if the underwriters' option to purchase additional shares is exercised in full). The outstanding share number includes shares that we are selling in this offering, which may be resold immediately in the public market. The remaining outstanding shares are restricted from immediate resale under the lock-up agreements with the underwriters described in "Underwriting," but may be sold into the market in the near future. Following the expiration of the applicable lock-up period, which is            days after the date of this prospectus,                         shares of our common stock will be freely transferable without restriction or further registration under the Securities Act, except for any such shares which are held or may be acquired by any of our "affiliates" as that term is defined in Rule 144 under the Securities Act, which will be subject to the resale limitations of Rule 144. See "Shares Eligible for Future Sale" for a discussion of the shares of our common stock that may be sold into the public market in the future.

        Pursuant to the Registration Rights Agreement, the Legacy Class A Stockholders have certain rights to demand underwritten registered offerings in respect of the approximately                 shares of common stock that they will own immediately following this offering, and we have granted the Sponsors and the other Legacy Class A Stockholders incidental registration rights, in respect of shares of common stock. Upon the effectiveness of a registration statement, all shares covered by the registration statement would be freely transferable without restriction or further registration under the Securities Act, except for any such shares which are held or may be acquired by any of our "affiliates" as that

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term is defined in Rule 144 under the Securities Act, which will be subject to the resale limitations of Rule 144. See "Certain Relationships and Related Party Transactions—Registration Rights Agreement."

        Pursuant to our Second Amended and Restated Certificate of Incorporation, in connection with certain sales of common stock by Apollo and/or Riverstone (the "Specified Stockholders"), holders of Class B common stock will have their Class B shares exchanged for shares of newly issued common stock. In connection with the exchanges of Class B common stock, we intend to file one or more shelf registration statements under the Securities Act covering the newly issued shares of common stock. Accordingly, these registered shares may become available for sale in the open market upon the completion of such exchanges, subject to Rule 144 limitations applicable to our affiliates. See "Description of Capital Stock—Class B common stock" and "Description of Capital Stock—Class B Exchange." As soon as practicable after the completion of this offering, we intend to file a registration statement on Form S-8 under the Securities Act covering                shares of our common stock reserved for issuance under the Omnibus Incentive Plan described elsewhere in this prospectus. Accordingly, shares of our common stock registered under such registration statement may become available for sale in the open market upon grants under the Omnibus Incentive Plan, subject to vesting restrictions, Rule 144 limitations applicable to our affiliates and contractual lock-up provisions.

        We cannot predict the size of future issuances of our common stock or the effect, if any, that future issuances and sales of our common stock will have on the market price of our common stock. Sales of substantial amounts of our common stock (including any shares issued in connection with an acquisition), or the perception that such sales could occur, may adversely affect prevailing market prices for our common stock.

Our organizational documents and the Stockholders Agreement may impede or discourage a takeover, which could deprive our investors of the opportunity to receive a premium for their shares.

        Provisions of our Second Amended and Restated Certificate of Incorporation, our amended and restated bylaws to be effective upon the completion of this offering (our "Amended and Restated Bylaws") and the Stockholders Agreement may make it more difficult for, or prevent a third party from, acquiring control of us without Special Board Approval (as defined below). These provisions include:

    granting each Sponsor, for so long as it beneficially owns certain percentages of its ownership of common stock as of the effective time of the registration statement of which this prospectus forms a part (the "Effective Time"), the right to designate a certain number of directors and the sole right to remove any director designated by it, with or without cause, and to fill any vacancy caused by the removal of any such director;

    classifying our Board into three classes of directors;

    prohibiting cumulative voting in the election of directors;

    authorizing the issuance of "blank check" preferred stock without stockholder approval; and

    for so long as the Negative Control Condition (as defined below) is satisfied, requiring Special Board Approval (as defined below) for certain corporate actions, including amendments to our organizational documents, equity issuances, acquisitions or dispositions of material assets, changing the composition of our Board, hiring or firing our chief executive officer, chief financial officer and any other member of senior management and certain other significant matters (see "Certain Relationships and Related Party Transactions—Stockholders Agreement").

        In addition, for so long as the Negative Control Condition is satisfied, our Board may, by Special Board Approval, issue preferred stock in one or more series, designate the number of shares constituting any series, and fix the rights, preferences, privileges and restrictions thereof, including dividend rights, voting rights, rights and terms of redemption, redemption price or prices and liquidation preferences of such series. The issuance of preferred stock may have the effect of delaying,

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deferring or preventing a change in control without further action by the stockholders, even where stockholders are offered a premium for their shares. Under our Stockholders Agreement, (i) "Negative Control Condition" means that the Legacy Class A Stockholders hold at least 25% of our outstanding common stock and either Apollo or Riverstone is entitled to designate at least one director pursuant to the Stockholders Agreement and (ii) "Special Board Approval" means the approval by a majority of our Board, which majority includes (a) at least one director designated to our Board by Apollo and (b) at least one director designated to our Board by one of the other Sponsors or one replacement director designated to our Board by a vote of the Legacy Class A Stockholders holding a majority-in-interest of our outstanding common stock then held by the Legacy Class A Stockholders in the event a Sponsor has lost its right to designate its applicable director and the Legacy Class A Stockholders hold at least 50% of our outstanding common stock.

        Together, our organizational documents and the Stockholders Agreement could make the removal of management more difficult and may discourage transactions that otherwise could involve payment of a premium over prevailing market prices for our common stock. Furthermore, the existence of the foregoing provisions, as well as the significant common stock owned by the Sponsors following this offering and their individual rights to designate a specified number of directors in certain circumstances, could limit the price that investors might be willing to pay in the future for our common stock. Our organizational documents and the Stockholders Agreement could also deter potential acquirers of us, thereby reducing the likelihood that you could receive a premium for your common stock in an acquisition. See "Description of Capital Stock—Certain Anti-Takeover, Limited Liability and Indemnification Provisions" and See "Certain Relationships and Related Party TransactionsStockholders Agreement—Consent Rights."

The corporate opportunity provisions in our Second Amended and Restated Certificate of Incorporation could enable the Sponsors to benefit from corporate opportunities that might otherwise be available to us.

        Subject to the limitations of applicable law, our Second Amended and Restated Certificate of Incorporation provides, among other things, that:

    any Covered Person has the right to, and has no duty to abstain from, exercising such right to conduct business with any business that is competitive or in the same line of business as us, do business with any of our clients or customers, or invest or own any interest publicly or privately in, or develop a business relationship with, any business that is competitive or in the same line of business as us;

    if a Covered Person acquires knowledge of a potential transaction that could be a corporate opportunity, he or she has no duty to offer such corporate opportunity to us; and

    we have renounced any interest or expectancy in, or in being offered an opportunity to participate in, such corporate opportunities.

        As a result, the Legacy Class A Stockholders and their affiliates may become aware, from time to time, of certain business opportunities, such as acquisition opportunities, and may direct such opportunities to other businesses in which they have invested, in which case we may not become aware of or otherwise have the ability to pursue such opportunity. Further, such businesses may choose to compete with us for these opportunities. As a result, our renouncing our interest and expectancy in any business opportunity that may be presented to the Legacy Class A Stockholders and their affiliates could adversely impact our business or prospects if attractive business opportunities are procured by such parties for their own benefit rather than for ours. Please read "Description of Capital Stock—Corporate Opportunities."

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We have engaged in transactions with our affiliates and expect to do so in the future. The terms of such transactions and the resolution of any conflicts that may arise may not always be in our or our stockholders' best interests.

        We have engaged in transactions and expect to continue to engage in transactions with affiliated companies, as described under the caption "Certain Relationships and Related Party Transactions." The resolution of any conflicts that may arise in connection with any related party transactions that we have entered into with the Sponsors, the other Legacy Class A Stockholders or their affiliates, including pricing, duration or other terms of service, may not always be in our or our stockholders' best interests because the Sponsors and the other Legacy Class A Stockholders may have the ability to influence the outcome of these conflicts. For a discussion of potential conflicts, please read "—The interests of our Sponsors may conflict with or differ from your interests as a stockholder."

You will experience an immediate and substantial dilution in the net tangible book value of the common stock you purchase.

        After giving effect to this offering and the other adjustments described in "Dilution," we expect that our pro forma as adjusted net tangible book value as of June 30, 2013 would be $            per share. Based on an assumed initial public offering price of $            per share, the midpoint of the range set forth on the cover page of this prospectus, you will experience immediate and substantial dilution of approximately $            per share in net tangible book value of the common stock you purchase in this offering. See "Dilution," including the discussion of the effects on dilution from a change in the price of this offering.

We may issue preferred stock with terms that could adversely affect the voting power or value of our common stock.

        Our Second Amended and Restated Certificate of Incorporation authorizes us to issue, without the approval of our stockholders, one or more classes or series of preferred stock having such designations, preferences, limitations and relative rights, including preferences over our common stock respecting dividends and distributions, as our Board may determine, subject to Special Board Approval for so long as the Negative Control Condition is satisfied. The terms of any class or series of preferred stock could adversely impact the voting power or value of our common stock. For example, we might grant holders of preferred stock the right to elect some number of our directors in all events or on the happening of specified events or the right to veto specified transactions. Similarly, the repurchase or redemption rights or liquidation preferences we might assign to holders of preferred stock could affect the residual value of the common stock. See "Description of Capital Stock—Certain Anti-Takeover, Limited Liability and Indemnification Provisions."

We have issued shares of Class B common stock to management with terms that may adversely affect the value of our common stock.

        Certain of our employees and members of our management team indirectly hold 808,304 shares of our Class B common stock, par value $0.01 per share. In addition, we will issue an additional 70,000 shares of our Class B common stock to EPE Employee Holdings II, LLC, a vehicle through which we will grant to our current and future employees awards representing the right to receive the proceeds paid in respect of such shares of Class B common stock pursuant to the Second Amended and Restated Certificate of Incorporation. The terms, preferences and rights of the Class B common stock set forth in our Second Amended and Restated Certificate of Incorporation may under certain circumstances reduce the amount of dividends and liquidation proceeds otherwise distributable to holders of common stock and dilute existing holders of common stock as a result of an exchange of shares of Class B common stock for shares of common stock. Pursuant to our Second Amended and Restated Certificate of Incorporation and subject to certain limitations, holders of Class B common stock are entitled to participate in dividends and distributions of proceeds upon a liquidation of the

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company. In connection with certain sales of shares of common stock by Apollo and Riverstone, holders of shares of Class B common stock will have their shares exchanged for shares of newly issued common stock. The extent to which holders of Class B common stock participate in dividends and distributions of liquidation proceeds will depend on the return on invested capital in the Company and EPE Acquisition received by our Sponsors and the other Legacy Class A Stockholders, but will in any event be limited to 8.5% of the amount of such returns in excess of such invested capital by the Sponsors and the other Legacy Class A Stockholders. The number of shares of common stock issued in an exchange will depend on the return on invested capital in the Company and EPE Acquisition received by Apollo and Riverstone subject to an adjustment multiple (with respect to exchanges of Class B common stock). See "Description of Capital Stock—Class B common stock," "Description of Capital Stock—Distributions Upon a Liquidation" and "Description of Capital Stock—Class B Exchange."

The additional requirements of having a class of publicly traded equity securities may strain our resources and distract management.

        Even though EP Energy LLC currently files reports with the SEC, after the consummation of this offering, we will be subject to additional reporting requirements of the Securities Exchange Act of 1934, as amended (the "Exchange Act"), the Sarbanes-Oxley Act of 2002 (the "Sarbanes-Oxley Act") and the Dodd-Frank Act. The Dodd-Frank Act effects comprehensive changes to public company governance and disclosures in the United States and will subject us to additional federal regulation. We cannot predict with any certainty the requirements of the regulations ultimately adopted or how the Dodd-Frank Act and such regulations will impact the cost of compliance for a company with publicly traded common stock. We are currently evaluating and monitoring developments with respect to the Dodd-Frank Act and other new and proposed rules and cannot predict or estimate the amount of the additional costs we may incur or the timing of such costs. All laws, regulations and standards are subject to varying interpretations, in many cases due to their lack of specificity, and, as a result, their application in practice may evolve over time as new guidance is provided by regulatory and governing bodies. This could result in continuing uncertainty regarding compliance matters and higher costs necessitated by ongoing revisions to disclosure and governance practices. We intend to invest resources to comply with evolving laws, regulations and standards, and this investment may result in increased general and administrative expenses and a diversion of management's time and attention from revenue-generating activities to compliance activities. If our efforts to comply with new laws, regulations and standards differ from the activities intended by regulatory or governing bodies due to ambiguities related to practice, regulatory authorities may initiate legal proceedings against us and our business may be harmed. We also expect that being a company with publicly traded common stock subject to these new rules and regulations will make it more expensive for us to obtain director and officer liability insurance, and we may be required to accept reduced coverage or incur substantially higher costs to obtain coverage. These factors could also make it more difficult for us to attract and retain qualified members of our Board, particularly to serve on our audit committee, and qualified executive officers.

        The Sarbanes-Oxley Act requires that we maintain effective disclosure controls and procedures and internal control over financial reporting. These requirements may place a strain on our systems and resources. Under Section 404 of the Sarbanes-Oxley Act, we will be required to include a report of management on our internal control over financial reporting in our Annual Reports on Form 10-K beginning with the Form 10-K for the year ending December 31, 2014. In order to maintain and improve the effectiveness of our disclosure controls and procedures and internal control over financial reporting, significant resources and management oversight will be required. This may divert management's attention from other business concerns, which could have a material adverse effect on our business, financial condition, results of operations and cash flows. If we are unable to conclude that our disclosure controls and procedures and internal control over financial reporting are effective, investors may lose confidence in our financial reports and our stock price may decline.

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CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

        This prospectus 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 prospectus, including those set forth in "Risk Factors." Important factors that could cause our actual results to differ materially from the expectations reflected in our forward-looking statements include, among others:

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

    our ability to meet production volume targets;

    the uncertainty of estimating proved reserves and unproved resources;

    the future level of service and capital costs;

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

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

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

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

    actions by credit rating agencies;

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

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

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

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

    political and currency risks associated with our international operations;

    competition; and

    the other factors described under "Risk Factors."

        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 our forward-looking statements, whether as a result of new information, subsequent events, anticipated or unanticipated circumstances or otherwise.

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USE OF PROCEEDS

        Assuming an initial public offering price of $            per share, the midpoint of the range set forth on the cover page of this prospectus, we estimate that we will receive net proceeds from this offering of approximately $             million, after deducting underwriting discounts and commissions and other estimated expenses of $             million payable by us.

        Each $1.00 increase (decrease) in the assumed initial public offering price of $            per share would increase (decrease) the net proceeds to us from this offering by $             million, assuming the number of shares offered by us, as set forth on the cover page of this prospectus, remains the same and after deducting the estimated underwriting discounts and commissions and estimated expenses payable by us. An increase (decrease) of 1,000,000 in the number of shares we are offering would increase (decrease) the net proceeds to us from this offering, after deducting the estimated underwriting discounts and commissions and estimated expenses payable by us, by approximately $             million, assuming the initial public offering price per share remains the same.

        We intend to use the net proceeds from this offering (i) to redeem all of the outstanding 8.125%/8.875% Senior PIK Toggle Notes due 2017 issued by our subsidiaries, EPE Holdings LLC and EP Energy Bondco Inc., and pay the redemption premium and the accrued and unpaid interest on the notes, (ii) to repay outstanding borrowings under the RBL Facility, (iii) to pay an approximately $             million fee under the transaction fee agreement with certain affiliates of our Sponsors and (iv) for general corporate purposes. We will also reimburse the Legacy Stockholders for expenses incurred in connection with the Corporate Reorganization and this offering.

        The PIK notes were issued on December 21, 2012 and mature on December 15, 2017. The issuers may elect to pay interest on the PIK notes (i) in cash, (ii) by increasing the principal amount of the outstanding notes or issuing new notes ("PIK interest") or (iii) in cash on 50% of the outstanding principal amount of the notes and in PIK interest on the remaining 50% of the outstanding principal amount of the notes. The PIK notes accrue cash interest at a rate of 8.125% per annum and PIK interest at a rate of 8.875% per annum. The PIK notes may be redeemed with the net cash proceeds of this offering at a redemption price equal to 102% of the principal amount plus accrued and unpaid interest to the redemption date. See "Description of Certain Indebtedness—Senior PIK Toggle Notes." As of August 31, 2013, we had $372 million of outstanding aggregate principal amount of PIK notes.

        As of August 31, 2013, we had $175 million of outstanding borrowings under the RBL Facility. The RBL Facility matures on May 24, 2017 and bears interest at LIBOR plus 1.50%. The borrowings to be repaid were incurred primarily to fund capital expenditures and other general corporate expenditures. See "Description of Certain Indebtedness—RBL Facility."

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DIVIDEND POLICY

        We currently intend to retain all future earnings, if any, for use in the operation of our business and to fund future growth. The decision whether to pay dividends in the future will be made by our Board in light of conditions then existing, including factors such as our financial condition, earnings, available cash, business opportunities, legal requirements, restrictions in our debt agreements and other contracts, including requirements under our Second Amended and Restated Certificate of Incorporation and the Stockholders Agreement described elsewhere in this prospectus, and other factors our Board deems relevant. See "Certain Relationships and Related Party Transactions—Stockholders Agreement."

        We are a holding company and have no direct operations. We will only be able to pay dividends from our available cash on hand and funds received from our subsidiaries, whose ability to make any payments to us will depend upon many factors, including their operating results and cash flows. In addition, the RBL Facility and the indentures governing our subsidiaries' existing notes limit the ability of our subsidiary, EP Energy LLC, to pay distributions on its equity interests. See "Management's Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources," "—Contractual Obligations," "—Commitments and Contingencies" and "Description of Certain Indebtedness."

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CAPITALIZATION

        The following table sets forth our cash and cash equivalents and capitalization as of June 30, 2013:

            (1)   on a historical basis,

            (2)   on a pro forma as adjusted basis to give effect to (i) our pending and completed divestitures and the use of proceeds therefrom as described in "Summary—Recent Divestitures," (ii) the repayment of $500 million under our senior secured term loans in August 2013, and (iii) the $200 million distribution EPE Acquisition made to its members in August 2013, and

            (3)   on a pro forma as further adjusted basis to give effect to (i) the Corporate Reorganization and (ii) our sale of                    shares of common stock in this offering at an assumed offering price of $            , which is the midpoint of the range listed on the cover page of this prospectus, and our use of the estimated net proceeds from this offering as described under "Use of Proceeds."

        You should read this table in conjunction with "Selected Historical Consolidated Financial Data," "Management's Discussion and Analysis of Financial Condition and Results of Operations" and our historical consolidated financial statements and the related notes appearing elsewhere in this prospectus, as well as the sections "Summary—Summary Historical and Pro Forma Consolidated Financial Data," "Use of Proceeds" and "Unaudited Pro Forma Condensed Consolidated Financial Data" included in this prospectus.

 
  June 30, 2013  
 
  EPE Acquisition,
LLC Historical(1)
  EP Energy
Corporation
Pro Forma as
Adjusted
  EP Energy
Corporation
Pro Forma
as Further
Adjusted(2)
 
 
  (in millions)
 

Cash and cash equivalents

  $ 283   $ 66   $               
               

Debt:

                   

RBL Facility(3)

  $ 785   $   $    

Senior secured term loans

    1,142     642        

Senior secured notes due 2019

    750     750        

9.375% senior notes due 2020

    2,000     2,000        

7.750% senior notes due 2022

    350     350        

8.125% / 8.875% PIK notes due 2017

    365     365        
               

Total debt

  $ 5,392   $ 4,107   $    

Total equity

    2,842     2,817        
               

Total capitalization

  $ 8,234   $ 6,924   $    
               

(1)
The data has been derived from the unaudited financial statements of EPE Acquisition included elsewhere in this prospectus.

(2)
A $1.00 increase (decrease) in the assumed initial public offering price of $            per share would increase (decrease) cash and total capitalization by $             million, assuming the number of shares offered by us, as set forth on the cover page of this prospectus, remains the same and after deducting the estimated underwriting discounts and commissions and estimated expenses payable by us.

(3)
At the completion of this offering, we will have borrowing availability of $2.5 billion under the RBL Facility. See "Description of Certain Indebtedness—The RBL Facility."

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DILUTION

        Dilution is the amount by which the offering price paid by the purchasers of the common stock to be sold in this offering exceeds the net tangible book value per share of common stock after the offering. Net tangible book value per share is determined at any date by subtracting our total liabilities from the total book value of our tangible assets and dividing the difference by the number of shares of common stock deemed to be outstanding at that date. There will be shares of our common stock reserved for future awards under the Omnibus Incentive Plan as of the consummation of this offering.

        Our net tangible book value (tangible assets less total liabilities) as of June 30, 2013, after giving pro forma effect to the transactions described in "—Summary Historical and Pro Forma Consolidated Financial Data" was approximately $2.8 billion, or $            per share of common stock. Pro forma net tangible book value per share is determined by dividing our pro forma net tangible book value by our shares of common stock that will be outstanding immediately prior to the closing of this offering, including giving effect to the transactions described above. After giving effect to the receipt of approximately $             million of estimated net proceeds from our sale of                    shares of common stock in this offering at an assumed offering price of $            per share, the midpoint of the range set forth on the front cover of this prospectus, our pro forma net tangible book value as of June 30, 2013 would have been approximately $             million, or $            per share. This represents an immediate decrease in our pro forma net tangible book value of $            per share to our existing stockholders and an immediate dilution of $            per share to new investors purchasing shares of common stock in the offering. The following table illustrates this substantial and immediate per share dilution to new investors:

 
  Per Share  

Assumed initial public offering price per share

  $    

Pro forma net tangible book value prior to the offering

       

Increase per share attributable to investors in the offering

       

Pro forma net tangible book value after the offering

       

Dilution per share to new investors

  $    

        A $1.00 increase (decrease) in the assumed initial public offering price of $            per share would decrease (increase) our pro forma net tangible book value by $             million, or $            per share, and increase (decrease) the dilution per share to new investors in this offering by $            , assuming the number of shares offered by us, as set forth on the cover page of this prospectus, remains the same and after deducting the estimated underwriting discounts and commissions and estimated expenses payable by us.

        The following table summarizes on an as adjusted basis as of June 30, 2013, giving effect to:

    the total number of shares of common stock purchased from us;

    the total consideration paid to us, assuming an initial public offering price of $            per share (before deducting the estimated underwriting discount and commissions and offering expenses payable by us in connection with this offering); and

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    the average price per share paid by our existing stockholders and by new investors purchasing shares in this offering:

 
   
   
  Total
Consideration
   
 
 
  Shares Purchased    
 
 
  Average Price
Per Share
 
 
  Number   Percent   Amount   Percent  

Existing stockholders

          % $       % $    

Investors in this offering

          %         %      

Total

        100 % $     100 % $    

        A $1.00 increase (decrease) in the assumed initial public offering price of $            per share (the midpoint of the range set forth on the cover page of this prospectus) would increase (decrease) total consideration paid by new investors, total consideration paid by all stockholders and the average price per share by $             million, $             million and $             million, respectively, assuming the number of shares offered by us, as set forth on the cover page of this prospectus, remains the same.

        The tables and calculations above also assume no exercise of the underwriters' option to purchase                    additional shares. If the underwriters exercise their option to purchase                     additional shares in full, then new investors would purchase                    shares, or approximately        % of shares outstanding, the total consideration paid by new investors would increase to $             million, or        % of the total consideration paid (based on the midpoint of the range set forth on the cover page of this prospectus), and the additional dilution per share to new investors would be $            .

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SELECTED HISTORICAL CONSOLIDATED FINANCIAL DATA

        We have derived the selected historical consolidated balance sheet data as of December 31, 2012 (successor) and December 31, 2011 (predecessor), and the statements of income data and statements of cash flow data for the period from February 14 (inception) to December 31, 2012 (successor), the period from January 1, 2012 through May 24, 2012 (predecessor) and each of the two years in the period ended December 31, 2011 (predecessor), from the audited consolidated financial statements of EPE Acquisition, LLC, which are included elsewhere in this prospectus. EPE Acquisition, LLC, was the ultimate holding company prior to our Corporate Reorganization. Historical financial results of EPE Acquisition, LLC in this prospectus for the period before the Acquisition on May 24, 2012, are referred to as the predecessor and after the Acquisition are referred to as the successor in accordance with the required GAAP presentation.

        We have derived the selected historical consolidated balance sheet data as of December 31, 2010, 2009, and 2008, and the statements of income data and statements of cash flow data for the years ended December 31, 2009 and 2008 from the audited consolidated financial statements of EP Energy Corporation, the predecessor of EPE Acquisition, LLC and referred to herein as Historical EP Energy Corporation, which are not included in this prospectus. The selected unaudited historical consolidated financial data as of and for the six months ended June 30, 2013 (successor) and for the period from February 14, 2012 through June 30, 2012 (successor), have been derived from the unaudited consolidated financial statements of EPE Acquisition, LLC appearing elsewhere in this prospectus, which have been prepared on a basis consistent with the audited consolidated financial statements of EPE Acquisition, LLC. In the opinion of management, such unaudited financial data reflects all adjustments, consisting only of normal and recurring adjustments, necessary for a fair presentation of the results for such period. The results of operations for the interim periods are not necessarily indicative of the results to be expected for the full year or any future period.

        The following selected historical consolidated financial data should be read in conjunction with the information included under the headings "Summary—Corporate History and Structure" and "Management's Discussion and Analysis of Financial Condition and Results of Operations" and the historical consolidated financial statements and related notes included elsewhere in this prospectus.

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  EPE Acquisition, LLC   Historical EP
Energy Corporation
 
 
  Six
months
ended
June 30,
(Successor)
  February 14
(inception)
to June 30,
(Successor)
  February 14
(inception)
to
December 31,
(Successor)
   
  January 1
to
May 24,
(Predecessor)
  Years ended
December 31,
(Predecessor)
  Years ended
December 31,
 
 
  2013   2012   2012    
  2012   2011   2010   2009   2008  
 
  (in millions)
   
 

Statement of income data

                                                     

Operating revenues:

                                                     

Oil and condensate

  $ 568   $ 74   $ 555       $ 322   $ 552   $ 346   $ 214   $ 436  

Natural gas

    215     46     278         262     973     974     830     1,960  

NGL

    32     4     32         29     57     60     53     105  
                                       

Physical sales

    815     124     865         613     1,582     1,380     1,097     2,501  

Financial derivatives(1)

    35     57     (62 )       365     284     390     687     196  

Other

                        1     19     44     65  
                                       

Total operating revenues

    850     181     803         978     1,867     1,789     1,828     2,762  
                                       

Operating expenses:

                                                     

Natural gas purchases

    10     4     19                          

Transportation costs

    46     9     51         45     85     73     66     79  

Lease operating expenses

    98     15     96         96     217     193     197     244  

General and administrative expenses           

    118     208     371         75     201     190     195     160  

Depreciation, depletion and amortization

    277     26     217         319     612     477     440     818  

Impairments/Ceiling test charges

    10     1     1         62     158     25     2,148     2,824  

Exploration expense

    27     6     50                          

Taxes, other than income taxes

    43     10     51         45     91     85     68     132  

Other

                            15     31     38  
                                       

Total operating expenses

    629     279     856         642     1,364     1,058     3,145     4,295  
                                       

Operating income (loss)

    221     (98 )   (53 )       336     503     731     (1,317 )   (1,533 )

Income (loss) from unconsolidated affiliates

    6     (1 )   (1 )       (5 )   (7 )   (7 )   (30 )   (93 )

Other income (expense)

    (1 )   1     3         (3 )   (2 )   3     (1 )   7  

Loss on extinguishment of debt

    (3 )       (14 )                        

Interest expense, net of capitalized interest

    (178 )   (53 )   (219 )       (14 )   (12 )   (21 )   (25 )   (57 )
                                       

Income (loss) from continuing operations before income taxes

    45     (151 )   (284 )       314     482     706     (1,373 )   (1,676 )

Income tax expense (benefit)

    2         2         136     220     263     (462 )   (413 )
                                       

Income (loss) from continuing operations

  $ 43   $ (151 ) $ (286 )     $ 178   $ 262   $ 443   $ (911 ) $ (1,263 )
                                       

(1)
Includes $5 million for the periods from January 1 to May 24, 2012, and $11 million, $11 million, ($406) million and $88 million for the years ended December 31, 2011, 2010, 2009 and 2008, respectively, reclassified from accumulated other comprehensive income associated with accounting hedges.

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  EPE Acquisition, LLC   Historical EP Energy
Corporation
 
 
  Six
Months
ended
June 30,
(Successor)
  February 14
(inception),
to June 30,
(Successor)
  February 14
(inception),
to
December 31,
(Successor)
   
  January 1,
to
May 24,
(Predecessor)
  Years ended
December 31,
(Predecessor)
  Years ended
December 31,
 
 
  2013   2012   2012    
  2012   2011   2010   2009   2008  
 
  (in millions)
   
 

Statement of cash flows data

                                                     

Net cash provided by

                                                     

(used in):

                                                     

Operating activities

  $ 450   $ (92 ) $ 449       $ 580   $ 1,426   $ 1,067   $ 1,573   $ 2,218  

Investing activities

    (906 )   (7,254 )   (7,893 )       (628 )   (1,237 )   (1,130 )   (1,156 )   (993 )

Financing activities

    670     7,401     7,513         110     (238 )   (46 )   (336 )   (1,237 )

 

 
  EPE Acquisition, LLC   Historical EP Energy Corporation  
 
  As of
June 30,
(Successor)
  As of
December 31,
(Successor)
   
  As of
December 31,
(Predecessor)
  As of December 31,  
 
  2013   2012    
  2011   2010   2009   2008  
 
  (in millions)
   
 

Balance sheet data

                                         

Cash and cash equivalents

  $ 283   $ 69       $ 25   $ 74   $ 183   $ 102  

Total assets

    9,181     8,306         5,099     4,942     4,457     6,384  

Total debt

    5,392     4,695         851     301     835     915  

Members'/ Stockholder's equity

    2,842     2,748         3,100     3,067     2,529     3,697  

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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 included elsewhere in this prospectus. This discussion contains forward-looking statements and involves numerous risks and uncertainties, including, but not limited to, those described in "Risk Factors." Actual results may differ materially from those contained in any forward-looking statements. Additionally, the financial results for the successor periods include the application of the acquisition method of accounting and the application of the successful efforts method of accounting for oil and natural gas properties. The successor periods also present certain of our natural gas assets sold, including the CBM, South Texas and the majority of our Arklatex assets, as discontinued operations. Predecessor periods do not present these sales as discontinued operations due to the application of the full cost method of accounting prior to the Acquisition. As a result of these differences in presentation, trends and results in future periods may be different than those that existed prior to the Acquisition. Unless otherwise indicated or the context otherwise requires, references in this MD&A section to "we," "our," "us" and "the Company" refer to EPE Acquisition, LLC (subsequently reorganized as a directly and indirectly owned subsidiary of EP Energy Corporation (the issuer) in the third quarter of 2013) and its predecessor entities 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 Uinta Basin (Utah) and the Haynesville Shale (North Louisiana).

        During the third quarter of 2013, we sold certain of our natural gas properties, including our CBM properties located in the Raton, Black Warrior and Arkoma basins, the majority of our Arklatex natural gas properties and our natural gas properties in South Texas. As of June 30, 2013, these assets represented 1,014 Bcfe of proved reserves (96% natural gas). The total consideration from these transactions was approximately $1.3 billion. In addition, in July 2013, certain of our subsidiaries entered into a Quota Purchase Agreement relating to the sale of all of our Brazil operations. This transaction represents the sale of all of our remaining international assets and is expected to close by the end of the first quarter of 2014, subject to Brazilian regulatory approval and certain other customary closing conditions.

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

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

    finding and producing oil and natural gas at reasonable costs;

    managing cash costs; and

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

        In addition to these factors, our future profitability and performance will be affected by our ability to execute our strategy, volatility in the financial and commodity markets, changes in the cost of drilling and oilfield services, operating and capital costs and our debt level and related interest costs.

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Additionally, we may be impacted by weather events, or domestic or international regulatory issues or other third party actions outside of our control (e.g., oil spills).

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

        Derivative Instruments.    During the six months ended June 30, 2013, approximately 95% of our liquids production and 90% of our natural gas production were hedged and settled at average floor prices of $99.93 per barrel and $3.57 per MMBtu, respectively. In conjunction with the sale of certain of our non-core natural gas assets, we entered into offsetting positions on natural gas derivatives of 36 TBtu on anticipated 2013 production and 42 TBtu on anticipated 2014 production. The following table reflects the contracted volumes and the prices we will receive under derivative contracts we held as of June 30, 2013.

 
  2013   2014   2015  
 
  Volumes(1)   Average
Price(1)
  Volumes(1)   Average
Price(1)
  Volumes(1)   Average
Price(1)
 

Oil

                                     

Fixed Price Swaps(2)

    8,684   $ 100.09     12,117   $ 97.70     6,231   $ 94.57  

Ceilings

    1,042   $ 98.24     1,095   $ 100.00     1,095   $ 100.00  

Three Way Collars Ceiling

      $     2,920   $ 103.76       $  

Three Way Collars Floors(3)

      $     2,920   $ 95.00       $  

Basis Swaps

    2,645     Various     4,380     Various     3,650     Various  

Natural Gas

                                     

Fixed Price Swaps

    49   $ 3.37     67   $ 4.02     44   $ 4.28  

Ceilings

    1   $ 3.75     13   $ 4.02       $  

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

(2)
On 3,128 MBbls, if market prices settle at or below $71.47 in 2013, we will receive a "locked-in" cash settlement of the market price plus $24.27 per Bbl.

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

        Between July 1 and August 29, 2013, we added fixed price oil derivatives covering volumes of 4 MMBbl, 12 MMBbl and 2 MMBbl to our 2014, 2015 and 2016 anticipated production, respectively. These derivatives are not reflected in the table above.

        Summary of Liquidity and Capital Resources.    As of June 30, 2013, we had available liquidity, including existing cash, of approximately $2.0 billion. We believe we have sufficient liquidity for the foreseeable future from our cash flows from operations, combined with the availability under our RBL Facility and available cash, to fund our capital spending plan, debt obligations, and projected working capital requirements. Additionally, the earliest maturity date of our debt obligations is in 2017. See "Liquidity and Capital Resources" for more information.

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

 
  Capital
Expenditures
(In millions)
  Rig
Count
 

Eagle Ford Shale

  $ 600     5  

Wolfcamp Shale

    236     3  

Uinta Basin

    94     2  

Haynesville Shale

    1      

Other

    6      
           

Total capital expenditures

  $ 937     10  
           

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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 following periods:

 
  Six months
ended
June 30,
  Year ended
December 31,
 
 
  2013   2012   2012   2011   2010  

United States (MBoe/d)

                               

Eagle Ford Shale

    33     15     20     6     1  

Wolfcamp Shale

    3     2     2          

Uinta Basin

    11     10     11     9     8  

Haynesville Shale

    32     53     48     45     25  

Other domestic

    5     9     7     7     7  

Divested assets(1)

        39     20     57     74  

Brazil (MBoe/d)

    5     6     6     6     5  
                       

Total Consolidated

    89     134     114     130     120  

Unconsolidated affiliate (MBoe/d)

    9     9     9     10     10  
                       

Total Combined (MBoe/d)

    98     143     123     140     130  
                       

Oil and condensate (MBbls/d)

                               

Consolidated volumes

    33     21     25     13     8  

Divested assets(1)

        1         3     5  

Unconsolidated affiliate volumes

    1     1     1     1     1  
                       

Total Combined

    34     23     26     17     14  
                       

Natural Gas (MMcf/d)

                               

Consolidated volumes

    300     425     391     355     226  

Divested assets(1)

        214     114     306     392  

Unconsolidated affiliate volumes

    40     43     42     46     47  
                       

Total Combined

    340     682     547     707     665  
                       

NGLs (MBbls/d)

                               

Consolidated volumes

    6     3     3     1      

Divested assets(1)

        2     2     2     4  

Unconsolidated affiliate volumes

    1     1     1     1     2  
                       

Total Combined (MBbls/d)

    7     6     6     4     6  
                       

(1)
Predecessor periods prior to May 24, 2012 include volumes from our CBM, South Texas, and the majority of our Arklatex assets, all of which were sold in 2013, and our Gulf of Mexico assets, which were sold in 2012. For periods after May 24, 2012, our CBM, South Texas and Arklatex assets are treated as discontinued operations and accordingly volumes relating to those assets are excluded from all financial and non-financial metrics.
    Eagle Ford Shale—Our Eagle Ford Shale equivalent volumes increased 18 MBoe/d for the six months ended June 30, 2013 compared to the same period in 2012 and 14 MBoe/d for the year ended December 31, 2012 compared to 2011, due in both cases to the success of our drilling program in the area. Eagle Ford oil production increased by 11 MBbls/d (or 106%) compared with the six months ended June 30, 2012. During the six months ended June 30, 2013, we drilled 67 additional wells and during the year ended December 31, 2012, we drilled 84 additional wells in our Eagle Ford area. We had a total of 203 net operated wells as of June 30, 2013. With a majority of our acreage located in the core of the oil window, primarily in LaSalle and Atascosa counties, we continue to grow our oil and NGLs production in the area.

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    Wolfcamp Shale—Our Wolfcamp Shale equivalent volumes increased 2 MBoe/d for the six months ended June 30, 2013 compared to the same period in 2012 and 2 MBoe/d for the year ended December 31, 2012 compared to the same period in 2011. We continue to progress the development of our Wolfcamp Shale drilling program where we drilled 17 additional wells during 2012 and drilled 25 additional wells during the first six months of 2013, for a total of 56 net operated wells as of June 30, 2013.

    Uinta Basin—Our Uinta Basin equivalent volumes increased 1 MBoe/d for the six months ended June 30, 2013 compared to the six months ended June 30, 2012 and 2 MBoe/d for the year ended December 31, 2012 compared to same period in 2011. The Uinta Basin produced an average of 8 MBbls/d of oil during the six months ended June 30, 2013, and we drilled an additional 13 operated oil wells at Uinta for a total of 319 net operated wells at June 30, 2013.

    Haynesville Shale—Our Haynesville Shale equivalent volumes decreased 21 MBoe/d for the six months ended June 30, 2013 compared to the six months ended June 30, 2012 and increased 3 MBoe/d for the year ended December 31, 2012 compared to same period in 2011. The decrease in 2013 was due to natural declines as we suspended our drilling program at the end of the first quarter of 2012 as a result of low natural gas prices. As of June 30, 2013 we had 99 net operated wells in the Haynesville Shale, and our total production for the six months ended June 30, 2013 was approximately 189 MMcf/d.

    Divested assets—Our divested assets were reclassified as discontinued operations for the six-month period ended June 30, 2013 and thus volumes related to these assets were not reflected in the table above. Equivalent volumes of divested assets in 2012, 2011 and 2010 include volumes for CBM, South Texas and the majority of our Arklatex assets, each sold in 2013, and Gulf of Mexico assets sold in 2012.

    Brazil—Production volumes related to our Brazil operations were 5 MBoe/d in each of the six-month periods ended June 30, 2013 and 2012 and 6 MBoe/d for the year ended December 31, 2012. On July 16, 2013, we entered into a Quota Purchase Agreement to sell our Brazil operations which is expected to close by the end of the first quarter of 2014, subject to Brazilian regulatory approval and certain other customary closing conditions.

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

Reserve replacement ratio   Sum of reserve additions(1)
     
    Actual production for the corresponding period

Reserve replacement costs/Boe

 

Total oil and natural gas capital costs(2)
     
    Sum of reserve additions(1)

(1)
Reserve additions include proved reserves and reflect reserve revisions for prices and performance, extensions, discoveries and other additions and acquisitions and do not include unproved reserve quantities or proved reserve additions attributable to investments accounted for using the equity method. 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 "—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 "—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."

        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 June 30, 2013, proved developed reserves represented approximately 35% of our total consolidated proved reserves. Proved developed reserves will generally begin producing within the year they are added, whereas proved undeveloped reserves generally require additional future expenditures.

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        The table below shows our reserve replacement ratio and reserve replacement costs, including and excluding the effect of price revisions on reserves for the six months ended June 30, 2013 and for each of the years ended December 31 2012, 2011 and 2010:

 
  Including Price Revisions   Excluding Price Revisions  
 
  Six
months
ended
June 30,
  Year ended December 31,   Six
months
ended
June 30,
  Year ended December 31,  
 
  2013   2012   2011   2010   2013   2012   2011   2010  

Reserve Replacement Ratios

    357%     47%     416%     370%     343%     298%     418%     306%  

Reserve Replacement Costs(1)($/Boe)

 
$

16.96
 
$

67.56
 
$

8.52
 
$

7.74
 
$

17.67
 
$

10.74
 
$

8.46
 
$

9.36
 

(1)
Proved and unproved acquisition and leasehold costs are included in all calculations. Excluding property acquisition costs would not materially impact our reserve replacement cost or reserve replacement ratio.

        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 the three years ended December 31, 2012.

 
  Including Price
Revisions
  Excluding Price
Revisions
 
 
  Three years ended
December 31, 2012
 
 
  ($/Boe)
 

Reserve Replacement Costs

  $ 11.88   $ 9.42  

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Results of Operations

        The information below reflects financial results for EPE Acquisition, LLC (the ultimate holding company prior to the Corporate Reorganization) for the six months ended June 30, 2013 (successor), for the periods from February 14 (inception) to June 30, 2012 (successor) and December 31, 2012 (successor), for the period from January 1 to May 24, 2012 (predecessor) and for the predecessor years ended December 31, 2011 and 2010. Beginning with the Acquisition in May 2012, our successor period financial results reflect the application of the acquisition method of accounting, the application of the successful efforts method of accounting for oil and natural gas properties, and the presentation of our domestic natural gas assets divested in 2013 as discontinued operations. For periods prior to the Acquisition, we have not reflected the domestic natural gas assets divested in 2013 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. As a result, trends and results in future periods are different than those prior to the Acquisition.

        The successor, EPE Acquisition, LLC, had no independent oil and gas operations prior to the Acquisition in 2012 and accordingly there were no operational exploration and production activities that changed as a result of the acquisition of the predecessor, Historical EP Energy Corporation. Consequently, in certain period-to-period explanations that follow we have provided supplemental information that compares (i) results for the six months ended June 30, 2013 with results for the successor period from February 14 (inception) to June 30, 2012 and for the predecessor period from January 1 to May 24, 2012 on a combined basis and excluding divested assets (such combined period is referred to as the "combined six months ended June 30, 2012") and (ii) results from the successor period from February 14 (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 referred to as the "combined year ended December 31, 2012") with results for the year ended December 31, 2011 excluding divested assets. We have provided this additional analysis for comparability of results and to aid in the analysis and understanding of our operating performance period over period. Any non-GAAP analysis is provided as supplemental financial information to our GAAP results and is not intended to be a substitute for our reported successor and predecessor period GAAP results.

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Year-to-Date Period Ended June 30, 2013 to Year-To-Date Period Ended June 30, 2012

 
   
   
   
   
 
 
  Year-to-Date Periods  
 
  2013   2012  
 
  Successor   Successor    
  Predecessor  
 
  Six months
ended
June 30
  February 14
(inception) to
June 30
 



  January 1 to
May 24
 

Operating revenues:

                       

Oil and condensate

  $ 568   $ 74       $ 322  

Natural gas

    215     46         262  

NGLs

    32     4         29  
                   

Total physical sales

    815     124         613  

Financial derivatives

    35     57         365  
                   

Total operating revenues

    850     181         978  
                   

Operating expenses:

                       

Natural gas purchases

    10     4          

Transportation costs

    46     9         45  

Lease operating expense

    98     15         96  

General and administrative

    118     208         75  

Depreciation, depletion and amortization

    277     26         319  

Impairments/Ceiling test charges

    10     1         62  

Exploration expense

    27     6          

Taxes, other than income taxes

    43     10         45  
                   

Total operating expenses

    629     279         642  
                   

Operating income (loss)

    221     (98 )       336  

Earnings (loss) from unconsolidated affiliates

    6     (1 )       (5 )

Other (expense) income

    (1 )   1         (3 )

Loss on extinguishment of debt

    (3 )            

Interest expense

    (178 )   (53 )       (14 )
                   

Income (loss) from continuing operations before income tax

    45     (151 )       314  

Income tax expense

    2             136  
                   

Income (loss) from continuing operations

    43     (151 )       178  

Income from discontinued operations

    44     1          
                   

Net income (loss)

  $ 87   $ (150 )     $ 178  
                   

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Operating Revenues

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

 
   
   
   
   
 
 
  Year-to-Date Periods  
 
  2013   2012  
 
  Successor   Successor    
  Predecessor  
 
  Six months
ended
June 30
  February 14
(inception)
to June 30
 



  January 1 to
May 24
 

Operating revenues(1):

                       

Oil and condensate

  $ 568   $ 74       $ 322  

Natural gas

    215     46         262  

NGLs

    32     4         29  
                   

Total physical sales

    815     124         613  

Financial derivatives

    35     57         365  
                   

Total operating revenues

  $ 850   $ 181       $ 978  
                   

Volumes(1):

                       

Oil and condensate

                       

Consolidated volumes (MBbls)

    5,976     905         3,209  

Unconsolidated affiliate volumes (MBbls)

    136     28         115  

Natural gas

                       

Consolidated volumes (MMcf)

    54,351     17,182         99,158  

Unconsolidated affiliate volumes (MMcf)

    7,317     1,538         6,310  

NGLs

                       

Consolidated volumes (MBbls)

    1,098     147         673  

Unconsolidated affiliate volumes (MBbls)

    229     47         190  

Equivalent volumes

                       

Consolidated MBoe

    16,133     3,915         20,408  

Unconsolidated affiliate MBoe

    1,585     331         1,357  
                   

Total combined MBoe

    17,718     4,246         21,765  
                   

Consolidated MBoe/d

    89                  

Unconsolidated affiliate MBoe/d

    9                  
                       

Total Combined MBoe/d

    98                  
                       

Consolidated prices per unit(2):

                       

Oil and condensate

                       

Average realized price on physical sales ($/Bbl)

  $ 94.97   $ 82.08       $ 100.44  

Average realized price, including financial derivatives ($/Bbl)(3)

  $ 101.44   $ 93.80       $ 99.18  

Natural gas

                       

Average realized price on physical sales ($/Mcf)

  $ 3.77   $ 2.42       $ 2.64  

Average realized price, including financial derivatives ($/Mcf)(3)

  $ 3.49   $ 4.48       $ 4.31  

NGLs

                       

Average realized price on physical sales ($/Bbl)

  $ 28.68   $ 28.87       $ 42.94  

(1)
Operating revenues and volumes in the successor periods do not include those revenues and volumes associated with domestic natural gas assets classified as discontinued operations at June 30, 2013.

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(2)
Natural gas prices for the six months ended June 30, 2013 and six months ended June 30, 2012 are calculated reflecting a reduction of $16 million and $4 million for natural gas purchases in the applicable period associated with managing our physical sales.

(3)
Average realized price, including financial derivatives for successor periods, does not reflect volumes associated with domestic natural gas assets classified as discontinued operations.

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

        Oil and condensate sales for the six months ended June 30, 2013 compared to the combined six months ended June 30, 2012 increased by $172 million (43%), due primarily to oil and volume growth from our Eagle Ford drilling program. In 2013, Eagle Ford production increased by 11 MBbls (or 106%) compared with the year-to-date period ended June 30, 2012.

        Natural gas sales for the six months ended June 30, 2013 and successor period from February 14 (inception) to June 30, 2012 were $215 million and $46 million, respectively, and for the predecessor period from January 1 to May 24, 2012 were $262 million (including approximately $88 million of natural gas sales related to divested assets). Natural gas sales (excluding amounts related to divested assets) remained relatively flat for the six months ended June 30, 2013 compared with the combined six months ended June 30, 2012, primarily due to an increase in average realized natural gas prices which offset the decrease in volumes due to natural production declines in the Haynesville Shale. During the first quarter of 2012, we suspended our drilling program in the Haynesville Shale due to low natural gas prices.

        NGLs sales remained relatively flat for the six months ended June 30, 2013 compared with the combined six months ended June 30, 2012. Average realized prices for the six months ended June 30, 2013 decreased compared to 2012, offset by an increase in NGLs volumes primarily attributable to our Eagle Ford drilling program. Eagle Ford NGLs volumes increased by 3 MBbls/d (or approximately 176%) compared with the year-to-date period ended June 30, 2012.

        As of June 30, 2013, the NYMEX spot price of a barrel of oil was $96.56 versus the NYMEX spot price of natural gas of $3.57, a ratio of 27 to 1. We will continue to target increases in our oil volumes in 2013 due to the value of oil in relation to the value of natural gas, but we also expect volumes of natural gas to decline with less capital focus in this area. Growth in our revenue will largely be impacted by our ability to grow our oil volumes with sustained current prices of oil.

        Realized and unrealized gains or losses on financial derivatives.    We record realized and unrealized gains or losses due to changes in the fair value of our derivative contracts based on forward commodity prices relative to the prices in the underlying contracts. During the six months ended June 30, 2013, we recorded $35 million of derivative losses compared to derivative gains of $422 million during the combined six months ended June 30, 2012.

Operating Expenses

        Transportation costs.    Transportation costs for the six months ended June 30, 2013 and successor period from February 14 (inception) to June 30, 2012 were $46 million and $9 million, respectively, and for the predecessor period from January 1 to May 24, 2012 were $45 million (including $18 million of transportation costs related to divested assets). Total transportation costs (excluding amounts related to divested assets) for the six months ended June 30, 2013 compared to same period in 2012 increased for the six months ended June 30, 2013 due to oil transportation costs associated with our Eagle Ford area as a result of our production growth in that area.

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        Lease Operating Expense.    Lease operating expense for the six months ended June 30, 2013 and successor period from February 14 (inception) to June 30, 2012 were $98 million and $15 million, respectively, and for the predecessor period from January 1 to May 24, 2012 were $96 million (including approximately $31 million related to divested assets). Lease operating expenses for the combined six months ended June 30, 2013 increased over 2012 due to increased equipment and chemical costs in our Eagle Ford area and higher maintenance, repair and power costs.

        General and administrative expenses.    General and administrative expenses for the six months ended June 30, 2013 decreased $165 million compared to the combined six months ended June 30, 2012. The decrease was primarily due to transition and restructuring costs of $183 million recorded in 2012 as a result of the Acquisition offset by an increase of $10 million in 2013 in management consulting and advisory service charges compared to 2012. Prior to the Acquisition, we were allocated general and administrative costs based on the estimated level of resources devoted to our operations and the relative size of our earnings before interest and taxes, gross property and payroll.

        Depreciation, depletion and amortization expense.    Our depreciation, depletion and amortization costs increased in 2013 compared with 2012 due to the ongoing development of higher cost oil programs (e.g. Eagle Ford and Wolfcamp). Our average depreciation, depletion and amortization costs per unit for the year-to-date ended June 30 were:

 
   
   
   
 
 
  Year-to-Date Periods  
 
   
  2012  
 
  2013  
 
   
   
   
 
 
  Successor   Successor    
  Predecessor  
 
   
 
 
  Six months
ended
June 30
  February 14
(inception)
to June 30
   
  January 1 to May 24  

Depreciation, depletion and amortization ($/Boe)(1)

  $ 17.15   $ 6.74       $ 15.62