UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K

(Mark One)

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

For the fiscal year ended December 31, 2012

OR

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

For the transition period from                  to                  .

Commission File Number 333-183815

EP Energy LLC

(Exact Name of Registrant as Specified in Its Charter)

Delaware	45-4871021
(State or Other Jurisdiction of	(I.R.S. Employer
Incorporation or Organization)	Identification No.)

1001 Louisiana Street
Houston, Texas	77002
(Address of Principal Executive Offices)	(Zip Code)

Telephone Number: (713) 997-1200

Internet Website: www.epenergy.com

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

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

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

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

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

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

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

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

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

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

Documents Incorporated by Reference:  None

EP ENERGY LLC

TABLE OF CONTENTS

Caption	Page
PART I
Item 1. Business	1
Item 1A. Risk Factors	18
Item 1B. Unresolved Staff Comments	38
Item 2. Properties	38
Item 3. Legal Proceedings	38
Item 4. Mine Safety Disclosures	38
PART II
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	39
Item 6. Selected Financial Data	40
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations	41
Item 7A. Quantitative and Qualitative Disclosures About Market Risk	58
Item 8. Financial Statements and Supplementary Data	60
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	115
Item 9A. Controls and Procedures	115
Item 9B. Other Information	115
PART III
Item 10. Directors, Executive Officers and Corporate Governance	116
Item 11. Executive Compensation	121
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	142
Item 13. Certain Relationships and Related Transactions, and Director Independence	145
Item 14. Principal Accountant Fees and Services	147
PART IV
Item 15. Exhibits and Financial Statement Schedules	148
Signatures	149

i

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

/d	=	per day
Bbl	=	barrel
Bcf	=	billion cubic feet
Bcfe	=	billion cubic feet of natural gas equivalents
Boe	=	barrel of oil equivalent
LNG	=	liquified natural gas
Mboe	=	thousand barrels of oil equivalent
MBbls	=	thousand barrels
Mcf	=	thousand cubic feet
Mcfe	=	thousand cubic feet of natural gas equivalents
MMBtu	=	million British thermal units
MMBbls	=	million barrels
MMcf	=	million cubic feet
MMcfe	=	million cubic feet of natural gas equivalents
NGL	=	natural gas liquids
TBtu	=	trillion British thermal units
Tcfe	=	trillion cubic feet of natural gas equivalents

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

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

ii

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

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

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

·the company’s 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;

·the company’s ability to comply with the covenants in various financing documents;

·the company’s 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 served by the company, or where operations of the company are located, including the risk of a global recession and negative impact on natural gas demand;

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

·political and currency risks associated with international operations of the company;

·competition; and

·the other factors described under Item 1A, “Risk Factors,” on pages 18 through 37 of this Annual Report on Form 10-K, and any updates to those factors set forth in EP Energy’s subsequent Quarterly Reports on Form 10-Q or Current Report on Form 8-K.

In light of these risks, uncertainties and assumptions, the events anticipated by EP Energy’s 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 EP Energy’s forward-looking statements.  EP Energy’s forward-looking statements speak only as of the date made, and EP Energy undertakes no obligation, other than as required by applicable law, to update or revise its forward-looking statements, whether as a result of new information, subsequent events, anticipated or unanticipated circumstances or otherwise.

iii

PART I

ITEM 1.BUSINESS

Overview

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

We are engaged in the exploration for and the acquisition, development, and production of oil, natural gas and NGL primarily in the United States. We have a large and diverse base of producing assets.  These assets provide cash flow to fund the development of our key programs, which at this time are primarily oil-focused. We allocate capital based on financial returns and value creation.  Over the past five years, our strategy has been to focus our capital investment programs on areas that offer repeatable drilling programs, enabling us to reduce development costs and to grow our asset base, proved reserves, production volumes and inventory size. In that time, we have consistently increased our drilling opportunities and also high-graded our asset base by establishing large acreage positions through producing property acquisitions and acreage acquisitions with repeatable drilling opportunities and more favorable return characteristics, and divesting producing properties that tended to be later in life with less future drilling opportunities.  We intend to continue to high-grade our asset base and remain opportunistic with respect to divesting other assets.

In addition to our inventory of unconventional natural gas resources, we have established a substantial resource base in unconventional oil plays. We currently estimate we have approximately 4,600 drilling locations across our key programs, 83% of which are located in oil-focused reservoirs. The move to oil-focused reservoirs has allowed us to take advantage of higher oil prices and has improved cash flow through commodity diversity. The development of these assets should generate accelerated growth in oil production and reserves and provide us the flexibility to take advantage of strength in either gas or oil commodity price environments. We expect that the oil composition of our portfolio will continue to increase as we develop our key oil programs over the next several years.

Domestically, we operate through three divisions: Eagle Ford, Southern and Central with a strategic presence in well-known oil resource areas, including the Eagle Ford Shale, the Wolfcamp Shale and the Altamont Field. Our large and diverse gas production assets include our Haynesville Shale position primarily in Louisiana, substantially all of which is held by production, which gives us a significant presence in unconventional natural gas.   The technical and operating experience gained from our successful Haynesville program has been employed in our other key programs, including the Eagle Ford and the Wolfcamp shales in south and east Texas. We also have coal bed methane (CBM) assets in the Raton Basin of northern New Mexico and southern Colorado, the Black Warrior Basin in Alabama and the Arkoma in Oklahoma.  Internationally, we have a small presence in Brazil.  Prior to July 2012, we had interests in the Gulf of Mexico and Egypt which were sold.  Our existing assets are geographically diversified among many of the major basins of North America, insulating us to some extent from regional commodity pricing and cost dislocations that occur from time to time. Our producing assets provide a diverse source of cash flow to fund the development of our key programs, reducing our reliance on outside sources of capital and improving our ability to replace and grow production in the future. While our existing producing assets are well diversified, we maintain a focused and concentrated approach with our capital programs that enable us to gain efficiencies, benefit from economies of scale, remain flexible in allocating capital to our most profitable projects and leverage our knowledge base from one project to the next.

1

The following table provides summary oil, natural gas and NGL reserve and production data of each of our areas of operation as of December 31, 2012:

	Estimated Net Proved Reserves					Average
	Bcfe	% Proved Developed		PV- 10(1)		Production MMcfe/d	Approximate Net Acres
	(dollars in millions)
United States
Eagle Ford Shale	1,233	18	%	$	3,826	121	156,000
Southern
Wolfcamp Shale	262	12	%	347		12	138,000
Other Southern(2)	188	96	%	170		87	78,000
Central
Altamont Field	583	35	%	1,777		64	173,000
Haynesville Shale	400	71	%	328		291	41,000
Other Central(3)	805	82	%	451		215	1,248,000
Total United States	3,471	96	%	6,899		790	1,834,000
International
Brazil	80	100	%	172		35	111,000
Total Consolidated	3,551	47	%	7,071		825	1,945,000
Unconsolidated Affiliate(4)	199	93	%	214		55
Total Combined	3,750	49	%	$	7,285	880

(1)PV-10 is considered a non-GAAP measure derived from the standardized measure of discounted future net cash flows of our oil and natural gas properties, 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 for our international operations and income taxes related to our investment in Four Star.  For our domestic operations we are not subject to federal income taxes.  We believe that the presentation of PV-10 is useful to investors because it presents (i) relative monetary significance of our oil and natural gas properties regardless of tax structure and (ii) the relative size and value of our reserves to other companies. We also use this measure when assessing the potential return on investment related to our oil and natural gas properties. PV-10 and the standardized measure of discounted future net cash flows do not purport to present the fair value of our oil, natural gas and NGL reserves.

(2)Other Southern includes our South Texas assets.  Prior to July 2012, this area included our Gulf of Mexico assets (sold in July 2012) with average daily production of 25 Mmcfe/d included in the average total production of 87 Mmcfe/d.

(3)Other Central includes our interests in our South Louisiana Wilcox, Arklatex, and CBM areas.

(4)Represents our approximate 49% equity interest in Four Star.

Approximately 1.6 Tcfe, or 42%, of our total combined proved reserves are proved developed producing assets, which generated an average of 880 MMcfe/d in 2012 from approximately 6,000 wells. As of December 31, 2012, we had 261 MMBbls of proved oil reserves, 40 MMBbls of proved NGL reserves and 1,945 Bcfe of proved natural gas reserves, representing 42%, 6% and 52%, respectively, of our total proved reserves.  During 2012, 59% of our revenues (excluding realized and unrealized gains on financial derivatives) were contributed by oil and NGL versus 38% during 2011, and our oil production grew by approximately 55% in 2012. In 2013, we anticipate that approximately 94% of our capital expenditures will be allocated to our key oil programs.

We have operational control over approximately 76% of our producing wells and 91% of our key program drilling inventory as of December 31, 2012. This control provides us with flexibility around the amount and timing of capital spending and has allowed us to continually improve our capital and operating efficiencies. We also employ a centralized operational structure to accelerate the knowledge transfer around the execution of our drilling and completion programs and to continually enhance our field operations and base production performance. In 2012, we drilled 188 gross wells domestically (155 net) with a success rate of 98%, adding approximately 880 Bcfe of proved reserves at a replacement cost of $1.79 per Mcfe, excluding price revisions, the majority of which was oil.  See Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations — Reserve Replacement Ratio/Reserve Replacement Costs.

2

Key Programs

Eagle Ford Shale.  Beginning in late 2008, we were an early entrant in the Eagle Ford Shale, acquiring interests in LaSalle, Dimmit, Atascosa and Webb counties of south Texas through leasehold acquisitions for less than $1,000 per acre on average. Of our 156,000 net acres, we have approximately 145,000 undeveloped net acres across all Eagle Ford areas including approximately 69,000 net acres under development in our central Eagle Ford area. With our Eagle Ford Shale interests, we have a multi-year future drilling location inventory, favorable crude oil pricing relative to the WTI index and midstream infrastructure with ample take-away capacity. As a result, the Eagle Ford Shale has become one of our key programs and a contributor to the increase in our oil reserves and production. The Eagle Ford central program currently generates the highest economic return in our portfolio.  As of December 31, 2012, we had 1,176 future drilling locations in the Eagle Ford Shale.

During 2012, we invested $943 million in capital expenditures in our Eagle Ford Shale and operated an average of four drilling rigs. As of December 31, 2012, we had 144 net producing wells (143 net operated wells) and are currently running six rigs, with the addition of the sixth rig occurring in early February 2013.  During 2012, we improved the efficiency and productivity of our development program, reducing per-well capital costs by approximately 14% and drilling cycle time by more than 10% as compared to 2011.  Oil production in this area has also grown significantly since the beginning of 2011. Average net production for the year ended December 31, 2012 was 121 MMcfe/d, including 14 Mboe/d of oil production, compared to 40 MMcfe/d (including 5 Mboe/d of oil production) for the year ended December 31, 2011.

Wolfcamp Shale.  In 2009, we successfully leased approximately 138,000 net acres (including approximately 133,000 undeveloped net acres) in the Wolfcamp Shale in the Permian Basin in west Texas. Our operations in the Wolfcamp Shale are focused in Reagan, Crockett, Upton and Irion counties. We were an early entrant in the Wolfcamp Shale, acquiring our interests for less than $1,500 per acre on average. The acreage is prospective for multiple producing zones, including the Upper and Lower Wolfcamp.  We have leveraged our technical and operating expertise that have allowed us to be successful in the Haynesville and Eagle Ford shales.  During most of 2012 we had a single rig focused on delineating the Upper Wolfcamp horizon.  In late 2012 our drilling results led to the decision to move to full development of the Upper Wolfcamp and to begin testing of the Lower Wolfcamp.   As of December 31, 2012, we had 1,292 future drilling locations in the Wolfcamp Shale.

During 2012, we invested $212 million in capital expenditures in our Wolfcamp Shale and operated an average of one drilling rig. As of December 31, 2012, we had 31 net operated producing wells and are currently running three rigs, with the addition of the third rig in January 2013.  Average net production for the year ended December 31, 2012 was 12 MMcfe/d, including 1 Mboe/d of oil production.

Altamont Field.  The Altamont Field is one of our key programs in the Central division where we have approximately 173,000 total net acres, including approximately 58,000 undeveloped acres.  Altamont was initially developed in the 1970s, and we are applying current drilling and stimulation technology to vertically drill and develop this prolific oil area. We have enhanced the value of this field through infill drilling, for which we received regulatory approval in 2008. Our focus in the Altamont Field has been on drilling vertical fractured wells through fractured tight oil sands in the Uinta Basin located in Utah. We have gained operational efficiencies as we have developed the field.  The Altamont Field has a multi-year inventory of future drilling locations, giving us a substantial opportunity for growth in oil production. Since our acreage is predominantly held by production, we have greater flexibility to improve both our costs and technical understanding of this area, while also growing returns. As of December 31, 2012, we had 1,386 future drilling locations in the Altamont Field.

During 2012, we invested $172 million in capital expenditures in the Altamont Field, operated an average of two drilling rigs, and drilled 30 gross wells. As of December 31, 2012, we had 315 net producing wells (308 net operated wells) and are currently running two rigs in the Altamont Field. Average production for the year ended December 31, 2012, was 64 MMcfe/d (including 8 Mboe/d of oil production), compared to 55 MMcfe/d (including 7 Mboe/d of oil production) for the year ended December 31, 2011.

3

Haynesville Shale.  Our most mature horizontal shale program is the Haynesville Shale, where we had existing conventional production as a result of historical development activities in east Texas and north Louisiana. Our operations in the Haynesville Shale are primarily focused in DeSoto Parish and Caddo Parish, Louisiana in the Holly, Bethany Longstreet and Logansport fields. We currently have approximately 41,000 total net acres in this area, including approximately 19,000 undeveloped net acres.  We piloted horizontally drilled wells in the Haynesville Shale, experimenting with different horizontal lateral lengths and fracture stimulation staging, with the objective of delivering optimal capital efficiency, finding costs and returns. Our acreage in the Haynesville Shale is predominately held by production, giving us the flexibility to pace our development and optimize our returns. Furthermore, our operations are surrounded by existing infrastructure, providing take-away access to markets. As of December 31, 2012, we had 805 future drilling locations in the Haynesville and Bossier shales.

During 2012, we invested $92 million in capital expenditures in our Haynesville Shale program. Although we had a very efficient drilling program in the Haynesville Shale, we suspended the program at the end of the first quarter of 2012 due to low natural gas prices. As of December 31, 2012, we had 107 net producing wells (100 net operated wells) in this area. Average production for the year ended December 31, 2012, was 291 MMcfe/d compared to 265 MMcfe/d for the year ended December 31, 2011.

Average Well Characteristics — Key Oil Programs.  The following table describes the characteristics of an average well for the respective key oil areas described above, based on our 2013 capital program and internal engineering estimates (dollars in millions):

	Capital Costs (1)	Initial Production (Boe/d) (1)(2)	Average Working Interest		Average Net Revenue Interest
Eagle Ford Shale, Central	$7.8 – $8.8	550-750	89	%	67	%
Wolfcamp Shale, Upper	6.2 – 7.2	425-500	100		75
Altamont Field	5.0 – 7.0	400-550	81		68

(1) Based on 100% working interest.

(2) Based on initial 30 days of production.

Other Oil and Natural Gas Assets

Domestic. We have a large and diverse base of other domestic producing assets that provides cash flow to fund the development of our key programs. During 2012, we invested $122 million in capital expenditures in the following areas:

South Louisiana Wilcox.  Our South Louisiana Wilcox play we control 130,000 total net acres located primarily in Beauregard Parish focused on the Wilcox Sands. This play is a conventional vertical well play that produces oil, natural gas and NGL from a series of completed sands.  We have over 1,000 square miles of 3-D seismic data in South Louisiana Wilcox. South Louisiana Wilcox has access to Louisiana Light Sweet Crude and Gulf Coast NGL pricing, which has recently traded at a premium relative to the WTI index. In addition, it does not compete for horizontal drilling and completion services due to vertical drilling and completion design.

During most of 2012, we operated one drilling rig in South Louisiana Wilcox.  For the year ended December 31, 2012 we had average daily production of 14 MMcfe/d.  As of December 31, 2012, we had 20 net operated producing wells.  In the fourth quarter of 2012, we idled drilling activity to allow completion of a regional model based on our well results and seismic data.

4

Coal Bed Methane.  Our CBM area includes the Raton Basin of northern New Mexico and southern Colorado, where we own the minerals beneath the Vermejo Park Ranch, the Black Warrior Basin in Alabama, the Arkoma Basin in Oklahoma and a non-operated working interest in the County Line property in Wyoming, with additional non-producing acreage in Colorado, Wyoming, North Dakota and Utah.  As of December 31, 2012, these operations included 1,074,000 total net acres, and for the year ended December 31, 2012 we had average daily production of 144 MMcfe/d.

Arklatex.  Our Arklatex land positions are primarily focused on tight gas sands production in the Travis Peak/Hosston, Bossier and Cotton Valley formations. Our operations are in the Bear Creek, Vacherie Dome, Holly, Bethany, Longstreet, and Bald Prairie fields. As of December 31, 2012, these operations included 44,000 total net acres, and for the year ended December 31, 2012 we had average daily production of 56 MMcfe/d.

South Texas.  Our assets in South Texas include 78,000 total net acres, including approximately 16,000 net undeveloped acres in the Renger and Dry Hollow fields, located in Lavaca County, and the Vicksburg/Frio area, with concentrated and contiguous assets in the Jeffress and Monte Christo fields, primarily in Hidalgo County. These assets also include assets in the Alvarado and Kelsey fields, in Starr and Brooks Counties, and working interests in the Bob West and Roleta fields, located in Zapata County. Other interests in Zapata County include the Bustamante and Las Comitas fields.

As of December 31, 2012, we had 767 net producing wells (751 net operated wells) in this area. Average production for the year ended December 31, 2012 was 87 MMcfe/d (including 25 MMcfe/d of average daily production for the Gulf of Mexico assets sold in July 2012) compared to 124 MMcfe/d (including 46 MMcfe/d of average daily production for the Gulf of Mexico assets) for the year ended December 31, 2011.

Unconsolidated Affiliate — Four Star Oil & Gas Company (Four Star).  We have an approximate 49 percent equity interest in Four Star. Four Star operates in the San Juan, Permian, Hugoton and South Alabama basins and in the Gulf of Mexico. Production is from conventional and CBM assets in several basins. During 2012, our equity interest in Four Star’s daily equivalent natural gas production averaged approximately 55 MMcfe/d.

5

International.  Internationally, our portfolio consists of producing fields along with exploration and development projects in offshore Brazil. Our Brazilian operations are in the Camamu, Espirito Santo and Potiguar basins covering approximately 111,000 net acres. During 2012, we invested $11 million on capital projects in Brazil, and production averaged 35 MMcfe/d. As of December 31, 2012, we have total capitalized costs of approximately $86 million attributable to our operations in Brazil. Achieving success in Brazil requires maintaining strong partner relations and, where necessary, obtaining approvals from regulatory agencies. Our operations in each basin are described below:

·Espirito Santo Basin.  We own an approximate 24% working interest in the Camarupim Field. We have four wells producing in the field, and production in the Camarupim Field averaged approximately 27 MMcfe/d in 2012. We also own a 35% working interest in two areas that are under plans of evaluation, originating from the ES-5 block, which are operated by Petrobras. During May of 2012 we sent Petrobras a Notice of Withdrawal with respect to these two areas.

·Potiguar Basin.  We own a 35% working interest in the Pescada-Arabaiana fields. Our production from these fields averaged approximately 7 MMcfe/d in 2012.

·Camamu Basin.  We own a 100% working interest in two development areas, the Pinauna and Camarao fields. During 2011, we were informed that our environmental permit request for the Pinauna Field in the Camamu Basin was denied by the Brazilian environmental regulatory agency. We have filed an appeal with respect to the denial of this permit and are awaiting a response with respect thereto.

We own a 20% interest in two additional blocks in the Camamu Basin, CAL-M-312 and CAL-M-372. In November of 2012 we sent our partners a Notice of Withdrawal regarding that interest, the terms of which are currently under negotiation.

6

Oil and Natural Gas Properties

Oil and Condensate, Natural Gas and NGL Reserves and Production

The table below presents information about our estimated proved reserves as of December 31, 2012. These reserves 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 Item 1A, Risk Factors. Net proved reserves exclude royalties and interests owned by others and reflect contractual arrangements and royalty obligations in effect at December 31, 2012.

	Net Proved Reserves							2012
	Natural Gas	Oil/Condensate	NGL	Total				Production
	(MMcf)	(MBbls)	(MBbls)	(MMcfe)		(Percent)		(MMcfe)
Reserves and Production by Division
Consolidated:
Proved
U.S.
Eagle Ford	193,043	149,483	23,884	1,233,249		33	%	44,184
Southern	200,282	32,263	9,401	450,261		12	%	36,408
Central	1,333,889	74,496	1,046	1,787,148		48	%	208,529
Total	1,727,214	256,242	34,331	3,470,658		93	%	289,121
Brazil	67,421	2,152	—	80,329		2	%	12,663
Total Consolidated	1,794,635	258,394	34,331	3,550,987		95	%	301,784
Unconsolidated Affiliate(1)	150,508	2,148	5,967	199,198		5	%	20,113
Total Combined	1,945,143	260,542	40,298	3,750,185		100	%	321,897
Reserves by Classification
Consolidated:
Proved Developed
U.S.	1,189,167	55,924	9,080	1,579,191		45	%
Brazil	67,421	2,152	—	80,329		2	%
Total	1,256,588	58,076	9,080	1,659,520	(2)	47	%
Proved Undeveloped
U.S.	538,047	200,318	25,251	1,891,467		53	%
Brazil	—	—	—	—		—	%
Total	538,047	200,318	25,251	1,891,467		53	%
Total Consolidated	1,794,635	258,394	34,331	3,550,987	(2)	100	%
Unconsolidated Affiliate(1):
Proved Developed	140,336	2,111	5,289	184,739		93	%
Proved Undeveloped	10,172	37	678	14,459		7	%
Total Unconsolidated Affiliate(1)	150,508	2,148	5,967	199,198		100	%
Total Combined	1,945,143	260,542	40,298	3,750,185		100	%

(1)Amounts represent our approximate 49 percent equity interest in Four Star.

(2)Includes 1,406 Bcfe of proved developed producing reserves representing 40 percent of consolidated proved reserves and 253 Bcfe of proved developed non-producing reserves representing 7 percent of consolidated proved reserves at December 31, 2012.

Our consolidated reserves in the table above are consistent with estimates of reserves filed with other federal agencies except for differences of less than five percent resulting from actual production, acquisitions, property sales, necessary reserve revisions and additions to reflect actual experience.

7

The table below presents proved reserves as reported and sensitivities related to our estimated proved reserves based on differing price scenarios as of December 31, 2012.

	Net Proved Reserves
	(MMcfe)
As Reported
Consolidated	3,550,987
Unconsolidated Affiliate	199,198
Total Combined	3,750,185
10 percent increase in commodity prices(1)
Consolidated	3,720,791
Unconsolidated Affiliate	204,944
Total Combined	3,925,735
10 percent decrease in commodity prices(1)
Consolidated	3,392,768
Unconsolidated Affiliate	189,258
Total Combined	3,582,026

(1)Based on the first day 12-month average U.S prices of $94.61 per barrel of oil and $2.76 per MMBtu of natural gas used to determine proved reserves at December 31, 2012.

The current 12-month average natural gas prices used to determine our domestic proved reserves at December 31, 2012 are significantly below the 12-month average price used to determine our domestic proved reserves at December 31, 2011. These lower domestic natural gas prices resulted in a downward revision of proved reserves and a corresponding reduction in the discounted future net cash flows from our natural gas proved reserves. This downward revision was offset by our emphasis on the development of oil reserves. The net result was a slight downward revision in total proved equivalent reserves, but an increase in overall reserve value.

We employ a technical staff of engineers and geoscientists that perform technical analysis of each undeveloped location. The staff uses industry accepted practices to estimate, with reasonable certainty, the economically producible oil and natural gas. The practices for estimating hydrocarbons in place include, but are not limited to, mapping, seismic interpretation of two-dimensional and/or three-dimensional data, core analysis, mechanical properties of formations, thermal maturity, well logs of existing penetrations, correlation of known penetrations, decline curve analysis of producing locations with significant production history, well testing, static bottom hole testing, flowing bottom hole pressure analysis and pressure and rate transient analysis.

Our primary internal technical person in charge of overseeing our reserves estimates, including the reserves estimate we prepare related to our investment in Four Star, has a B.S. degree in Petroleum Engineering and is a member of the Society of Petroleum Engineers. He is the executive vice president and chief operating officer of the company.  In this capacity, he is responsible for the company’s operating divisions as well as the Marketing and Business Development groups.  In addition, he oversees the reserve reporting and technical/business excellence groups. He has more than 24 years of industry experience in various domestic and international engineering and management roles. For a discussion of the internal controls over our proved reserves estimation process, see Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations — Critical Accounting Estimates.

Ryder Scott Company, L.P. (Ryder Scott) conducted an audit of the estimates of proved reserves prepared by us as of December 31, 2012. In connection with its audit, Ryder Scott reviewed 81 percent (by value) of the total proved reserves on a natural gas equivalent basis and representing 90 percent of the total discounted future net cash flows of these proved reserves. Ryder Scott also conducted an audit of the estimates we prepared of the proved reserves of Four Star as of December 31, 2012. In connection with the audit of these proved reserves, Ryder Scott reviewed 85 percent of the properties associated with Four Star’s total proved reserves on a natural gas equivalent basis, representing 92 percent of the total discounted future net cash flows. For the reviewed properties, 97 percent of our total PUD reserves were evaluated and our overall proved reserves estimates are within 10 percent of Ryder Scott’s estimates. Ryder Scott’s report is included as an exhibit to this Annual Report on Form 10-K.

8

The technical person primarily responsible for overseeing the reserves audit by Ryder Scott has a B.S. degree in chemical engineering. He is a Licensed Professional Engineer in the State of Texas, a member of the Society of Petroleum Engineers and has more than nine years of experience in petroleum reserves evaluation.

In general, the volume of production from oil and natural gas properties declines as reserves are depleted. Except to the extent we conduct successful exploration and development activities or acquire additional properties with proved reserves, or both, our proved reserves will decline as they are produced. Recovery of PUD reserves requires significant capital expenditures and successful drilling operations. The reserve data assumes that we can and will make these expenditures and conduct these operations successfully, but future events, including commodity price changes, may cause these assumptions to change. In addition, estimates of PUD reserves and proved non-producing reserves are inherently subject to greater uncertainties than estimates of proved producing reserves. For further discussion of our reserves, see Part II, Item 8, Financial Statements and Supplementary Data, under the heading Supplemental Oil and Natural Gas Operations.

We currently have 1,090 PUD locations, of which 632 are in shale areas where we are actively developing reserves. The three shale areas are Eagle Ford, Wolfcamp and Haynesville. At this time we do not have a developed to undeveloped relationship that is beyond one adjacent offset to a productive well.

We assess our PUD reserves on a quarterly basis. At December 31, 2012, we had 1,891 Bcfe of consolidated PUD reserves representing a decrease of 27 Bcfe of PUD reserves compared to December 31, 2011. During 2012, we added 785 Bcfe of PUD reserves primarily due to our drilling activities in the Eagle Ford Shale in our Eagle Ford division, the Wolfcamp Shale in our Southern division and the Haynesville Shale in our Central division. We had 190 Bcfe of PUD reserves transferred to proved developed reserves and negative revisions of 618 Bcfe primarily due to natural gas prices. We divested 4 Bcfe of PUD reserves from the sales of assets throughout the year in our Central and Southern divisions. At this time we have no PUD reserves associated with our International assets.

We spent approximately $587 million, $601 million and $199 million, during 2012, 2011 and 2010, respectively, to convert approximately 10 percent or 190 Bcfe, 17 percent or 210 Bcfe and 11 percent or 94 Bcfe, respectively, of our prior year-end PUD reserves to proved developed reserves. In our December 31, 2012 internal reserve report, the amounts estimated to be spent in 2013, 2014 and 2015 to develop our consolidated worldwide PUD reserves are $924 million, $1,100 million and $1,133 million, respectively. The upward trend in the amounts estimated to be spent to develop our PUD reserves is a result of our shift in capital focus to develop our key programs. The amount and timing of these expenditures will depend on a number of factors, including actual drilling results, service costs and commodity prices.

Of the 1,905 Bcfe of combined PUD reserves at December 31, 2012, less than 1 Bcfe are scheduled to remain undeveloped beyond five years.  The undeveloped reserves scheduled beyond five years are associated with an existing and currently producing well.

9

Acreage and Wells

The following tables detail (i) our interest in developed and undeveloped acreage at December 31, 2012, (ii) our interest in oil and natural gas wells at December 31, 2012 and (iii) our exploratory and development wells drilled during the years 2010 through 2012. Any acreage in which our interest is limited to owned royalty, overriding royalty and other similar interests is excluded.

	Developed		Undeveloped		Total
	Gross(1)	Net(2)	Gross(1)	Net(2)	Gross(1)	Net(2)
Acreage
United States
Eagle Ford	10,931	10,532	152,402	145,247	163,333	155,779
Southern	165,022	67,387	176,809	148,857	341,831	216,244
Central	614,062	476,717	1,296,551	985,051	1,910,613	1,461,768
Total United States	790,015	554,636	1,625,762	1,279,155	2,415,777	1,833,791
Brazil	47,377	14,492	398,732	96,418	446,109	110,910
Worldwide Total	837,392	569,128	2,024,494	1,375,573	2,861,886	1,944,701

(1)Gross interest reflects the total acreage we participate in regardless of our ownership interest in the acreage.

(2)Net interest is the aggregate of the fractional working interests that we have in the gross acreage.

In the United States, our net developed acreage is concentrated primarily in New Mexico (23 percent), Utah (21 percent), Texas (15 percent), Louisiana (14 percent), Oklahoma (13 percent) and Alabama (9 percent). Our net undeveloped acreage is concentrated primarily in New Mexico (35 percent), Texas (23 percent), Louisiana (10 percent), and Colorado (9 percent). Approximately 11 percent, 6 percent and 5 percent of our total United States net undeveloped acreage is held under leases that have minimum remaining primary terms expiring in 2013, 2014 and 2015, respectively. Approximately 76 percent of our total Brazilian net undeveloped acreage is held under leases that have minimum remaining primary terms expiring in 2014. We have sent our partners a Notice of Withdrawal regarding certain of our interests in Brazil with undeveloped acreage totaling approximately 74,000 net acres. We employ various techniques to manage the expiration of leases, including drilling the acreage ourselves prior to lease expiration, entering into farm-out agreements with other operators or extending lease terms.

	Natural Gas		Oil		Total		Wells Being Drilled atDecember 31, 2012(1)
	Gross(2)(3)	Net(4)	Gross (2)	Net(4)	Gross(2)	Net(4)(5)	Gross(2)	Net(4)
Productive Wells
United States
Eagle Ford	4	4	144	140	148	144	25	22
Southern	877	760	39	38	916	798	9	9
Central	4,606	3,292	408	319	5,014	3,611	5	3
Total	5,487	4,056	591	497	6,078	4,553	39	34
Brazil	12	4	2	1	14	5	—	—
Worldwide Total	5,499	4,060	593	498	6,092	4,558	39	34

(1)Includes wells that were spud in 2012 or a prior year and have not been completed.

(2)Gross interest reflects the total wells we participated in, regardless of our ownership interest.

(3)Includes 29 wells with multiple completions.

(4)Net interest is the aggregate of the fractional working interests that we have in the gross wells or gross wells drilled.

(5)At December 31, 2012, we operated 4,118 of the 4,558 net productive wells.

10

	Net Exploratory(1)			Net Development(1)
	2012	2011	2010	2012	2011	2010
Wells Drilled
United States
Productive	20	87	35	132	95	55
Dry(2)	1	—	—	3	—	2
Total	21	87	35	135	95	57
Brazil
Productive	—	—	—	—	—	—
Dry	—	1	—	—	—	—
Total	—	1	—	—	—	—
Worldwide
Productive	20	87	35	132	95	55
Dry	1	1	—	3	—	2
Total	21	88	35	135	95	57

(1)Net interest is the aggregate of the fractional working interests that we have in the gross wells or gross wells drilled.

(2)For 2012, the net exploratory dry well and one net developmental dry well occurred during the predecessor period.

The drilling performance above should not be considered indicative of future drilling performance, nor should it be assumed that there is any correlation between the number of productive wells drilled and the amount of oil and natural gas that may ultimately be recovered.

11

Net Production, Sales Prices, Transportation and Production Costs

The following table details our net production volumes, average sales prices received, average transportation costs, average lease operating expense and average production taxes associated with the sale of oil and natural gas for each of the three years ended December 31:

	2012		2011		2010
Volumes:
Consolidated Net Production Volumes
United States
Oil and condensate (MBbls) (1)	9,131		5,680		4,363
Natural gas (MMcf)(1)	222,906		230,669		215,905
NGL (MBbls) (1)	1,904		1,068		1,423
Total (MMcfe)	289,121		271,157		250,621
Brazil
Oil and condensate (MBbls)	406		354		384
Natural gas (MMcf)	10,230		10,414		9,706
NGL (MBbls)	—		—		—
Total (MMcfe)	12,663		12,539		12,010
Consolidated — Worldwide
Oil and condensate (MBbls)	9,537		6,034		4,747
Natural gas (MMcf)	233,136		241,083		225,611
NGL (MBbls)	1,904		1,068		1,423
Total (MMcfe)	301,784		283,696		262,631
Total (MMcfe/d)	825		777		720
Unconsolidated Affiliate Volumes(2)
Oil and condensate (MBbls)	282		306		364
Natural gas (MMcf)	15,552		16,881		17,165
NGL (MBbls)	478		556		573
Total equivalent volumes (MMcfe)	20,113		22,052		22,787
MMcfe/d	55		61		62
Total Combined Volumes(2)
Oil and condensate (MBbls)	9,819		6,340		5,111
Natural gas (MMcf)	248,688		257,964		242,776
NGL (MBbls)	2,382		1,624		1,996
Total equivalent volumes (MMcfe)	321,897		305,748		285,418
MMcfe/d	880		838		782
Consolidated Prices and Costs per Unit
Oil and Condensate Average Realized Sales Price ($/Bbl)
United States
Physical sales	$	92.55	$	90.22	$	72.37
Including financial derivatives(3)	$	97.49	$	88.98	$	70.52
Brazil
Physical sales	$	108.81	$	110.33	$	78.02
Including financial derivatives(3)	$	108.81	$	110.33	$	78.02
Worldwide
Physical sales	$	93.25	$	91.40	$	72.83
Including financial derivatives(3)	$	97.97	$	90.23	$	71.13
Natural Gas Average Realized Sales Price ($/Mcf)
United States
Physical sales	$	2.62	$	3.91	$	4.26
Including financial derivatives(3)	$	4.15	$	5.37	$	5.71
Brazil
Physical sales	$	7.66	$	6.94	$	5.65
Including financial derivatives(3)	$	7.66	$	6.94	$	4.93
Worldwide

12

	2012		2011		2010
Physical sales	$	2.84	$	4.04	$	4.32
Including financial derivatives(3)	$	4.30	$	5.44	$	5.67
NGL Average Realized Sales Price ($/Bbl)
United States
Physical sales	$	39.96	$	53.50	$	42.38
Worldwide
Physical sales	$	39.96	$	53.50	$	42.38
Average Transportation Costs
United States
Oil and condensate ($/Bbl)(4)	$	1.91	$	0.06	$	0.09
Natural gas ($/Mcf)	$	0.40	$	0.35	$	0.31
NGL ($/Bbl)(4)	$	5.41	$	3.83	$	3.16
Worldwide
Oil and condensate and($/Bbl) (4)	$	1.82	$	0.06	$	0.08
Natural gas ($/Mcf)	$	0.39	$	0.33	$	0.30
NGL ($/Bbl) (4)	$	5.41	$	3.83	$	3.16
Average Production Costs (Lease Operating Expenses) ($/Mcfe)
United States	$	0.66	$	0.65	$	0.62
Brazil	$	3.27	$	3.29	$	3.07
Worldwide	$	0.77	$	0.77	$	0.73
Average Production Taxes ($/Mcfe)
United States	$	0.29	$	0.26	$	0.21
Brazil	$	0.93	$	0.91	$	0.73
Worldwide	$	0.32	$	0.28	$	0.27

(1)For the years ended December 31, 2012, 2011 and 2010, the Eagle Ford Field had oil and condensate volumes of 5,022 MMBbls, 1,702 MMBbls and 177 MMBbls, natural gas volumes of 8,425 MMcf, 3,094 MMcf and 947 MMcf, and NGL volumes of 937 MMBbls, 207 MMBbls and 30 MMBbls, respectively. For the years ended December 31, 2012, 2011 and 2010, the Altamont Field, within the Central division, had oil and condensate volumes of 2,765 MMBbls, 2,385 MMBbls and 2,273 MMBbls, natural gas volumes of 6,632 MMcf, 5,677 MMcf and 4,915 MMcf, and NGL volumes of 5 MMBbls, 7 MMBbls and 5 MMBbls, respectively.

(2)Represents our approximate 49 percent equity interest in the volumes of Four Star.

(3)Amounts reflect settlements on derivative instruments, excluding premiums paid. During the years ended December 31, 2012, 2011 and 2010, no cash premiums were paid related to oil derivatives settled.  During the year ended December 31, 2012 no cash premiums were paid related to natural gas derivatives settled whereas during the years ended December 31, 2011and 2010, these premiums were $23 million and $157 million.  Had these premiums been included in the natural gas average realized prices in 2011 and 2010, the realized price, including financial derivative settlements, would have decreased by $0.10/Mcf and $0.70/Mcf for the years ended December 31, 2011 and 2010.

(4)Increase in 2012 primarily related to our Eagle Ford division.

13

Acquisition, Development and Exploration Expenditures

The following table details information regarding the capital expenditures in our acquisition, development and exploration activities for each of the three years ended December 31:

	Successor		Predecessor
	March 23 (inception) to December 31, 2012		January 1 to May 24,2012		2011		2010
			(In millions)
United States(1)
Acquisition Costs:
Proved	$	—	$	—	$	—	$	51
Unproved	20		31		45		269
Development Costs	787		503		694		276
Exploration Costs:
Delay rentals	6		8		8		9
Seismic acquisition and reprocessing	23		20		32		15
Drilling	91		51		818		576
Asset Retirement Obligations	28		21		25		7
Total oil and natural gas expenditures	955		634		1,622		1,203
Non-oil and natural gas expenditures	15		3		18		35
Total capital expenditures	$	970	$	637	$	1,640	$	1,238
Brazil and Egypt(2)
Development Costs	$	3	$	—	$	12	$	28
Exploration Costs:
Seismic acquisition and reprocessing	6		—		9		6
Drilling	—		3		6		52
Asset Retirement Obligations	3		10		—		—
Total oil and natural gas expenditures	12		13		27		86
Non-oil and natural gas expenditures	—		—		2		1
Total capital expenditures	$	12	$	13	$	29	$	87
Worldwide(1) (2)
Acquisition Costs:
Proved	$	—	$	—	$	—	$	51
Unproved	20		31		45		269
Development Costs	790		503		706		304
Exploration Costs:
Delay rentals	6		8		8		9
Seismic acquisition and reprocessing	29		20		41		21
Drilling	91		54		824		628
Asset Retirement Obligations	31		31		25		7
Total oil and natural gas expenditures	967		647		1,649		1,289
Non-oil and natural gas expenditures	15		3		20		36
Total capital expenditures	$	982	$	650	$	1,669	$	1,325

(1)Includes total capital expenditures for the Gulf of Mexico which were less than $1 million for the successor period from March 23 (inception) to December 31, 2012 and less than $1 million, $18 million and $69 million for the predecessor periods from January 1 to May 24, 2012 and the years ended December 31, 2011 and 2010. In July of 2012, we sold our Gulf of Mexico assets.

(2)Includes total capital expenditures for Egypt which were less than $1 million for the successor period from March 23, 2012 to December 31, 2012 and $2 million, $8 million and $20 million for the predecessor periods from January 1, 2012 to May 24, 2012 and the years ended December 31, 2011 and 2010. In June of 2012, we sold our Egyptian interests.

14

Markets and Competition

We primarily sell our domestic oil and natural gas to third parties at spot market prices, subject to customary adjustments. We sell our NGL at market prices under monthly or long-term contracts, subject to customary adjustments. In Brazil, we sell the majority of our oil and natural gas under long-term contracts to Petrobras. These long-term contracts include a gas sales agreement and a condensate sales agreement. The gas sales agreement provides for a price that adjusts quarterly based on a basket of fuel oil prices, while the condensate sales agreement provides for a price that adjusts monthly based on a Brent crude price less a fixed differential that will adjust annually. The gas sales agreement also includes a minimum daily delivery commitment of our natural gas production. The current delivery commitment is approximately 16 MMcf/d and can be modified on an annual basis depending on the production capacity of the subject wells. We do not anticipate being unable to meet the delivery commitment. We enter into derivative contracts on our oil and natural gas production to stabilize our cash flows, reduce the risk and financial impact of downward commodity price movements and protect the economic assumptions associated with our capital investment programs. For a further discussion of these derivative contracts, see Part II, Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations.

The exploration and production business is highly competitive in the search for and acquisition of additional oil and natural gas reserves and in the sale of oil, natural gas and NGL. Our competitors include major and intermediate sized oil and natural gas companies, independent oil and natural gas operators and individual producers or operators with varying scopes of operations and financial resources. Competitive factors include price and contract terms, our ability to access drilling, completion and other equipment and our ability to hire and retain skilled personnel on a timely and cost effective basis. Ultimately, our future success in this business will be dependent on our ability to find or acquire additional reserves at costs that yield acceptable returns on the capital invested.

Regulatory Environment

Our oil and natural gas exploration and production activities are regulated at the federal, state and local levels in the United States and Brazil. These regulations include, but are not limited to, those governing the drilling and spacing of wells, conservation, forced pooling and protection of correlative rights among interest owners.  We are also subject to various governmental safety and environmental regulations in the jurisdictions in which we operate.

Our domestic operations under federal oil and natural gas leases are regulated by the statutes and regulations of the U.S. Department of the Interior that currently impose liability upon lessees for the cost of environmental impacts resulting from their operations. Royalty obligations on all federal leases are regulated by the Office of Natural Resources Revenue within the Department of Interior, which has promulgated valuation guidelines for the payment of royalties by producers. Our exploration and production operations in Brazil are subject to environmental regulations administered by that government, which include political subdivisions in that country. These domestic and international laws and regulations affect the construction and operation of facilities, water disposal rights, drilling operations, production or the delay or prevention of future offshore lease sales.  In addition, we maintain insurance to limit exposure to sudden and accidental pollution liability exposures.

Hydraulic Fracturing. Hydraulic fracturing is the well stimulation technique we use to maximize productivity of our oil and natural gas wells in most of our domestic basins, including in our Haynesville, Eagle Ford, Wolfcamp, Altamont, Wilcox, Raton and Black Warrior programs. We currently do not use hydraulic fracturing in our Arkoma program. Our net acreage position in basins in which hydraulic fracturing is utilized total approximately 2 million acres. Approximately 98 percent of our domestic proved undeveloped oil and natural gas reserves are subject to hydraulic fracturing. During 2012, we incurred costs of approximately $400 million associated with hydraulic fracturing.

15

Hydraulic fracturing fluid is typically composed of over 99 percent water and proppant, which is usually sand. The other one percent or less of the fluid is composed of additives that may contain acid, friction reducer, surfactant, gelling agent and scale inhibitor. We retain service companies to conduct such operations and we have worked with several service companies to evaluate, test and, where appropriate, modify our fluid design to reduce the use of chemicals in our fracturing fluid. We have worked closely with our service companies to provide voluntary and regulatory disclosure of our hydraulic fracturing fluids.

In order to protect surface and groundwater quality during the drilling and completion phases of our operations, we follow applicable industry practices and legal requirements of the applicable state oil and natural gas commissions with regard to well design, including requirements associated with casing steel strength, cement strength and slurry design. Our activities in the field are monitored by state and federal regulators. Key aspects of our field protection measures include: (i) pressure testing well construction and integrity, (ii) casing and cementing practices to ensure pressure management and separation of hydrocarbons from groundwater, and (iii) public disclosure of the contents of hydraulic fracture fluids.

In addition to these measures, our drilling, casing and cementing procedures are designed to prevent fluid migration, which typically include some or all of the following:

·Our drilling process executes several repeated cycles conducted in sequence—drill, set casing, cement casing and then test casing and cement for integrity before proceeding to the next drilling interval.

·Conductor casing is drilled and cemented or driven in place. This string serves as the structural foundation for the well. Conductor casing is not necessary or required for all wells.

·Surface casing is set generally within the conductor casing, and is cemented in place. Surface casing is set for all wells. The purpose of the surface casing is to contain wellbore fluids and pressure and protect Underground Sources of Drinking Water (USDW) as identified by federal and state regulatory bodies. The surface casing and cement isolates wellbore materials from any potential contact with USDW’s.

·Intermediate casing is set through the surface casing to a depth necessary to isolate abnormally pressured subsurface formations from normally pressured formations. Intermediate casing is not necessary or required for all wells. Our standard practices include (a) cementing above any hydrocarbon bearing zone and (b) performing casing pressure and other tests to verify the integrity of the casing and cement.

·Production casing is set through the surface and intermediate casing through the depth of the targeted producing formation. Our standard practices include (a) pumping cement above the confining structure of the target zone and (b) performing casing pressure tests and other tests to verify the integrity of the casing and cement. If any problems are detected, then appropriate remedial action is taken.

·With the casing set and cemented, a barrier of steel and cement is in place that is designed to isolate the wellbore from surrounding geologic formations. This barrier as designed mitigates against the risk of drilling or fracturing fluids entering potential sources of drinking water.

In addition to the required use of casing and cement in the well construction, we follow additional regulatory requirements and industry operating practices. These typically include (a) pressure testing of casing and surface equipment, (b) continuous monitoring of surface pressure, pumping rates, volumes of fluids and chemical concentrations, and (c) continuous monitoring of well pressure during hydraulic fracturing operations. When any pressure differential outside the normal range of operations occurs, pumping is shut down until the cause of the pressure differential is identified and any required remedial measures are completed. Hydraulic fracturing fluid is delivered to our sites in accordance with Department of Transportation (“DOT”) regulations in DOT approved shipping containers using DOT transporters.

We also have procedures to address water use and disposal. This includes evaluating surface and groundwater sources, commercial sources, and potential recycling and reuse of treated water sources. When commercially and technically feasible, we use recycled or treated water. This practice helps mitigate against potential adverse impacts to other water supply sources. When using raw surface or groundwater, we obtain all required water rights or compensate owners for water consumption. We are evaluating additional treatment capability to augment future water supplies at several of our sites. During our drilling operations, we manage waste water to minimize risks and costs. Frac water or flowback water returned to the surface is typically contained in steel tanks or pits. Water that is not treated for reuse is usually piped or trucked to waste disposal injection wells,

16

many of which we own and operate. These wells are permitted through Underground Injection Control (UIC) program of the Safe Drinking Water Act. We also use commercial injection facilities for frac fluid disposal, which typically dispose of the frac fluids in permitted injection disposal wells. In Alabama, we operate a water treatment disposal facility with a permitted surface discharge. This facility is regulated by the National Pollutant Discharge Elimination System (NPDES) program under the jurisdiction of Alabama Department of Environmental Management.

We have not received regulatory citations or notice of suits related to our hydraulic fracturing operations for environmental concerns. We have experienced no material incidents of surface spills of fluids associated with hydraulic fracturing. Consistent with local, state and federal requirements, any releases were reported to appropriate regulatory agencies and site restoration was completed. No remediation reserve has been identified or anticipated as a result of these incidents.

Spill Prevention/Response Procedures. There are various state and federal regulations that are designed to prevent and respond to any spills or leaks resulting from exploration and production activities. In this regard, we maintain spill prevention control and countermeasures programs, which frequently include the installation and maintenance of spill containment devices designed to contain spill materials on location. In addition, we maintain emergency response plans to minimize potential environmental impacts in the event of a spill or leak or any material hydraulic fracturing well control issue.

Environmental

A description of our environmental remediation activities is included in Part II, Item 8, Financial Statements and Supplementary Data, Note 8.

Employees

As of February 25, 2013, we had 991 full-time employees, of which 35 employees are subject to collective bargaining arrangements.

Available Information

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

17

ITEM 1A. RISK FACTORS

Risks Related to Our Business and Industry

The supply and demand for oil, natural gas and NGL 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 NGL which will depend on many other factors outside of our control, which include, among others:

·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 NGL;

·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 natural gas, including potential restrictive regulations associated with hydraulic fracturing operations;

·adoption of various energy efficiency and conservation measures;

·increased prices of oil, natural gas or NGL 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 NGL that may be caused by the wider spread between oil and natural gas prices;

·competition from imported LNG and Canadian supplies and alternate fuels; and

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

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

18

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

·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 NGL;

·weather conditions;

·technological advances affecting energy consumption and energy supply;

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

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

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

·the effect of LNG deliveries to 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 NGL prices may adversely impact the value of our proved reserves and, in turn, the bank pricing used by our lenders to determine our borrowing base. Any of these factors could negatively impact our liquidity, our ability to replace our production and our future rate of growth. On the other hand, increases in these commodity prices may be offset by increases in drilling costs, production taxes and lease operating costs that typically result from any increase in such commodity prices. Any of these outcomes could have a material adverse effect on our business, results of operations and financial condition.

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.

19

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 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, for commodity price and basis risks, we do not typically hedge all of these exposures beyond several years. As a result, we have substantial commodity price and basis exposure since our business has multi-year drilling programs for our proved reserves and unproved resources.

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

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

·when production is less than expected;

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

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

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

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

In addition, our commodity derivative activities could have the effect of reducing our revenue and net income. As of December 31, 2012, the net unrealized asset represented by our hedging contracts was $165 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.

20

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, or 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 and mandates that the Commodity Futures Trading Commission, or CFTC, adopt rules or regulations implementing the Dodd-Frank Act and providing definitions of terms used in the Dodd-Frank Act. The Dodd-Frank Act establishes margin requirements and requires clearing and trade execution practices for certain market participants and may result in certain market participants needing to curtail or cease their derivatives activities. Although many of the rules necessary to implement the Dodd-Frank Act remain to be adopted, the CFTC has issued a large number of rules to implement the Dodd-Frank Act, including a rule establishing an “end-user” exception to mandatory clearing, or the End-User Exception, and a rule imposing position limits, or the Position Limit Rule.

We currently anticipate that we will qualify as a “non-financial entity” for purposes of the End-User Exception and, as such, we will be eligible for and expect to utilize such exception and, as a result, our hedging activity will not be subject to mandatory clearing or the margin requirements imposed in connection with mandatory clearing. However, most if not all of our hedge counterparties will be subject to mandatory clearing in connection with their hedging activities with parties who do not qualify for the End-User Exception. The Position Limit Rule was vacated and remanded to the CFTC for further proceedings by order of the United States District Court for the District of Columbia, U.S. District Judge Robert L. Wilkins on September 28, 2012. The Dodd-Frank Act, the rules which have been adopted and not vacated, and, to the extent that a position limit rule is ultimately effected, such position limit rule 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 replace our production. We have established a capital budget for 2013 between $1.7 billion and $1.8 billion and we intend to rely on cash flow from operating activities and borrowings under the RBL Facility as our primary sources of liquidity. We also may engage in asset sale transactions to 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 replace our reserves or maintain our 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, or if we have a downward revision in estimates of our proved reserves, our borrowing base may be reduced.

21

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

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

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

The oil, natural gas and NGL 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 NGL 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.

22

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, property could be damaged and/or customer information could be stolen 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 (such as damage from collisions with vessels in our offshore exploration and production operations in Brazil); 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 may encounter additional marine perils, including adverse weather conditions, damage from collisions with vessels, and governmental regulations (including interruption or termination of drilling rights by governmental authorities based on environmental, safety and other considerations).

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

23

Some of our operations are subject to joint ventures or operations by third parties, which could negatively impact our control over these operations, and our inability to maintain these relationships and find appropriate partners for our operations in the future could 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. The most significant joint venture is our approximate 49% equity interest in Four Star. Although we operate the substantial majority of the properties in our business, certain of the properties are operated by our joint venture partners or other third-party working interest owners. In certain cases, (a) we have limited ability to influence or control the day-to-day operation of such properties, including compliance with environmental, safety and other regulations, (b) we cannot control the amount of capital expenditures that we are required to fund with respect to properties, (c) we are dependent on third parties to fund their required share of capital expenditures and (d) 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 are subject to a complex set of laws and regulations that regulate the energy industry for which we have to incur substantial compliance and remediation costs.

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

·the location of wells;

·methods of drilling and completing wells;

·allowable production from wells;

·unitization or pooling of oil and gas properties;

·spill prevention plans;

·limitations on venting or flaring of natural gas;

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

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

·plugging and abandoning of wells;

·air quality, noise levels and related permits;

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

·taxation; and

·competitive bidding rules on federal and state lands.

24

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

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

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

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

25

The Sponsors and other investors own substantially all of the equity interests in us may have conflicts of interest with us and or the holders of our notes in the future.

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

Additionally, the Sponsors and such other investors are in the business of making investments in companies and may from time to time acquire and hold interests in businesses that compete directly or indirectly with us or that supply us with goods and services. These persons may also pursue acquisition opportunities that may be complementary to (or competitive with) our business, and as a result those acquisition opportunities may not be available to us. In addition, the Sponsors’ and other investors’ interests in other portfolio companies could impact our ability to pursue acquisition opportunities. See Part III, Item 13, Certain Relationships and Related Transactions, and Director Independence.

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 are not protected by 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 these individuals 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 could result in the inability to implement our business plans.

Our business requires the retention and recruitment of a skilled workforce including engineers, technical personnel, geoscientists and land personnel and other professionals. We compete with other companies in the energy industry for this skilled workforce. We have developed firm-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 (a) retain our current employees, (b) successfully complete our knowledge transfer and/or (c) 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.

26

Skilled labor shortages and increased labor costs could negatively impact our profitability.

We may be affected by skilled labor shortages of certain types of technical or qualified personnel, including engineers, geo-professionals, project managers, field supervisors and other technical or qualified personnel, 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.

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 (such as if our access to capital resources becomes 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 natural gas and oil 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 producible reservoirs, we either may not fully recover our investments or that our rates of return will be less than expected. We are also subject to the risk that we encounter unexpected drilling conditions. 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 exploring for the reserves in these regions or in developing the reserves that are found. 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.

27

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

·unexpected drilling conditions;

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

·unexpected pressure or irregularities in geological formations;

·equipment failures or accidents;

·fracture stimulation accidents or failures;

·adverse weather conditions;

·declines in oil and natural gas prices;

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

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

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

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

Additionally, the occurrence of certain of these events 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 result in our inability to realize an acceptable return on our investments in such projects. The additional production and reserves, if any, attributable to the use of enhanced recovery methods are inherently difficult to predict. If our enhanced recovery methods do not allow for the extraction of natural gas and oil in a manner or to the extent that we anticipate, we may not realize an acceptable return on our investments in such projects. Further, 2-D and 3-D seismic data that we obtain is subject to interpretation and may not accurately identify the presence of natural gas, which could also negatively impact the results of our drilling operations.

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 drilling and completion techniques as developed by us and our service providers in order to maximize cumulative recoveries and therefore generate the highest possible returns. Risks that we face while drilling include, but are not limited to, landing our well bore in the desired drilling zone, staying in the desired drilling zone while drilling horizontally through the formation, running our casing the entire length of the well bore and being able to run tools and other equipment consistently through the horizontal well bore. Risks that we face while completing our wells include, but are not limited to, being able to fracture stimulate the planned number of stages, being able to run tools the entire length of the well bore during completion operations and successfully cleaning out the well bore after completion of the final fracture stimulation stage.

28

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 long time period. If our drilling results are less than anticipated or we are unable to execute our drilling program because of capital constraints, lease expirations, limited access to gathering systems and takeaway capacity, and/or oil and natural gas prices decline, 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 NGL in commercially viable quantities.

We describe potential drilling locations and our plans to explore those potential drilling locations in this 10-K. These potential drilling locations are in various stages of evaluation, ranging from a location which is ready to drill to a location that will require substantial additional interpretation. There is no way to predict in advance of drilling and testing whether any particular location will yield oil, natural gas or NGL 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 NGL will be present or, if present, whether oil, natural gas or NGL will be present in sufficient quantities to be economically viable. Even if sufficient amounts of oil, natural gas or NGL 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. In summary, 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. In addition, we may not be able to raise the significant amount of capital that would be necessary to drill a substantial portion of our potential drilling locations.

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 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 NGL 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 NGL from these or any other potential drilling locations. Pursuant to existing SEC rules and guidance, subject to limited exceptions, proved undeveloped reserves may only be booked if they relate to wells scheduled to be drilled within five years of the date of booking. These rules and guidance may limit our potential to book additional proved undeveloped reserves as we pursue our drilling program.

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

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

29

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

The marketability of our oil, natural gas and NGL 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 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:

·some of the acquired businesses or properties 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;

·properties we acquire may be 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;

·acquisitions could disrupt our ongoing business, distract management, divert resources and make it difficult to maintain our current business standards, controls and procedures;

·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;

·an inability to implement uniform standards, controls, procedures and policies;

·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;

·potential loss of key customers; and

·potential loss of key employees, including costly litigation resulting from the termination of those employees.

30

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

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, losses and impairments.

All estimates of proved reserves are determined according to the rules prescribed by the SEC. Our reserve information was prepared internally and was audited by an independent petroleum consultant. There are numerous uncertainties involved in estimating proved reserves, which may result in these estimates varying considerably from actual results. Estimating quantities of proved reserves is complex and involves significant interpretations 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 10-K 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.

31

A portion of our proved reserves are undeveloped. Recovery of undeveloped reserves requires significant capital expenditures and successful drilling operations. In addition, as the portion of our proved reserve base that consists of unconventional resources increases, 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.

In addition, if our cash flows or the borrowing base under the RBL Facility decrease as a result of lower oil and natural gas prices, operating difficulties, declines in reserves or for any other reason, we may be required to seek additional debt or equity financing to sustain our operations at current levels. If we are unable to secure sufficient capital to meet our capital requirements, we may be required to curtail operations, which could lead to a possible decline in our reserves and could have a material adverse effect on our business, results of operations and financial condition.

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

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

In addition, there have been various legislative and regulatory proposals at the federal and state levels to address climate change and to regulate greenhouse gas (“GHG”) emissions. The EPA and several state environmental agencies have already adopted regulations to regulate GHG emissions. Although natural gas as a fuel supply for power generation has the least GHG emissions of any fossil fuel, it is uncertain at this time what impact the existing and proposed regulations will have on the demand for natural gas and on our operations. This impact will largely depend on what regulations are ultimately adopted, including the level of any emission standards, the amount and costs of allowances, offsets and credits granted and any incentives and subsidies provided to other fossil fuels, nuclear power and renewable energy sources. The EPA has adopted a “Tailoring

32

Rule” concerning regulation of large emitters of GHGs under the Clean Air Act’s Prevention of Significant Deterioration (“PSD”) and Title V programs. This rule tailors these permitting programs to apply to certain stationary sources of GHG emissions in a multi-step process, with the largest sources subject to permitting first. Facilities required to obtain PSD permits for their GHG emissions will also be required to meet “best available control technology” standards, which will be established by states or, in some instances, the EPA on a case-by-case basis. At this time we do not expect the Tailoring Rule to materially impact our operations. There have also been various legislative and regulatory proposals at the federal and state levels to address various emissions from coal-fired power plants. Although such proposals will generally favor the use of natural gas-fired power plants over coal-fired power plants, it remains uncertain what regulations will ultimately be adopted and when they will be adopted. In addition, any regulations regulating GHG emissions would likely increase our costs of compliance by requiring us to monitor such emissions, to install additional equipment to reduce carbon emissions and possibly to purchase emission credits. Any such regulations also could potentially delay the receipt of permits and other regulatory approvals. While we may be able to include some or all of the costs associated with our environmental liabilities and environmental compliance in the prices at which we sell oil, natural gas and NGL, our ability to recover such costs is uncertain and may depend on events beyond our control.

In addition to the EPA initiatives, the U.S. Congress has considered legislation that would establish a nationwide cap-and-trade system for GHGs. If enacted, such laws and regulations could require us to modify existing, or obtain new, permits, implement additional pollution control technology, curtail operations or increase significantly our operating costs.

Regulation of GHG emissions could also result in reduced demand for our products, as oil and natural gas consumers seek to reduce their own GHG emissions. Any regulation of GHG emissions, including through a cap-and-trade system, technology mandate, emissions tax, reporting requirement or other program, could have a material adverse effect on our business, results of operations and financial condition. In addition, to the extent climate change results in more severe weather and significant physical effects, such as increased frequency and severity of storms, floods, droughts and other climatic effects, our own, our counterparties’ or our customers’ operations may be disrupted, which could result in a decrease in our available products or reduce our customers’ demand for our products.

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

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. 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

33

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 a recent explosion on an offshore platform of a third party 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, 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 currently use hydraulic fracturing extensively in all of our key programs. Hydraulic fracturing typically involves the injection of water, sand and additives under pressure into rock formations in order to stimulate hydrocarbon production. We find that the use of hydraulic fracturing is necessary to produce commercial quantities of oil and natural gas from many of the reservoirs in which we operate. Recently, there have been a number of initiatives and proposed initiatives at the federal, state and local level to ban or regulate hydraulic fracturing and to study the environmental impacts of hydraulic fracturing and the need for further regulation of the practice. For example, debate has intensified over whether certain of the chemical constituents in hydraulic fracturing fluids may contaminate drinking water supplies, with some members of Congress and others proposing to revisit the exemption of hydraulic fracturing from the permitting requirements of the Safe Drinking Water Act (the “SDWA”). Eliminating this exemption could establish an additional level of regulation and permitting at the federal level that could lead to operational delays or increased operating costs and could result in additional regulatory burdens that could make it more difficult to perform hydraulic fracturing and increase our costs of compliance and doing business. Even in the absence of new legislation, the EPA recently asserted the authority to regulate hydraulic fracturing involving the use of diesel additives under the SDWA’s Underground Injection Control Program.

34

Scrutiny of hydraulic fracturing activities continues in other ways, with the EPA having commenced a multi-year study of the potential environmental impacts of hydraulic fracturing on drinking water, the final draft report of which is anticipated to be available in 2014. Hydraulic fracturing operations require the use of water and the disposal or recycling of water that has been used in operations. The federal Clean Water Act (the “CWA”) restricts the discharge of produced waters and other pollutants into waters of the United States and requires permits before any pollutants may be discharged. The CWA and comparable state laws and regulations provide for penalties for unauthorized discharges of pollutants including produced water, oil, and other hazardous substances. Compliance with and future revisions to requirements and permits governing the use, discharge, and recycling of water used for hydraulic fracturing may increase our costs and cause delays, interruptions or terminations of our operations which cannot be predicted.

The EPA has also taken actions to regulate air emissions from hydraulic fracturing operations. On August 16, 2012, EPA published regulations in the Federal Register pursuant to the federal Clean Air Act to reduce various air pollutants from the oil and natural gas industry. These regulations will limit emissions from the hydraulic fracturing of certain natural gas wells and from certain equipment including compressors, storage vessels and natural gas processing plants. These regulations require reduction of flowback emissions from gas wells effective October 15, 2012 and use of “green completions” effective January 1, 2015. We have developed plans to comply with the new regulations.

Several states have also adopted or are considering legislation requiring the disclosure of fracturing fluids and other restrictions on hydraulic fracturing operations, including states in which we operate. The DOI is also considering disclosure requirements or other mandates for hydraulic fracturing on federal land, which, if adopted, would affect our operations on federal lands. The Department of Energy (the “DOE”) is also considering whether to implement actions to lessen the environmental impact associated with hydraulic fracturing operations. Initiatives by the EPA and other federal and state regulators to expand their regulation of hydraulic fracturing, together with the possible adoption of new federal or state laws or regulations that significantly restrict hydraulic fracturing, could result in delays, eliminate certain drilling and injection activities, make it more difficult or costly for us to perform hydraulic fracturing, increase our costs of compliance and doing business, and delay or prevent the development of unconventional hydrocarbon resources from shale and other formations that are not commercial without the use of hydraulic fracturing. In addition, there have been proposals by non-governmental organizations to restrict certain buyers from purchasing oil and natural gas produced from wells that have utilized hydraulic fracturing in their completion process, which could negatively impact our ability to sell our production from wells that utilized these fracturing processes.

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.

35

EP Energy LLC is classified as an entity disregarded for U.S. federal income tax purposes. As a result, EP Energy LLC does not pay U.S. federal, state or local income tax; rather, the direct and indirect owners must report and pay U.S. federal, state and local income tax on their distributive share of the income, gain, loss, deduction and credit recognized. Changes in U.S. federal and applicable state and local income tax law (such as the proposals listed above) may increase the U.S. federal and applicable state and local income tax liability of the direct and indirect owners and EP Energy LLC may be obligated to distribute greater amounts indirectly to such owners on account of such increased U.S. federal and applicable state and local income tax liability.

Our Brazilian operations involve special risks.

Our activities in Brazil are subject to the risks inherent in foreign operations and other additional risks not associated with assets located in the United States, which include, among others:

·protracted delays in securing government consents, permits, licenses, customer authorizations or other regulatory approvals necessary to conduct our operations, including those required in Brazil for the Pinauna project;

·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;

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

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

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

In addition, the credit markets and the financial services industry in recent years has experienced a period of unprecedented turmoil and upheaval characterized by the bankruptcy, failure, collapse or sale of various financial institutions and an unprecedented level of intervention from the United States government. These

36

circumstances and events led to reduced credit availability, tighter lending standards and higher interest rates on loans. While we cannot predict the future condition of the credit markets, future turmoil in the credit markets could have a material adverse effect on our business, liquidity, financial condition and cash flows, particularly if our ability to borrow money from lenders or access the capital markets to finance our operations were to be impaired.

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

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

We have sold various assets and either retained certain liabilities or indemnified certain purchasers against future liabilities relating to businesses and assets sold, including breaches of warranties, environmental expenditures, asset retirements and other representations that we have provided.  Although we believe that we have established appropriate reserves for those liabilities, we could be required to accrue additional amounts in the future and these amounts could be material.

We will provide periodic reports as a “voluntary filer” pursuant to our contractual obligations in the indentures governing the notes, which contractual obligations may be amended without your consent.

We currently anticipate that our reporting obligations pursuant to Section 15(d) of the Exchange Act will terminate after we file this Annual Report on Form 10-K because each series of our notes were held by fewer than 300 persons as of January 1, 2013. Notwithstanding the anticipated automatic suspension of our reporting obligations pursuant to Section 15(d) of the Exchange Act, we intend to continue filing periodic reports with the SEC and to provide holders of our notes with copies of any filed reports as a “voluntary filer” in compliance with the indentures governing our notes. We expect that such periodic reports filed by us as a voluntary filer will comply fully with all applicable rules and regulations of the SEC. However, we could eliminate the periodic reporting covenant in each indenture governing our notes with the consent of the holders of at least a majority of the applicable series of the notes, in which case we would no longer be obligated to file periodic reports with the SEC and may cease doing so.

37

ITEM 1B.UNRESOLVED STAFF COMMENTS

None.

ITEM 2.PROPERTIES

A description of our properties is included in Part I, Item 1, Business, and is incorporated herein by reference.

We believe that we have satisfactory title to the properties owned and used in our businesses, subject to liens for taxes not yet payable, liens incident to minor encumbrances, liens for credit arrangements and easements and restrictions that do not materially detract from the value of these properties, our interests in these properties or the use of these properties in our businesses. We believe that our properties are adequate and suitable for the conduct of our business in the future.

ITEM 3.LEGAL PROCEEDINGS

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

ITEM 4.MINE SAFETY DISCLOSURES

Not applicable.

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

On February 12, 2013, certain investment funds affiliated with Apollo beneficially owned approximately 19.6% of the ordinary shares of LyondellBasell Industries N.V.  (“LyondellBasell”) and have certain director nomination rights. LyondellBasell may be deemed to be under common control with us, but this statement is not meant to be an admission that common control exists. As a result, it appears that we are required to provide disclosures as set forth herein pursuant to Section 219 of the new Iran Threat Reduction and Syria Human Rights Act of 2012 and Section 13(r) of the Securities Exchange Act of 1934, as amended.  The Annual Report on Form 10-K for the year ended December 31, 2012 filed by LyondellBasell with the SEC on February 12, 2013 contained the disclosure set forth below (with all references contained therein to “the Company” being references to LyondellBasell and its consolidated subsidiaries).

The disclosure below does not relate to any activities conducted by us and does not involve us or our management.  The disclosure relates solely to activities conducted by LyondellBasell and its consolidated subsidiaries.

“Disclosure pursuant to Section 219 of the Iran Threat Reduction & Syria Human Rights Act

Certain non-U.S. subsidiaries of our predecessor, LyondellBasell AF, licensed processes to construct and operate manufacturing plants in Iran that produce polyolefin plastic material, which is used in the packaging of household and consumer goods. The subsidiaries also provided engineering support and supplied catalyst products to be used in these manufacturing operations. In 2009, the Company made the decision to suspend the pursuit of any new business dealings in Iran.

As previously disclosed by the Company, in 2010, our management made the further decision to terminate all business by the Company and its direct and indirect subsidiaries with the government, entities and individuals in Iran. The termination was made in accordance with all applicable laws and with the knowledge of U.S. Government authorities. As part of the termination, we entered into negotiations with Iranian counterparties in order to exit our contractual obligations. As described below, two transactions occurred under settlement agreements in early 2012, although the agreements to cease our activities with these counterparties were entered into in 2011. In January 2012, one of our non-U.S. subsidiaries received a final payment of approximately €3.5 million for a shipment of catalyst from an entity that is 50% owned by the National Petrochemical Company of Iran.

38

Our shipment of the catalyst was in February 2012 as part of the agreement related to our termination and cessation of all business under agreements with the counterparty. In 2012, the gross revenue from this limited activity was approximately, €4.2 million and profit attributable to it was approximately, €2.4 million.

In January and February of 2012, one of the Company’s non-U.S. subsidiaries provided certain engineering documents relating to a polyolefin plastic process to a licensee comprising three Iranian companies, one of which is 20% owned by the National Oil Company of Iran. The provision of documents was the Company’s final act with respect to the termination and cessation of all business under agreements with the counterparties. No gross revenue or profit was attributable to this activity in 2012. The transactions disclosed in this report do not constitute violations of applicable anti-money laundering laws or sanctions laws administered by the U.S. Department of the Treasury, Office of Foreign Assets Control (OFAC), and are not the subject of any enforcement actions under the Iran sanction laws.

We have not conducted, and do not intend to conduct, any further business activities in Iran or with Iranian counterparties.”

PART II

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

Our member’s equity is privately held and thus there is no established public trading market for our membership interests.

39

ITEM 6.SELECTED HISTORICAL CONSOLIDATED FINANCIAL DATA

The following table sets forth selected historical financial and other data for the periods and as of the dates indicated for EP Energy LLC (the “Successor”) and EP Energy Global LLC (the “Predecessor” and formerly known as EP Energy Corporation). We have derived the consolidated statement of income for the years ended December 31, 2011, and 2010 and balance sheet data as of December 31, 2011, from EP Energy Corporation’s audited consolidated financial statements included in this Report on Form 10-K.  We have derived the consolidated statement of income for the years ended December 31, 2009 and 2008 and balance sheet data as of December 31, 2010, 2009 and 2008 from EP Energy Corporation’s audited consolidated financial statements included in our Registration Statement on Form S-4. We have derived the consolidated statement of income data for the Successor period from March 23, 2012 (inception) to December 31, 2012 and Predecessor period from January 1, 2012 to May 24, 2012 and the consolidated balance sheet data as of December 31, 2012 from EP Energy LLC’s audited consolidated financial statements.  The selected financial data is not necessarily indicative of results to be expected in future periods and should be read together with Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations and Item 8, Financial Statements and Supplementary data included in this Report on Form 10-K.

	Successor			Predecessor
	March 23 (inception), to December 31,			January 1, to May 24,			For Years ended December 31,
	2012			2012			2011			2010			2009			2008
							(In millions)
Results of Operations
Operating revenue	$	947		$	978		$	1,867		$	1,789		$	1,828		$	2,762
Operating (loss) income	(23		)	336			503			731			(1,317		)	(1,533		)
Interest expense	(218		)	(14		)	(12		)	(21		)	(25		)	(57		)
Net (loss) income	$	(255	)	$	178		$	262		$	443		$	(911	)	$	(1,263	)
Cash Flow
Net cash provided by (used in):
Operating activities	$	449		$	580		$	1,426		$	1,067		$	1,573		$	2,218
Investing activities	(7,893		)	(628		)	(1,237		)	(1,130		)	(1,156		)	(993		)
Financing activities	7,507			110			(238		)	(46		)	(336		)	(1,237		)

	As of December 31,		As of December 31,
	2012		2011		2010		2009		2008
					(In millions)
Financial Position
Total assets	$	8,293	$	5,099	$	4,942	$	4,457	$	6,384
Long-term debt	4,346		851		301		835		915
Member’s/Stockholder’s equity	3,085		3,100		3,067		2,529		3,697

Factors Affecting Trends. In May 2012, the Sponsors acquired us for approximately $7.2 billion with approximately $3.3 billion in equity contributions and the issuance of $4.25 billion in debt.  During the successor period from March 23 (inception) to December 31, 2012, we recorded realized and unrealized losses on financial derivatives included in operating revenues of $62 million and restructuring costs of $221 million.  For the predecessor periods ended January 1 to May 24, 2012, and for the years ended December 31, 2011, 2010, 2009 and 2008 we recorded realized and unrealized gains on financial derivatives included in operating revenues of $365 million, $284 million, $390 million, $687 million and $196 million, and non-cash ceiling test charges of $62 million, $152 million, $25 million, $2.1 billion and $2.8 billion, respectively.

40

ITEM 7.MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Our Management’s Discussion and Analysis of Financial Condition and Results of Operations (“MD&A”) should be read in conjunction with the financial statements and the accompanying notes presented in Item 8 of this Annual Report on Form 10-K. This discussion contains forward-looking statements and involves numerous risks and uncertainties, including, but not limited to, those described in “Risk Factors”.  Our actual results may differ materially from those contained in any forward-looking statements. See “Cautionary Statement Regarding Forward-Looking Statements” in the front of this report. Additionally, the financial results for the successor period subsequent to the Acquisition includes the application of the acquisition method of accounting and the application of the successful efforts method of accounting for oil and natural gas properties. As a result, trends and results in future periods may be different than those that existed prior to the Acquisition and under the full cost method of accounting. Unless otherwise indicated or the context otherwise requires, references in this MD&A section to “we”, “our”, “us” and “the Company” refer to both EP Energy LLC (the “Successor”) and EP Energy Global LLC (the “Predecessor” for accounting purposes), and each of its consolidated subsidiaries.

Our Business

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

We operate primarily through three domestic divisions: Eagle Ford, Southern and Central. Our Eagle Ford division operations are in south Texas.  The Southern division is located along the Gulf Coast as well as the south and west areas of Texas, including the Wolfcamp Shale.  Our Central division includes operations in east Texas, Louisiana, Alabama, eastern Oklahoma, in the Uintah Basin in Utah and the Raton Basin located in New Mexico and Colorado.  In July 2012, we sold assets in the Gulf of Mexico and Indiana.

Our key programs include the Eagle Ford Shale in south Texas, the Wolfcamp Shale in the Permian Basin of west Texas, the Altamont Field in Utah and the Haynesville Shale in northwest Louisiana and east Texas. Below are summary descriptions of each of these key programs further described in Item I, Business:

·Eagle Ford Shale. The Eagle Ford Shale provides the highest economic returns in our portfolio. We currently are running six rigs, with the addition of the sixth rig in early February 2013.

·Wolfcamp Shale. In the Wolfcamp Shale program, which we entered in 2009, we are focused on optimizing our drilling, completion and artificial lift systems. We currently are running three rigs, with the addition of the third rig in early January 2013.

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

·Haynesville Shale.  Although we had a very efficient drilling program in the Haynesville Shale, we suspended our drilling program at the end of the first quarter of 2012 due to low natural gas prices. The Haynesville Shale remains a key natural gas option for us when natural gas prices return to more economic levels in the future.  Substantially all of our acreage in the Haynesville shale is held by production.

41

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

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

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

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

·managing cash costs; and

·managing price risks to optimize realized prices on our oil and natural gas production.

In addition to these factors, our future profitability and performance will be affected by our ability to execute our strategy, the impacts of volatility in the financial and commodity markets, industry-wide changes in the cost of drilling and oilfield services which impact our daily production, operating and capital costs and our debt level and related interest costs. Additionally, we may be impacted by hurricanes and other weather events, or domestic or international regulatory issues or other 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.  Because we apply mark-to-market accounting on our financial derivative contracts and because we do not hedge all of our price risks, this strategy only partially reduces our commodity price exposure. 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.

42

Derivatives.  During 2012, approximately 76 percent of our natural gas production and 88 percent of our oil production were hedged and settled at average floor prices of $4.67 per MMBtu and $96.27 per barrel, respectively. The following table reflects the contracted volumes and the minimum, maximum and average prices we will receive under derivative contracts we held as of December 31, 2012.

	2013			2014			2015
	Volumes(1)	Average Price(1)		Volumes(1)	Average Price(1)		Volumes(1)	Average Price(1)
Natural Gas
Fixed Price Swaps	153	$	3.55	89	$	4.02	33	$	4.23
Ceilings	1	$	3.70	—	—		—	—
Oil
Fixed Price Swaps	8,955	$	103.52	8,760	$	98.64	5,501	$	95.42
Ceilings	61	$	97.50	1,095	$	100.00	1,095	$	100.00
Three Way Collars Ceiling	5,845	$	106.20	2,920	$	103.76	—	—
Three Way Collars Floors(2)	5,845	$	92.58	2,920	$	95.00	—	—

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

(2)If market prices settle at or below $71.25 and $75.00 for the years 2013 and 2014, respectively, our three-way collars-floors effectively “lock-in” a cash settlement of the market price plus $21.33 per Bbl and $20.00 per Bbl for 2013 and 2014, respectively.

In January and February of 2013, we added fixed price oil derivatives of 2,325 MBbl and 986 MBbl and fixed price natural gas derivatives of 7 TBtu and 11 TBtu related to our 2013 and 2014 anticipated production, respectively.  In addition, we added oil basis swaps of 3,650 MBbl and 2,920 MBbl related to a portion of our 2014 and 2015 crude differential exposure.  These derivatives are not reflected in the table above.

Summary of Liquidity and Capital Resources.  In connection with the Acquisition we issued $4.25 billion in principal amount of total indebtedness through a combination of notes, term loans and credit facilities. During 2012 we re-priced our $750 million term loan and repaid certain amounts outstanding under our RBL Facility by issuing an additional $350 million of senior unsecured notes and obtaining an incremental $400 million term loan. Under our RBL Facility we currently have the ability to incur an additional $1.68 billion of indebtedness (subject to a semi-annual borrowing base redetermination beginning April 2013), which gives us available liquidity, including existing cash, as of December 31, 2012 of $1.74 billion.

Based on our current level of operations and available cash, we believe our cash flows from operations, combined with availability under the RBL Facility, provides us sufficient liquidity into 2013 and the foreseeable future to fund our current obligations, projected 2013 working capital requirements and capital spending plan in 2013.  Additionally, the earliest maturity date of our debt obligations is in 2017.  See “Liquidity and Capital Resources” for more information.

Outlook for 2013. For 2013, we expect the following:

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

·Average daily production volumes for the year of approximately 125 MBoe/d to 135 MBoe/d or 750 MMcfe/d to 810 MMcfe/d.

·Per unit adjusted cash operating costs for the year of approximately $11.50 to $13.25 per Boe or $1.90 to $2.20 per Mcfe, before transportation costs of $2.85 to $ 3.15 per Boe or $0.48 to $0.53 per Mcfe.

43

Production Volumes and Drilling Summary

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

	2012	2011	2010
	MMcfe/d
United States
Eagle Ford	121	40	6
Southern	99	127	183
Central	570	576	498
International
Brazil	35	34	33
Total consolidated	825	777	720
Unconsolidated affiliate	55	61	62
Total combined	880	838	782
Oil and condensate (MBbls/d)
Consolidated volumes	26	16	13
Unconsolidated affiliate volumes	1	1	1
Total Combined	27	17	14
Natural Gas (MMcf/d)
Consolidated volumes	637	661	618
Unconsolidated affiliate volumes	42	46	47
Total Combined	679	707	665
NGL (MBbls/d)
Consolidated volumes	5	3	4
Unconsolidated affiliate volumes	1	1	2
Total Combined	6	4	6

·Eagle Ford division—Our 2012 Eagle Ford division volumes increased 81 MMcfe/d for the year ended December 31, 2012 compared to 2011 due to the success of our drilling program in the area. During the year ended December 31, 2012, we drilled 84 additional wells in our Eagle Ford area and had a total of 143 net operated wells as of December 31, 2012. With a majority of our acreage located in the oil and liquids rich area of the Eagle Ford Shale, our total oil and NGL production was approximately 16 MBbls/d for the year ended December 31, 2012, an increase of over 200 percent from 2011.

·Southern division—Our 2012 Southern division volumes decreased 28 MMcfe/d for the year ended December 31, 2012 compared to 2011 primarily due to the sale of our Gulf of Mexico assets in July 2012 and to natural declines and lower levels of drilling activity in the Texas Gulf Coast. In 2012 our Gulf of Mexico assets had average daily production of 25 MMcfe/d, while in 2011 they had average daily production of 46 MMcfe/d. Within the Southern division is our Wolfcamp Shale program where we drilled 17 additional wells during 2012, for a total of 31 net operated wells as of December 31, 2012.

·Central division—Our 2012 Central division volumes decreased 6 MMcfe/d for the year ended December 31, 2012 compared to 2011 due to natural declines offset by the success of our drilling programs in the Haynesville Shale,  Altamont and the Raton Basin areas.  As of December 31, 2012 we had 100 net operated wells in the Haynesville Shale and our total production was approximately 291 MMcfe/d.  Currently we are not running any rigs in the Haynesville Shale due to a lower natural gas price environment.  As of December 31, 2012, we had 308 net operated wells in our Altamont Field with total oil production of approximately 8 MBbls/d.

·International—The 2012 production volumes related to our Brazil operations were 35 MMcfe/d, slightly above our 2011 production volumes. We are still awaiting a response on our appeal filed in 2011 for our environmental permit request concerning the Pinauna Field which was denied by the Brazilian environmental regulatory agency in 2011.

44

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/Mcfe	Total oil and 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 “Financial Statements and Supplementary Data—Supplemental Oil and Natural Gas Operations.”

(2)Total oil and natural gas capital costs include the costs of development, exploration and property acquisition activities conducted to add reserves and exclude asset retirement obligations. Amounts are derived directly from the table presented in “Financial Statements and Supplementary Data—Supplemental Oil and Natural Gas Operations” which includes both successor and predecessor capital costs. For 2012, capital costs utilized in this ratio reflect the non-GAAP combination of predecessor and successor periods as further described in Results of Operations below.

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

The exploration for and the acquisition and development of oil and natural gas reserves is inherently uncertain as further discussed in “Risk Factors—Risks Related to Our Business and Industry.” One of these risks and uncertainties is our ability to spend sufficient capital to increase our reserves. While we currently expect to spend such amounts in the future, there are no assurances as to the timing and magnitude of these expenditures or the classification of the proved reserves as developed or undeveloped. At December 31, 2012, proved developed reserves represent approximately 47% 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.

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

	Including Price Revisions									Excluding Price Revisions
	2012			2011			2010			2012			2011			2010
	($/Mcfe)									($/Mcfe)
Reserve Replacement Ratios
Domestic	47		%	416		%	370		%	298		%	418		%	306		%
Worldwide	45		%	400		%	347		%	285		%	401		%	284		%
Reserve Replacement Costs (1)
Domestic	$	11.26		$	1.42		$	1.29		$	1.79		$	1.41		$	1.56
Worldwide	$	11.51		$	1.43		$	1.40		$	1.81		$	1.43		$	1.72

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

45

We typically cite reserve replacement costs in the context of a multi-year trend, in recognition of its limitation as a single year measure, and also to demonstrate consistency and stability, which are essential to our business model. The table below shows our reserve replacement costs for our domestic and worldwide operations for the three years ended December 31, 2012.

	Including PriceRevisions		Excluding PriceRevisions
	Three Years Ending December 31, 2012
	($/Mcfe)
Reserve Replacement Costs
Domestic	$	1.98	$	1.57
Worldwide	$	2.05	$	1.62

Results of Operations

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

	Successor			Predecessor
	March 23 (inception), to December 31,			January 1, to May 24,			Years ended December 31,
	2012			2012			2011			2010
				(In millions)
Operating revenues:
Oil and condensate	$	567		$	322		$	552		$	346
Natural gas	401			262			973			974
NGL	41			29			57			60
Total physical sales	1,009			613			1,582			1,380
Financial derivatives	(62		)	365			284			390
Other	—			—			1			19
Total operating revenues	947			978			1,867			1,789
Operating expenses
Transportation costs	73			45			85			73
Lease operating expense	136			96			217			193
General and administrative	379			75			201			190
Depreciation, depletion and amortization	268			319			612			477
Impairments/Ceiling test charges	1			62			158			25
Exploration expense	52			—			—			—
Taxes, other than income taxes	61			45			91			85
Other	—			—			—			15
Total operating expenses	970			642			1,364			1,058
Operating (loss) income	(23		)	336			503			731
Loss from unconsolidated affiliates	(1		)	(5		)	(7		)	(7		)
Other income (expenses)	3			(3		)	(2		)	3
Loss on extinguishment of debt	(14		)	—			—			—
Interest expense
Third party	(218		)	(14		)	(9		)	(16		)
Affiliated	—			—			(3		)	(5		)
(Loss) income before income taxes	(253		)	314			482			706
Income tax expense	2			136			220			263
Net (loss) income	$	(255	)	$	178		$	262		$	443

46

The historical financial results in the table above have been presented separately in accordance with required GAAP presentation. Periods prior to May 24, 2012 are referred to as predecessor periods ( “Predecessor”), while periods after March 23, 2012 for EP Energy LLC are referred to as successor periods ( “Successor”). Despite this separate GAAP presentation, the successor had no independent oil and gas operations prior to the Acquisition and accordingly there were no operational exploration and production activities that changed as a result of the acquisition of the Predecessor. Consequently, given the continuity of operations, when assessing variance analysis of our historical results of operations and financial performance, we have utilized supplemental combined predecessor and successor results for the year ended December 31, 2012 as follows:

	Successor			Predecessor			Combined
	March 23 (inception) to December 31, 2012			January 1 to May 24, 2012			Year Ended December 31, 2012
Operating revenues:
Oil and condensate	$	567		$	322		$	889
Natural gas	401			262			663
NGL	41			29			70
Total physical sales	1,009			613			1,622
Financial derivatives	(62		)	365			303
Total operating revenues	947			978			1,925
Operating expenses:
Transportation costs	73			45			118
Lease operating expense	136			96			232
General and administrative	379			75			454
Depreciation, depletion and amortization	268			319			587
Impairments/Ceiling test charges	1			62			63
Exploration expense	52			—			52
Taxes other than income	61			45			106
Total operating expenses	970			642			1,612
Operating (loss) income	(23		)	336			313
Loss from unconsolidated affiliates	(1		)	(5		)	(6		)
Other income (expense)	3			(3		)	—
Loss on extinguishment of debt	(14		)	—			(14		)
Interest expense	(218		)	(14		)	(232		)
(Loss) income before income taxes	(253		)	314			61
Income tax expense	2			136			138
Net (loss) income	$	(255	)	$	178		$	(77	)

We believe that reflecting the combined financial results in the 2012 variance analysis facilitates the most meaningful comparison and understanding of our operating performance in 2012 versus the prior years. These combined non-GAAP results for the year ended December 31, 2012 are provided as supplemental financial information when assessing variance analysis of our historical results of operations and financial performance in the tables and discussion that follow and are not intended to be a substitute for our reported GAAP results.

47

Operating Revenues.

The table below provides our period-over-period operating revenues, volumes and prices per unit. We present (i) average realized prices based on physical sales of oil and condensate, natural gas and NGL as well as (ii) average realized prices inclusive of the impacts of financial derivative settlements. Our average realized prices, including financial derivative settlements, reflect cash received and/or paid during the period on settled financial derivatives based on the period the contracted settlements were originally scheduled to occur; however, these prices do not reflect the impact of any associated premiums paid to enter into certain of our derivative contracts:

	Years ended December 31,
	2012		2011		2010		2012 – 2011 % change		2011 - 2010 % change
	(In millions, except for percentages)
Operating revenues
Oil and condensate	$	889	$	552	$	346	61	%	60	%
Natural gas	663		973		974		(32	)%	—	%
NGL	70		57		60		23	%	(5	)%
Total physical sales	1,622		1,582		1,380		3	%	15	%
Financial derivatives	303		284		390		7	%	(27	)%
Other	—		1		19		(100	)%	(95	)%
Total operating revenues	$	1,925	$	1,867	$	1,789	3	%	4	%
Volumes:
Oil and condensate
Consolidated volumes (MBbls)	9,537		6,034		4,747		58	%	27	%
Unconsolidated affiliate volumes (MBbls)	282		306		364		(8	)%	(16	)%
Natural gas
Consolidated volumes (MMcf)	233,136		241,083		225,611		(3	)%	7	%
Unconsolidated affiliate volumes (MMcf)	15,552		16,881		17,165		(8	)%	(2	)%
NGL
Consolidated volumes (MBbls)	1,904		1,068		1,423		78	%	(25	)%
Unconsolidated affiliate volumes (MBbls)	478		556		573		(14	)%	(3	)%
Equivalent volumes
Consolidated MMcfe	301,784		283,696		262,631		6	%	8	%
Unconsolidated affiliate MMcfe	20,113		22,052		22,787		(9	)%	(3	)%
Total combined MMcfe	321,897		305,748		285,418		5	%	7	%
Consolidated MMcfe/d	825		777		720		6	%	8	%
Unconsolidated affiliate MMcfe/d	55		61		62		(10	)%	(2	)%
Total Combined MMcfe/d	880		838		782		5	%	7	%
Consolidated prices per unit:
Oil and condensate
Average realized price on physical sales ($/Bbl)	$	93.25	$	91.40	$	72.83	2	%	25	%
Average realized price, including financial derivatives($/Bbl)(1)(2)	$	97.97	$	90.23	$	71.13	9	%	27	%
Natural gas
Average realized price on physical sales ($/Mcf)	$	2.84	$	4.04	$	4.32	(30	)%	(6	)%
Average realized price, including financial derivatives($/Mcf)(1)(2)	$	4.30	$	5.44	$	5.67	(21	)%	(4	)%
NGL
Average realized price on physical sales ($/Bbl)	$	36.96	$	53.50	$	42.38	(31	)%	26	%

(1)Amounts reflect settlements on derivative instruments, excluding premiums paid. During the years ended December 31, 2012, 2011 and 2010, no cash premiums were paid related to oil derivatives settled.  During the year ended December 31, 2012 no cash premiums were paid related to natural gas derivatives settled whereas during the years ended December 31,2011and 2010, these premiums were $23 million and $157 million.  Had these premiums been included in the natural gas average realized prices in 2011 and 2010, the realized price, including financial derivative settlements, would have decreased by $0.10/Mcf and $0.70/Mcf for the years ended December 31, 2011 and 2010.

48

(2)The years ended December 31, 2012, 2011 and 2010, include approximately $340 million, $338 million and $306 million of cash receipts for the settlement of natural gas derivative contracts. The year ended December 31, 2012 included approximately $45 million of cash receipts for the settlement of crude oil derivatives contracts. The years ended December 31, 2011 and 2010, include approximately $7 million and $8 million of cash paid for the settlement of crude oil derivative contracts.

Physical sales.  Physical sales represent accrual-based commodity sales transactions with customers. For the year ended December 31, 2012, physical sales increased by $40 million, or three percent compared to 2011. Oil revenues increased $337 million primarily attributable to a 58 percent increase in consolidated oil volumes, but were largely offset by a $310 million decrease in natural gas revenues primarily due to lower natural gas prices. The increase in oil production is primarily attributable to our Eagle Ford, Wolfcamp and Altamont key programs which are up 11 MBbls/d in 2012 over 2011.  For the year ended December 31, 2011, physical sales increased $202 million compared to 2010. In 2011, our oil revenues increased by $206 million due to both higher oil prices of $112 million and a 27% increase in consolidated oil production volumes of $94 million.  Natural gas revenues were largely flat comparing 2011 to 2010 as increases in production volumes were offset with lower natural gas prices.   For the years ended December 31, 2012 and 2011 our oil and condensate sales have increased 61 percent and 60 percent, respectively, from the prior year’s physical sales.

As of December 31, 2012, the NYMEX spot price of a barrel of oil was $91.82 versus the spot NYMEX price of natural gas of $3.35, or a ratio of 27 to 1.  Our primary focus in 2012 was to grow oil volumes due to the value of oil in relation to the value of natural gas.  We will continue to target increases in our oil volumes in 2013, 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 on financial derivatives.  Realized and unrealized gains for the year ended December 31, 2012 increased by $19 million compared to 2011 and for the year ended December 31, 2011 decreased by $106 million compared to 2010.  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.

Operating Expenses

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

	Years Ended December 31,
	2012		2011		2010
	(in Millions)
Transportation costs	$	118	$	85	$	73
Lease operating expense	232		217		193
General and administrative	454		201		190
Depreciation, depletion and amortization	587		612		477
Impairments/Ceiling test charges	63		158		25
Exploration expense	52		—		—
Taxes other than income	106		91		85
Other	—		—		15
Total operating expenses	$	1,612	$	1,364	$	1,058
Cash operating costs per unit ($/Mcfe)(1)	$	2.63	$	1.79	$	1.78
Adjusted cash operating costs per unit ($/Mcfe)(1)	$	1.74	$	1.69	$	1.71

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

49

Transportation costs.  Transportation costs for the year ended December 31, 2012 increased $33 million compared to the same period in 2011 mainly due to new transportation contracts entered into in 2012 primarily related to our Eagle Ford division in response to growth in that area. Transportation costs for the year ended December 31, 2011 increased $12 million compared to 2010 primarily due to increased production from the Haynesville area as we expanded that program.  Our average transportation costs per unit were:

	2012		2011		2010
Average transportation costs
Oil and condensate ($/Bbl)	$	1.82	$	0.06	$	0.08
Natural gas ($/Mcf)	$	0.39	$	0.33	$	0.30
NGL ($/Bbl)	$	5.41	$	3.83	$	3.16

Lease operating expense.  Lease operating expense for the year ended December 31, 2012 increased $15 million compared to 2011 due to increased water disposal, equipment and chemical costs in our Eagle Ford division as activity ramped up in that area.  Lease operating expenses for the year ended December 31, 2011 increased $24 million compared to 2010 due to higher maintenance, repair and power costs in our Central division, higher costs in our Eagle Ford division due to early well testing and higher expenses in our International area.

General and administrative expenses.  General and administrative expenses for the year ended December 31, 2012 increased $253 million compared to 2011. The increase is primarily due to transition and restructuring costs of $221 million for the year ended December 31, 2012. The costs include acquisition related costs of $173 million and transition and severance costs of $48 million.  General and administrative expenses for the year ended December 31, 2011 increased $11 million compared to 2010 due to severance costs related to an office closure and higher employee benefit costs.

Depreciation, depletion and amortization expense.  For the year ended December 31, 2012 depreciation, depletion and amortization decreased $25 million compared to 2011 due to an average lower depletion rate following the application of the successful efforts method of accounting for oil and natural gas properties, partially offset by higher production volumes. Due to the ongoing development of higher cost liquids programs, we expect our depletion rate will increase in future periods compared to our current levels.  For the year ended December 31, 2011 depreciation, depletion and amortization increased $135 million compared to 2010 as a result of higher depletion rates under the full cost method of accounting and higher production volumes compared to 2010.  Our depreciation, depletion and amortization rate increased in 2011 as we focused our capital on oil programs.  Our average depreciation, depletion and amortization costs per unit for the years ended December 31 were:

	2012		2011		2010
Depreciation, depletion and amortization ($/Mcfe)(1)	$	1.95	$	2.16	$	1.82

(1)Includes $0.05, $0.05 and $0.06 per Mcfe for the years ended December 31, 2012. 2011 and 2010 related to accretion expense on asset retirement obligations.

Exploration expense.  For the year ended December 31, 2012 we recorded $52 million of exploration expense as a result of applying the successful efforts method of accounting following the Acquisition. Prior to the Acquisition, exploration expense was capitalized under full cost accounting. Included in exploration expense is $23 million of amortization of unproved property costs.

Impairments and Ceiling test charges.  During the first quarter of 2012 we recorded a non-cash charge of approximately $62 million as a result of our decision to end exploration activities in Egypt. In June of 2012, we sold all our interests in Egypt. During the year ended December 31, 2011 we recorded a non-cash charge of approximately $152 million related to our Brazil oil and natural gas operations and a $6 million impairment of certain oil field related equipment and supplies. Forward commodity prices can play a significant role in determining impairments. Due to the current forecast of future natural gas prices and considering the significant amount of fair value allocated to our natural gas and oil properties in conjunction with the Acquisition, sustained lower natural gas and oil prices from the present levels could result in an impairment of the carrying value of our proved properties in the future.

50

Taxes, other than income taxes.  Taxes, other than income taxes for the year ended December 31, 2012 increased $15 million compared to 2011 primarily due to higher severance and ad valorem taxes associated with higher oil production volumes and property values from activity in our oil producing areas.  Production taxes for the year ended December 31, 2011 increased $6 million compared to 2010 also due to higher oil production volumes.

Cash Operating Costs and Adjusted Cash Operating Costs.  We monitor cash operating costs required to produce our oil and natural gas. Cash operating costs is a non-GAAP measure calculated on a per Mcfe basis and includes total operating expenses less depreciation, depletion and amortization expense, transportation costs, other ( cost of products), exploration expense, ceiling test and impairment charges. Adjusted cash operating costs is a non-GAAP measure and is defined as cash operating costs less transition and restructuring costs and equity based compensation expense. Cash operating costs and adjusted cash operating costs per unit are a valuable measure of operating performance and efficiency; however, these measures may not be comparable to similarly titled measures used by other companies. The table below represents a reconciliation of our cash operating costs and adjusted cash operating costs to operating expenses for the years ended December 31:

	Years Ended December 31,
	2012						2011						2010
	(In millions, except per unit costs)
	Total			Per Unit			Total			Per Unit			Total			Per Unit
Total operating expenses	$	1,612		$	5.34		$	1,364		$	4.81		$	1,058		$	4.03
Depreciation, depletion and amortization	(587		)	(1.95		)	(612		)	(2.16		)	(477		)	(1.82		)
Transportation costs	(118		)	(0.39		)	(85		)	(0.30		)	(73		)	(0.28		)
Other	—			—			—			—			(15		)	(0.05		)
Exploration expense	(52		)	(0.17		)	—			—			—			—
Impairments/Ceiling test charges	(63		)	(0.20		)	(158		)	(0.56		)	(25		)	(0.10		)
Total cash operating costs and per-unit cash costs	792			2.63			509			1.79			468			1.78
Transition/restructuring costs and equity based compensation expense (1)	(269		)	(0.89		)	(27		)	(0.10		)	(18		)	(0.07		)
Total adjusted cash operating costs and adjusted per-unit cash costs(1)	$	523		$	1.74		$	482		$	1.69		$	450		$	1.71
Total equivalent volumes (MMcfe)(2)	301,784						283,696						262,631

(1)Includes acquisition related costs of $173 million and transition and severance costs of $48 million, $16 million of advisory fees paid to Sponsors, and $32 million of equity-based compensation expense for the year ended December 31, 2012.  For the year ended December 31, 2011 we incurred $6 million of restructuring costs associated with the closure of our Denver office and $21 million of equity-based compensation expense. For the year ended December 31, 2010 we incurred $18 million of equity-based compensation expense.

(2)Excludes volumes and costs associated with Four Star.

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

	Years Ended December 31,
	2012			2011			2010
Cash operating costs ($/Mcfe)
Average lease operating expenses	$	0.77		$	0.77		$	0.73
Average production taxes(1)	0.32			0.28			0.27
Average general and administrative expenses	1.50			0.70			0.72
Average taxes, other than production and income taxes	0.04			0.04			0.06
Total cash operating costs	$	2.63		$	1.79		$	1.78
Transition/restructuring costs and equity-based compensation expense (2)	$	(0.89	)	$	(0.10	)	$	(0.07	)
Total adjusted cash operating costs	$	1.74		$	1.69		$	1.71

(1)Production taxes include ad valorem and severance taxes which increased in 2012 primarily due to higher severance and ad valorem taxes associated with our oil producing areas.

51

Other Income Statement Items.

Loss on extinguishment of debt.  For the year ended December 31, 2012 we recorded a $14 million loss on the extinguishment of debt for the pro-rata portion of deferred financing costs written off, debt discount and call premiums paid related to the re-pricing of our existing $750 million term loan.

Interest expense. Interest expense for the year ended December 31, 2012 increased compared to 2011 primarily due to the issuance of approximately $4.25 billion of debt in 2012 related to the Acquisition.

52

Liquidity and Capital Resources

Overview.  Our primary sources of liquidity are cash generated by our operations and borrowings under the RBL Facility. Our primary uses of cash are working capital requirements, debt service requirements and capital expenditures. As of December 31, 2012, our available liquidity was approximately $1.74 billion, including approximately $1.68 billion of additional borrowing capacity available under the RBL Facility (subject to semi-annual borrowing base redetermination beginning April 2013).

As of December 31, 2012, our long-term debt is approximately $4.35 billion, comprised of $3.1 billion in senior notes due in 2019, 2020 and 2022, $1.15 billion in senior secured term loans with maturity dates in 2018 and 2019, and $105 million outstanding under the RBL Facility expiring in 2017.  Based on our debt levels, we are, and will continue to be, highly leveraged and therefore expect that our interest costs will continue to be higher compared to what we have experienced prior to the Acquisition. For additional details on our long-term debt, see Part II Item 8, Financial Statements and Supplementary data, Note 7.

Based on our current level of operations and available cash, we believe our cash flows from operations, combined with availability under the RBL Facility, provides us sufficient liquidity into 2013 and the foreseeable future to fund our current obligations, projected 2013 working capital requirements and 2013 capital plan of approximately $1.7 - $1.8 billion.  Our ability to (i) generate sufficient cash flows from operations or obtain future borrowings under the RBL Facility, (ii) repay or refinance any of our indebtedness on commercially reasonable terms or at all on the occurrence of certain events, such as a change of control, or (iii) obtain additional capital if required on acceptable terms or at all for any potential future acquisitions, joint ventures or other similar transactions, depends on prevailing economic conditions many of which are beyond our control.  To the extent possible, we have attempted to mitigate certain of these risks (e.g. by entering into oil and natural gas derivative contracts to reduce the financial impact of downward commodity price movements on a substantial portion of our anticipated production), but we could be required to take additional future actions if necessary to address further changes in the financial or commodity markets.

Overview of Cash Flow Activities.  During the period from March 23 (inception) to December 31, 2012, we generated operating cash flow of approximately $449 million. During the period from January 1 to May 24, 2012, we generated operating cash flow of approximately $580 million. We utilized these amounts to fund our capital programs and repay amounts outstanding under our various credit facilities and other debt obligations. Our cash flows from operations are summarized as follows:

	Successor			Predecessor
	March 23 (inception) to December 31,			January 1 to May 24,			December 31,
	2012			2012			2011			2010
	(In millions)			(In millions)
Cash Flow from Operations
Operating activities
Net (loss) income	$	(255	)	$	178		$	262		$	443
Impairments/Ceiling test charges	1			62			158			25
Other income adjustments	351			537			973			859
Change in other assets and liabilities	352			(197		)	33			(260		)
Total cash flow from operations	$	449		$	580		$	1,426		$	1,067
Other Cash Inflows
Investing activities
Net proceeds from the sale of assets	110			9			612			155
Other	—			—			—			4
	110			9			612			159
Financing activities
Proceeds from long term debt	5,477			215			2,030			500
Contributions	3,323			960			—			—
Net change in note payable with parent	—			—			—			489
	8,800			1,175			2,030			989
Total cash inflows	$	8,910		$	1,184		$	2,642		$	1,148
Cash Outflows
Investing activities
Capital expenditures	$	877		$	636		$	1,591		$	1,238
Cash paid for acquisitions	7,126			1			22			51
Increase in note receivable with parent	—			—			236			—
	$	8,003		$	637		$	1,849		$	1,289
Financing activities
Repayment of long term debt	1,139			1,065			1,480			1,034
Net change in note payable with parent company and affiliates	—			—			781			—
Debt issuance costs	154			—			7			1
	1,293			1,065			2,268			1,035
Total cash outflows	$	9,296		$	1,702		$	4,117		$	2,324
Net change in cash and cash equivalents	$	63		$	62		$	(49	)	$	(109	)

53

Contractual Obligations

We are party to various contractual obligations. Some of these obligations are reflected in our financial statements, such as liabilities from commodity-based derivative contracts, while other obligations, such as operating leases and capital commitments, are not reflected on our balance sheet. The following table and discussion summarizes our contractual cash obligations as of December 31, 2012, for each of the periods presented:

	2013		2014 - 2015		2016 - 2017		Thereafter		Total
	(In millions)
Long-term financing obligations:
Principal	$	—	$	—	$	105	$	4,250	$	4,355
Interest	331		662		657		669		2,319
Liabilities from derivatives	17		14		—		—		31
Operating leases	14		27		21		—		62
Other contractual commitments and purchase obligations:
Volume and transportation commitments	100		180		168		293		741
Other obligations	61		62		50		160		333
Total contractual obligations	$	523	$	945	$	1,001	$	5,372	$	7,841

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

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

Operating Leases.  We maintain leases related to our office space and various equipment.

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

·Volume and Transportation Commitments.  Included in these amounts are commitments for volume deficiency contracts and demand charges for firm access to natural gas transportation and storage capacity.

54

·Other Obligations.  Included in these amounts are commitments for drilling, completions and seismic activities for our operations and various other maintenance, engineering, procurement, construction contracts and our management fee agreement. We have excluded asset retirement obligations and reserves for litigation and environmental remediation, as these liabilities are not contractually fixed as to timing and amount. Upon completing the Acquisition, affiliates of our sponsors and other investors entered into a management fee agreement requiring an annual advisory fee of $25 million to be paid. The agreement terminates on the twelve-year anniversary of the Acquisition date (May 24, 2012) if not terminated earlier by mutual agreement of the parties, or upon a change in control or specified IPO transaction.

Commitments and Contingencies

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

Off-Balance Sheet Arrangements

We enter into a variety of financing arrangements and contractual obligations, some of which are referred to as off-balance sheet arrangements. These include guarantees and letters of credit.

Guarantees.  We periodically provide indemnification arrangements related to assets or businesses we have sold. These indemnification arrangements include, but are not limited to, indemnification for income taxes, the resolution of existing disputes, environmental matters, and necessary expenditures to ensure the safety and integrity of assets sold. As of December 31, 2012, we had no material obligations related to our guarantee and indemnification arrangements.

Letters of Credit.  We enter into letters of credit in the ordinary course of our operations as well as periodically in conjunction with sales of assets or businesses. As of December 31, 2012, we had outstanding letters of credit of approximately $9 million. For additional information on our counterparty credit and nonperformance risk, see Part II Item 8, Financial Statements and Supplementary data, Note 7.

Critical Accounting Estimates

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

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

55

Under the successful efforts method of accounting for oil and natural gas properties, we review our oil and natural gas properties periodically (at least annually) to determine if impairment of such properties is necessary. Significant proved undeveloped leasehold costs are assessed for impairment at a field level or resource play based on total future undiscounted net cash flows. Estimates of future undiscounted cash flows require significant judgment based on estimates of such items as estimates of oil and natural gas reserve quantities, future commodity prices, operating costs and future production among other factors. Leasehold acquisition costs associated with prospective areas that have limited or no previous exploratory drilling are generally assessed for impairment by major prospect area based on our current drilling plans which could change in the future and result in impairments of unproved property. Proved oil and natural gas property values are reviewed when circumstances suggest the need for such a review and may occur if a field discovers lower than anticipated reserves, reservoirs produce below original estimates or in a mix that is different than anticipated or if commodity prices fall below 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. A majority of the Company’s unproved property costs are associated with properties acquired in the Eagle Ford and Wolfcamp shales. Generally, economic recovery of unproved reserves in such areas is not yet supported by actual production or conclusive formation tests, but may be confirmed by our continuing exploration and development programs. Subsequent to the Acquisition (May 25, 2012) to December 31, 3012, we did not record any impairments of our oil and gas properties.

Prior to the Acquisition on May 24, 2012, our predecessor accounted for oil and natural gas producing activities in accordance with the full cost method. Under the full cost accounting method, substantially all of the costs incurred in connection with the acquisition, exploration and development of oil and natural gas reserves were capitalized in full cost pools by country, regardless of whether reserves were actually discovered. Under the full cost method our most critical accounting assessment was a quarterly ceiling test performed on capitalized costs for each full cost pool since many of the variables (reserves, costs and future capital involved significant estimation). Prior to the Acquisition, our predecessor recorded ceiling test charges of $62 million, $152 million, $25 million and $2,123 million for the period from January 1, 2012 through May 24, 2012 and for the years ended 2011, 2010, and 2009, respectively.

Our estimates of proved reserves reflect quantities of oil, natural gas and NGL which geological and engineering data demonstrate, with reasonable certainty, will be recoverable in future years from known reservoirs under existing economic conditions. These estimates of proved oil and natural gas reserves primarily impact our property, plant and equipment amounts on our balance sheets and the depreciation, depletion and amortization amounts including any impairment test charges on our income statements, among other items. The process of estimating oil and natural gas reserves is complex and requires significant judgment to evaluate all available geological, geophysical engineering and economic data. Our proved reserves are estimated at a property level and compiled for reporting purposes by a centralized group of experienced reservoir engineers who work closely with the operating groups. These engineers interact with engineering and geoscience personnel in each of our operating areas and accounting and marketing personnel to obtain the necessary data for projecting future production, costs, net revenues and economic recoverable reserves. Reserves are reviewed internally with senior management quarterly and presented to the board of managers of our parent, EPE Acquisition, LLC, in summary form on an annual basis. Additionally, on an annual basis each property is reviewed in detail by our centralized and operating divisional engineers to ensure forecasts of operating expenses, netback prices, production trends and development timing are reasonable. Our proved reserves are reviewed by internal committees and the processes and controls used for estimating our proved reserves are reviewed by our internal auditors. In addition, a third-party reservoir engineering firm, which is appointed by and reports to the Audit Committee of the board of managers of our parent, EPE Acquisition, LLC, conducts an audit of the estimates of a significant portion of our proved reserves.

As of December 31, 2012, 53% of our total consolidated proved reserves were undeveloped (51% including Four Star) and 7% were developed, but non-producing. The data for a given field may change substantially over time as a result of numerous factors, including additional development activity, evolving production history and a continual reassessment of the viability of production under changing economic conditions. As a result, material revisions to existing reserve estimates occur from time to time. In addition, the subjective decisions and variances in available data for various fields increase the likelihood of significant changes in these estimates.

56

Asset Retirement Obligations.  The accounting guidance for future abandonment costs requires that a liability for the discounted fair value of an asset retirement obligation be recorded in the period in which it is incurred and the corresponding cost capitalized by increasing the carrying amount of the related long-lived asset. The liability is accreted to its present value each period, and the capitalized cost is depreciated over the useful life of the related asset. Future abandonment costs include costs to dismantle and relocate or dispose of our production platforms, gathering systems and related structures and restoration costs of land and seabed. We develop estimates of these costs for each of our properties based upon their geographic location, type of production structure, water depth, reservoir depth and characteristics, market demand for equipment, currently available procedures and ongoing consultations with construction and engineering consultants. Because these costs typically extend many years into the future, estimating these future costs is difficult and requires management to make judgments that are subject to future revisions based upon numerous factors, including changing technology and the political and regulatory environment. We review our assumptions and estimates of future development and abandonment costs on an annual basis, or more frequently if an event occurs or circumstances change that would affect our assumptions and estimates. Additionally, inherent in the present value calculations are numerous assumptions and judgments including the ultimate settlement amounts, inflation factors, credit adjusted discount rates, timing of settlements and changes in the legal, regulatory, environmental and political environments. As of December 31, 2012, our net asset retirement liability was approximately $190 million.

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

The table below presents the hypothetical sensitivity of our commodity-based derivatives to changes in fair values arising from immediate selected potential changes in oil and natural gas prices at December 31, 2012:

			Change in Price
			10 Percent Increase						10 Percent Decrease
	Fair Value		Fair Value			Change			Fair Value		Change
	(in millions)
Commodity-based derivatives—net assets (liabilities)	$	167	$	(218	)	$	(385	)	$	546	$	379

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

57

ITEM 7A.  Qualitative and Quantitative Disclosures About Market Risk

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

Commodity Price Risk

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

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

Interest Rate Risk

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

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

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

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

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

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

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

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

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

58

Commodity Price Risk

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

Sensitivity Analysis. The table below presents the hypothetical sensitivity of our commodity-based derivatives to changes in fair values arising from immediate selected potential changes in oil and natural gas prices, discount rates and credit rates at December 31, 2012:

			Oil and Natural Gas Derivatives
			10 Percent Increase						10 Percent Decrease
	Fair Value		Fair Value			Change			Fair Value		Change
	(in millions)
Price impact(1)	$	167	$	(218	)	$	(385	)	$	546	$	379

			Oil and Natural Gas Derivatives
			1 Percent Increase					1 Percent Decrease
	Fair Value		Fair Value		Change			Fair Value		Change
	(in millions)
Discount Rate(2)	$	167	$	165	$	(2	)	$	169	$	2
Credit rate(3)	$	167	$	166	$	(1	)	$	169	$	2

(1)Presents the hypothetical sensitivity of our commodity-based derivatives to changes in fair values arising from changes in oil and natural gas prices.

(2)Presents the hypothetical sensitivity of our commodity-based derivatives to changes in the discount rates we used to determine the fair value of our derivatives.

(3)Presents the hypothetical sensitivity of our commodity-based derivatives to changes in credit risk.

Interest Rate Risk

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

	December 31, 2012																						December 31, 2011
	Expected Fiscal Year of Maturity of Carrying Amounts																				Fair		Carrying		Fair
	2013			2014			2015			2016			2017			Thereafter			Total		Value		Amounts		Value
	(in millions)
Fixed rate long-term debt	$	—		$	—		$	—		$	—		$	—		$	3,100		$	3,100	$	3,430	$	1	$	1
Average interest rate	8.6		%	8.6		%	8.6		%	8.6		%	8.6		%	8.4		%
Variable rate long-term debt	$	—		$	—		$	—		$	—		$	105		$	1,141		$	1,246	$	1,260	$	850	$	764
Average interest rate	5.2		%	5.2		%	5.2		%	5.2		%	5.0		%	4.6		%

59

Item 8.      FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Index

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

	Page
Reports of Independent Registered Public Accounting Firms	61
Consolidated Statements of Income for (i) the successor period from March 23, 2012 (inception) to December 31, 2012 and (ii) the predecessor periods from January 1, 2012 to May 24, 2012 and the Years Ended December 31, 2011 and 2010	63
Consolidated Statements of Comprehensive Income for (i) the successor period from March 23, 2012 (inception) to December 31, 2012 and (ii) the predecessor periods from January 1, 2012 to May 24, 2012 and the Years Ended December 31, 2011 and 2010	64
Consolidated Balance Sheets as of December 31, 2012 (successor) and December 31, 2011 (predecessor)	65
Consolidated Statements of Cash Flows for (i) the successor period from March 23, 2012 (inception) to December 31, 2012 and (ii) the predecessor periods from January 1, 2012 to May 24, 2012 and the Years Ended December 31, 2011 and 2010	67
Consolidated Statements of Changes in Equity for (i) the successor period from March 23, 2012 (inception) to December 31, 2012 and (ii) the predecessor periods from January 1, 2012 to May 24, 2012 and the Years Ended December 31, 2011 and 2010	68
Notes to Consolidated Financial Statements
1.   Basis of Presentation and Significant Accounting Policies	69
2.   Acquisitions and Divestitures	73
3.   Ceiling Test Charges	74
4.   Income Taxes	75
5.   Financial Instruments	77
6.   Property, Plant and Equipment	80
7.   Long Term Debt	82
8.   Commitments and Contingencies	83
9.   Long-Term Incentive Compensation / Retirement 401(k) Plan	86
10. Investments in Unconsolidated Affiliates	87
11. Related Party Transactions	88
12. Consolidating Financial Statements	91
Supplemental Financial Information
Supplemental Selected Quarterly Financial Information (Unaudited)	103
Supplemental Oil and Natural Gas Operations (Unaudited)	104
Financial Statement Schedule
Schedule II — Valuation and Qualifying Accounts	114

60

Report of Independent Registered Public Accounting Firm

The Audit Committee of the Board of Managers of

EPE Acquisition, LLC:

We have audited the accompanying consolidated balance sheets of EP Energy LLC as of December 31, 2012 (Successor) and December 31, 2011 (Predecessor), and the related consolidated statements of income, comprehensive income, changes in equity, and cash flows for the period from March 23, 2012 to December 31, 2012 (Successor), the period from January 1, 2012 to May 24, 2012 (Predecessor), and each of the two years in the period ended December 31, 2011 (Predecessor). Our audits also included the financial statement schedule listed in Item 8. These financial statements and schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and schedule based on our audits. The financial statements of Four Star Oil & Gas Company (a corporation in which the Company has a 49 percent interest), have been audited by other auditors whose report has been furnished to us, and our opinion on the consolidated financial statements, insofar as it relates to the amounts included from Four Star Oil & Gas Company as of and for the year ended December 31, 2011 (Predecessor), is based solely on the report of other auditors. In the consolidated financial statements, the Predecessor’s investments in unconsolidated affiliates includes approximately $70 million from Four Star Oil & Gas Company as of December 31, 2011, and the Predecessor’s earnings from unconsolidated affiliates includes approximately $29 million for the year ended December 31, 2011, from Four Star Oil & Gas Company.

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

In our opinion, based on our audits and the report of other auditors, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of EP Energy LLC at December 31, 2012 (Successor) and December 31, 2011 (Predecessor), and the consolidated results of its operations and its cash flows the period from March 23, 2012 to December 31, 2012 (Successor), the period from January 1, 2012 to May 24, 2012 (Predecessor), and for each of the two years in the period ended December 31, 2011 (Predecessor), in conformity with U.S. generally accepted accounting principles. Also, in our opinion, the related financial statement schedule, when considered in relation to the basic financial statements taken as a whole, presents fairly in all material respects the information set forth therein.

/s/ Ernst & Young LLP

Houston, Texas

March 1, 2013

61

Report of Independent Registered Public Accounting Firm

To the Board of Directors and the Stockholders of

Four Star Oil & Gas Company:

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

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

/s/PricewaterhouseCoopers LLP

February 24, 2012

Houston, Texas

62

EP ENERGY LLC

CONSOLIDATED STATEMENTS OF INCOME

(In millions)

	Successor			Predecessor
	March 23 (inception) to December 31, 2012			January 1 to May 24, 2012			Year Ended December 31, 2011			Year Ended December 31, 2010
Operating revenues
Oil and condensate	$	567		$	322		$	552		$	346
Natural gas	401			262			973			974
NGL	41			29			57			60
Financial derivatives	(62		)	365			284			390
Other	—			—			1			19
Total operating revenues	947			978			1,867			1,789
Operating expenses
Transportation costs	73			45			85			73
Lease operating expense	136			96			217			193
General and administrative	379			75			201			190
Depreciation, depletion and amortization	268			319			612			477
Impairments/Ceiling test charges	1			62			158			25
Exploration expense	52			—			—			—
Taxes, other than income taxes	61			45			91			85
Other	—			—			—			15
Total operating expenses	970			642			1,364			1,058
Operating (loss) income	(23		)	336			503			731
Loss from unconsolidated affiliates	(1		)	(5		)	(7		)	(7		)
Other income (expense)	3			(3		)	(2		)	3
Loss on extinguishment of debt	(14		)	—			—			—
Interest expense
Third party	(218		)	(14		)	(9		)	(16		)
Affiliated	—			—			(3		)	(5		)
(Loss) income before income taxes	(253		)	314			482			706
Income tax expense	2			136			220			263
Net (loss) income	$	(255	)	$	178		$	262		$	443

See accompanying notes.

63

EP ENERGY LLC

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(In millions)

	Successor			Predecessor
	March 23 (inception) to December 31, 2012			January 1 to May 24, 2012		Year Ended December 31, 2011		Year Ended December 31, 2010
Net (loss) income	$	(255	)	$	178	$	262	$	443
Cash flow hedging activities:
Reclassification adjustment(1)	—			3		7		7
Comprehensive (loss) income	$	(255	)	$	181	$	269	$	450

(1)Reclassification adjustments are stated net of tax. Taxes recognized for the predecessor periods related to January 1, 2012 to May 24, 2012 and the years ended December 31, 2011 and 2010 are $2 million, $4 million and $4 million, respectively.

See accompanying notes.

64

EP ENERGY LLC

CONSOLIDATED BALANCE SHEETS

(In millions)

	Successor December 31, 2012		Predecessor December 31, 2011
ASSETS
Current assets
Cash and cash equivalents	$	63	$	25
Accounts receivable
Customer, net of allowance of less than $1 in 2012 and 2011	226		135
Affiliates	—		132
Other, net of allowance of $1 for 2012 and $7 for 2011	21		39
Materials and supplies	22		28
Derivatives	108		272
Prepaid assets	20		12
Other	4		15
Total current assets	464		658
Property, plant and equipment, at cost
Oil and natural gas properties, of which $481 was excluded from amortization for 2011	7,533		21,923
Other property, plant and equipment	103		147
	7,636		22,070
Less accumulated depreciation, depletion and amortization	266		18,003
Total property, plant and equipment, net	7,370		4,067
Other assets
Investments in unconsolidated affiliates	226		346
Derivatives	88		9
Deferred income taxes	6		7
Unamortized debt issue cost	134		8
Other	5		4
	459		374
Total assets	$	8,293	$	5,099

See accompanying notes.

65

EP ENERGY LLC

CONSOLIDATED BALANCE SHEETS

(In millions, except share amounts)

	SuccessorDecember 31, 2012		PredecessorDecember 31, 2011
LIABILITIES AND EQUITY
Current liabilities
Accounts payable
Trade	$	126	$	140
Affiliates	—		47
Other	358		258
Derivatives	17		7
Accrued taxes other than income	23		33
Accrued interest	57		—
Deferred income taxes	—		91
Accrued taxes	19		—
Asset retirement obligations	10		5
Other accrued liabilities	48		8
Total current liabilities	658		589
Long-term debt	4,346		851
Other long-term liabilities
Derivatives	14		73
Asset retirement obligations	180		148
Deferred income taxes	—		291
Other	10		47
Total non-current liabilities	4,550		1,410
Commitments and contingencies (Note 8)
Member’s/Stockholder’s equity
Common stock, par value $1 per share; 1,000 shares authorized and outstanding at December 31, 2011	—		—
Additional paid-in capital	—		4,580
Accumulated deficit	—		(1,476		)
Accumulated other comprehensive loss	—		(4		)
Member’s equity	3,085		—
Total member’s/stockholder’s equity	3,085		3,100
Total liabilities and equity	$	8,293	$	5,099

See accompanying notes.

66

EP ENERGY LLC

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In millions)

	Successor			Predecessor
	March 23 (inception) to December 31, 2012			January 1 to May 24, 2012			Year Ended December 31, 2011			Year Ended December 31, 2010
Cash flows from operating activities
Net (loss) income	(255		)	$	178		$	262		$	443
Adjustments to reconcile net (loss) income to net cash from operating activities
Depreciation, depletion and amortization	268			319			612			477
Deferred income tax expense	1			199			304			320
Loss from unconsolidated affiliates, adjusted for cash distributions	15			12			53			57
Impairments/Ceiling test charges	1			62			158			25
Loss on extinguishment of debt	14			—			—			—
Amortization of equity compensation expense	17			—			—			—
Non-cash portion of exploration expense	23			—			—			—
Amortization of debt issuance cost	13			7			3			5
Other non-cash income items	—			—			1			—
Asset and liability changes
Accounts receivable	(73		)	132			(20		)	(17		)
Accounts payable	66			(56		)	(67		)	90
Affiliate income taxes	—			4			83			(172		)
Derivatives	281			(201		)	47			(99		)
Accrued interest	57			(1		)	(1		)	1
Other asset changes	(18		)	(3		)	12			16
Other liability changes	39			(72		)	(21		)	(79		)
Net cash provided by operating activities	449			580			1,426			1,067
Cash flows from investing activities
Capital expenditures	(877		)	(636		)	(1,591		)	(1,238		)
Net proceeds from the sale of assets	110			9			612			155
Cash paid for acquisitions, net of cash acquired	(7,126		)	(1		)	(22		)	(51		)
Increase in note receivable with parent	—			—			(236		)	—
Other	—			—			—			4
Net cash used in investing activities	(7,893		)	(628		)	(1,237		)	(1,130		)
Cash flows from financing activities
Proceeds from long term debt	5,477			215			2,030			500
Repayment of long term debt	(1,139		)	(1,065		)	(1,480		)	(1,034		)
Contributed member equity	3,323			—			—			—
Contribution from parent	—			960			—			—
Change in note payable with parent	—			—			(781		)	489
Debt issuance costs	(154		)	—			(7		)	(1		)
Net cash provided by (used in) financing activities	7,507			110			(238		)	(46		)
Change in cash and cash equivalents	63			62			(49		)	(109		)
Cash and cash equivalents
Beginning of period	—			25			74			183
End of period	$	63		$	87		$	25		$	74
Supplemental cash flow information
Interest paid, net of amounts capitalized	$	145		$	7		$	9		$	7
Income tax (refunds) payments	2			2			(158		)	105

See accompanying notes.

67

EP ENERGY LLC

CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY

(In millions, except share amounts)

	Shares		Common Stock		Additional Paid-in Capital			Retained Earnings (Accumulated deficit)			Accumulated Other Comprehensive Income			Total Stockholder’s /Member’s Equity
Predecessor
Balance at December 31, 2010	1,000		$	—	$	4,816		$	(1,738	)	$	(11	)	$	3,067
Distribution to parent			—		(236		)	—			—			(236		)
Other			—		—			—			7			7
Net income			—		—			262			—			262
Balance at December 31, 2011	1,000		$	—	$	4,580		$	(1,476	)	$	(4	)	$	3,100
Contribution from parent			—		1,481			—			—			1,481
Other			—		12			—			3			15
Net income			—		—			178			—			178
Elimination of predecessor parent stockholder’s equity	(1,000	)	—		(6,073		)	1,298			1			(4,774		)
Balance at May 24, 2012	—		$	—	$	—		$	—		$	—		$	—
Successor
Balance at March 23, 2012 (inception)	—		$	—	$	—		$	—		$	—		$	—
Member contributions	—		—		—			—			—			3,323
Equity compensation expense	—		—		—			—			—			17
Net loss	—		—		—			—			—			(255		)
Balance at December 31, 2012	—		$	—	$	—		$	—		$	—		$	3,085

See accompanying notes.

68

EP ENERGY LLC

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

1.  Basis of Presentation and Significant Accounting Policies

Basis of Presentation and Consolidation

EP Energy LLC (the successor) was formed as a Delaware limited liability company on March 23, 2012 by investment funds affiliated with and managed by Apollo Global Management LLC (Apollo) and other private equity investors (collectively, the Sponsors). On May 24, 2012, the Sponsors acquired EP Energy Global LLC (formerly known as EP Energy Corporation and EP Energy, L.L.C. after its conversion into a Delaware limited liability company) and subsidiaries for approximately $7.2 billion in cash (the Acquisition) as contemplated by the merger agreement among El Paso Corporation (El Paso) and Kinder Morgan, Inc. (KMI) which is further described in Note 2. The entities acquired are engaged in the exploration for and the acquisition, development, and production of oil, natural gas and NGL primarily in the United States, with international activities in Brazil, and together these entities constituted the oil and natural gas operations of El Paso. Hereinafter, the acquired entities are referred to as the predecessor for financial accounting and reporting purposes.

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

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

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

Use of Estimates

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

Revenue Recognition

Our revenues are generated primarily through the physical sale of oil, condensate, natural gas and NGL. Revenues from sales of these products are recorded upon delivery and the passage of title using the sales method, net of any royalty interests or other profit interests in the produced product. Revenues related to products delivered, but not yet billed, are estimated each month. These estimates are based on contract data, commodity prices and preliminary throughput and allocation measurements. When actual sales volumes exceed our entitled share of sales volumes, an overproduced imbalance occurs. To the extent the overproduced imbalance exceeds our share of the remaining estimated proved natural gas reserves for a given property, we record a liability. Costs associated with the transportation and delivery of production are included in transportation costs. For the successor period, we had one customer that accounted for 10 percent or more of our total revenues.  The predecessor period in 2012 had three customers, and for the years ended December 31, 2011 and 2010, had one customer that accounted for 10 percent or more of total revenues.  The loss of any one customer would not have an adverse effect on our ability to sell our oil, natural gas and NGL production.

69

Cash and Cash Equivalents

We consider short-term investments with an original maturity of less than three months to be cash equivalents. As of December 31, 2012 and 2011, we had less than $1 million, respectively, of restricted cash in other current assets to cover escrow amounts required for leasehold agreements in our domestic operations.

Allowance for Doubtful Accounts

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

Oil and Natural Gas Properties

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

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

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

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

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

70

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

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

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

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

Accounting for Asset Retirement Obligations

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

Accounting for Long-Term Incentive Compensation

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

71

Environmental Costs and Other Contingencies

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

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

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

Derivatives

We enter into derivative contracts on our oil and natural gas products primarily to stabilize cash flows and reduce the risk and financial impact of downward commodity price movements on commodity sales.  We also use derivatives to reduce the risk of variable interest rates.

Our derivatives are reflected on our balance sheet at their fair value as assets and liabilities. We classify our derivatives as either current or non-current assets or liabilities based on their anticipated settlement date. We net derivative assets and liabilities on counterparties where we have a legal right of offset.

All of our derivatives are marked-to-market each period and changes in the fair value of our commodity based derivatives, as well as any realized amounts, are reflected as operating revenues.  Changes in the fair value of our interest rate derivatives are reflected as interest expense.

In our cash flow statement, cash inflows and outflows associated with the settlement of our derivative instruments are recognized in operating cash flows. In our balance sheet, receivables and payables resulting from the settlement of our derivative instruments are reported as trade receivables and payables. See Note 5 for a further discussion of our derivatives.

Income Taxes

We are a limited liability company, treated as a partnership for federal and state income tax purposes, with income tax liabilities and/or benefits of the Company passed through to our members. We are, however subject to the Texas margin tax and pay any liability directly to the state of Texas.  The aggregate difference in the basis of net assets for financial and tax reporting purposes cannot be readily determined as the Company does not have access to information about each member’s tax attributes.

72

Our Brazilian operations are corporate entities for Brazil purposes.  For Brazil, we record current income taxes based on our current taxable income and provide for deferred income taxes to reflect estimated future tax payments and receipts. We also record deferred tax assets and liabilities, which represent the tax impacts of differences between the financial statement and tax bases of assets and liabilities and carryovers at each year end. We account for tax credits in Brazil under the flow-through method, which reduces the provision for income taxes in the year the tax credits first become available.

The realization of our deferred tax assets related to our Brazilian operations depends on recognition of sufficient future taxable income in Brazil during periods in which those temporary differences are deductible. We reduce deferred tax assets by a valuation allowance when, based on our estimates, it is more likely than not that a portion of those assets will not be realized in a future period. The estimates utilized in recognition of deferred tax assets are subject to revision, either up or down, in future periods based on new facts or circumstances. In evaluating our valuation allowances, we consider the reversal of existing temporary differences, the existence of taxable income in prior carryback years, tax-planning strategies and future taxable income, the latter two of which involve the exercise of significant judgment. Changes to our valuation allowances could materially impact our results of operations.

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

2.  Acquisitions and Divestitures

Acquisitions.On May 24, 2012, Apollo and other investors acquired all of the equity of EP Energy Global LLC for approximately $7.2 billion. The Acquisition was funded with approximately $3.3 billion in equity contributions and the issuance of approximately $4.25 billion of debt. In conjunction with the sale, a portion of the proceeds were also used to repay approximately $960 million outstanding under predecessor’s revolving credit facility at that time. See Note 7 for additional discussion of debt.

The purchase transaction was accounted for under the acquisition method of accounting which requires, among other items, that assets and liabilities assumed be recognized on the balance sheet at their fair values as of the Acquisition date. Our consolidated balance sheet presented as of December 31, 2012, reflects our purchase price allocation based on available information to specific assets and liabilities assumed based on estimates of fair values and costs. There was no goodwill associated with the transaction.

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

73

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

	Year ended December 31, 2012		Year ended December 31, 2011
	(In millions)
Operating Revenues	$	1,925	$	1,867
Net Income	143		454

Divestitures.  In 2012, our divestitures primarily related to the sale of our Egypt interests for approximately $22 million and the sale of oil and natural gas properties located in the Gulf of Mexico for a gross purchase price of approximately $103 million. Proceeds from the Gulf of Mexico sale net of purchase price adjustments were approximately $79 million.  We did not record a gain or loss on any of these sales as the purchase price allocated to the assets sold was reflective of the estimated sales price of these properties and the relationship between capitalized costs and proved reserves was not altered. During 2011, the predecessor sold non-core oil and natural gas properties located in the Eagle Ford, Southern and Central divisions in several transactions from which they received proceeds that totaled approximately $612 million. During 2010, the predecessor sold processing plants and related gathering systems for cash proceeds of approximately $126 million. The predecessor did not record a gain or loss on any of these sales.

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

3.  Ceiling Test Charges

Under the full cost method of accounting, the predecessor recorded ceiling test charges of capitalized costs in each of the full cost pools as noted in the table below.

	Predecessor
	January 1 to May 24, 2012		Year Ended December 31, 2011		Year Ended December 31, 2010
	(In millions)
U.S.	$	—	$	6	$	—
Brazil	—		152		—
Egypt	62		—		25
Total	$	62	$	158	$	25

During the first quarter of 2012, the predecessor recorded a non-cash ceiling test charge of approximately $62 million as a result of the decision to exit exploration and development activities in Egypt. The charge related to unevaluated costs in that country and included approximately $2 million related to equipment. Forward commodity prices can play a significant role in determining impairments. Due to the current forecast of future natural gas prices and considering the significant amount of fair value allocated to our natural gas and oil properties in conjunction with the Acquisition, sustained lower natural gas and oil prices from present levels could result in an impairment of the carrying value of our proved properties in the future. For the predecessor period ended December 31, 2011, ceiling test charges of approximately $152 million related to Brazil oil and natural gas operations were recorded and an impairment of certain oil field related materials and supplies of $6 million was recorded.

74

4.  Income Taxes

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

	Successor			Predecessor
	March 23 (inception) to December 31, 2012			January 1 to May 24, 2012			Year ended December 31, 2011			Year ended December 31, 2010
				(In millions)
Pretax (Loss) Income
U.S.	$	(269	)	$	387		$	635		$	736
Foreign	16			(73		)	(153		)	(30		)
	$	(253	)	$	314		$	482		$	706
Components of Income Tax Expense (Benefit)
Current
Federal	$	—		$	(61	)	$	(77	)	$	(71	)
State	—			(3		)	1			3
Foreign	1			1			(8		)	11
	1			(63		)	(84		)	(57		)
Deferred
Federal	—			188			284			314
State	—			11			19			12
Foreign	1			—			1			(6		)
	1			199			304			320
Total income tax expense	$	2		$	136		$	220		$	263

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

	Successor			Predecessor
	March 23 (inception) to December 31, 2012			January 1 to May 24, 2012			Year ended December 31, 2011			Year ended December 31, 2010
				(In millions, except rates)
Income taxes at the statutory federal rate of 35%	$	(89	)	$	110		$	169		$	247
Increase (decrease)
State income taxes, net of federal income tax effect	—			5			12			10
Partnership earnings not subject to tax	89			—			—			—
Earnings from unconsolidated affiliates where we received or will receive dividends	—			(2		)	(8		)	(9		)
Valuation allowances	—			—			23			6
Foreign income (loss) taxed at different rates	2			27			24			9
Other	—			(4		)	—			—
Income tax expense (benefit)	$	2		$	136		$	220		$	263
Effective tax rate	1		%	43		%	46		%	37		%

75

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

Deferred Tax Assets and Liabilities.  The following are the components of net deferred tax assets and liabilities:

	Successor December 31, 2012			Predecessor December 31, 2011
	(In millions)
Deferred tax liabilities
Property, plant and equipment	$	—		$	(495	)
Investments in unconsolidated affiliates	—			(67		)
Derivatives	—			(73		)
Other	(5		)	—
Total deferred tax liabilities	(5		)	(635		)
Deferred tax assets
Net operating loss and tax credit carryovers	116			458
Property, plant and equipment	167			112
Other	—			3
Valuation allowance	(272		)	(313		)
Total deferred tax assets	11			260
Net deferred tax assets (liabilities)	$	6		$	(375	)

As a partnership, for U.S. federal and state income tax purposes, we do not record differences between the underlying tax and book basis of our assets and liabilities as deferred taxes.  Thus, the deferred balances in the table above relate solely to Brazil. In conjunction with the Acquisition, U.S. deferred taxes of the predecessor were settled with El Paso through a non-cash contribution.

Unrecognized Tax Benefits. We are not currently subject to any U.S. or state income tax audits.  Furthermore, pursuant to the Acquisition agreement, KMI indemnified us for any successor liability due to most of our entities having been members of the El Paso federal and state returns for any adjustments through the Acquisition date.  In Brazil, we continue to have a number of years in which our Brazilian returns are subject to review. The following table shows the balance of unrecognized tax benefits and changes therein:

	Successor March 23, 2012 (inception) to December 31. 2012			Predecessor Year ended December 31. 2011
	(In millions)
Amount at beginning of period	$	—		$	30
Amount at Acquisition date	7			—
Foreign currency fluctuations	(1		)	(1		)
Settlements with taxing authorities	—			(1		)
Amount at December 31	$	6		$	28

76

As of December 31, 2012 unrecognized tax benefits and any associated interest and penalties would not affect our recorded income tax expense or our effective income tax rate if recognized in future periods since our 2012 deferred tax assets as of December 31, 2012 are fully offset by a valuation allowance. As noted in the table above, unrecognized tax benefits for the predecessor were transferred to KMI as part of the Acquisition.

We classify interest and penalties related to unrecognized tax benefits as income taxes in our financial statements. We did not recognize interest and penalties in our consolidated income statements in 2012, nor do we have any accrued interest and penalties in our consolidated balance sheet as of December 31, 2012. As of December 31, 2011, the predecessor had $2 million of accrued interest and penalties in the consolidated balance sheet, and recognized $7 million in interest and penalties related to unrecognized tax benefits.

Net Operating Loss and Tax Credit Carryovers.  As of December 31, 2012 we have foreign net operating loss carryovers of $258 million and capital loss carryovers of $82 million. The losses related to Brazil are carried over indefinitely and can be utilized to offset up to 30 percent of Brazilian taxable income annually. As of December 31, 2011, the predecessor had $816 million of federal net operating loss and $340 million of state net operating loss that were transferred to KMI as part of the Acquisition.

Valuation Allowances.  As of December 31, 2012, our valuation allowance relates to deferred tax assets recorded on foreign net operating losses and temporary differences. We believe it is more likely than not that we will realize the benefit of our deferred tax assets, net of existing valuation allowances.  Changes to the valuation allowance are shown in the table below:

	Successor March 23, 2012 (inception) to December 31. 2012			Predecessor Year ended December 31. 2011
	(In millions)
Amount at beginning of period	$	—		$	291
Amount at Acquisition date (1)	323			—
Temporary differences for local differences, impairments, depreciation, depletion and amortization and foreign currency translation	(19		)	28
Net operating losses	(2		)	(6		)
Transfer on sale of Egypt	(30		)	—
Amount at December 31	$	272		$	313

(1) Includes a fair value adjustment at Acquisition date of $10 million.

5.  Financial Instruments

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

	Successor December 31, 2012				Predecessor December 31. 2011
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	(In millions)
Long-term debt	$	4,346	$	4,690	$	851	$	765
Derivatives	$	165	$	165	$	201	$	201

77

For the years ended December 31, 2012 and 2011, the carrying amounts of cash and cash equivalents, accounts receivable and accounts payable represent fair value because of the short-term nature of these instruments.  We hold long term debt obligations (see Note 7) with various terms. We estimated the fair value of debt (representing a Level 2 fair value measurement) primarily based on quoted market prices for the same or similar issuances, including consideration of our credit risk related to these instruments.

Oil and Natural Gas Derivatives.  We attempt to mitigate a portion of our commodity price risk and stabilize cash flows associated with forecasted sales of oil and natural gas production through the use of oil and natural gas swaps, basis swaps and option contracts. As of December 31, 2012 and 2011, 34,232 MBbl and 14,530 MBbl of oil and 276 TBtu and 105 TBtu of natural gas, respectively, are hedged through derivatives. None of these contracts are designated as accounting hedges. In January and February of 2013, we added fixed price oil derivatives of 3,311 MBbl and fixed price natural gas derivatives of 18 TBtu.  In addition, we added oil basis swaps of 6,570 MBbl related to a portion of our crude differential exposure.

Interest Rate Derivatives. During July 2012, we entered into interest rate swaps with a notional amount of $600 million that are intended to reduce variable interest rate risk. These interest rate derivatives started in November 2012 and extend through April 2017.  As of December 31, 2012, we have a $2 million net liability related to interest rate derivatives listed in our balance sheet. For the successor period of March 23 to December 31, 2012 we recorded an increase of $3 million in interest expense related to our interest rate derivatives.

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

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

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

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

As of December 31, 2012 and 2011, all financial instruments were classified as Level 2. Our assessment of an instrument within a level can change over time based on the maturity or liquidity of the instrument, which could result in a change in the classification of our financial instruments between other levels.

78

Financial Statement Presentation.  The following table presents the fair value of derivative financial instruments at December 31, 2012 and 2011.  Derivative assets and liabilities are netted with counterparties where we have a legal right of offset and derivatives are classified as either current or non-current assets or liabilities based on their anticipated settlement date.  On certain derivative contracts recorded as assets in the table below we are exposed to the risk that our counterparties may not perform or post the required collateral.

	Level 2
	Successor December 31. 2012			Predecessor December 31. 2011
	(In millions)
Assets
Oil and natural gas derivatives	$	231		$	304
Interest rate derivatives		4			—
Impact of master netting arrangements		(39	)		(23	)
Total net assets	196			281
Liabilities
Oil and natural gas derivatives	(64		)	(103		)
Interest rate derivatives	(6		)	—
Impact of master netting arrangements	39			23
Total net liabilities	(31		)	(80		)
Total	$	165		$	201

The following table presents realized and unrealized net gains and losses on financial oil and natural gas derivatives presented in operating revenues and dedesignated cash flow hedges of the predecessor included in accumulated other comprehensive income (in millions):

	Successor			Predecessor
	March 23 (inception) to December 31,			January 1 to May 24,		Years ended December 31,
	2012			2012		2011		2010
Realized and unrealized (losses) gains	$	(62	)	$	365	$	284	$	390
Accumulated other comprehensive income	—			5		11		11

Credit Risk. We are subject to the risk of loss on our financial instruments that we would incur as a result of non-performance by counterparties pursuant to the terms of their contractual obligations. We maintain credit policies with regard to our counterparties to minimize our overall credit risk. These policies require (i) the evaluation of potential counterparties’ financial condition to determine their credit worthiness; (ii) the daily monitoring of our oil, natural gas and NGL counterparties’ credit exposures; (iii) comprehensive credit reviews on significant counterparties from physical and financial transactions on an ongoing basis; (iv) the utilization of contractual language that affords us netting or set off opportunities to mitigate exposure risk; and (v) requiring counterparties to post cash collateral, parent guarantees or letters of credit to minimize credit risk.  Our assets from derivatives at December 31, 2012 represent derivative instruments from nine counterparties; all of which are financial institutions that have an “investment grade” (minimum Standard & Poor’s rating of A- or better) credit rating. We enter into derivatives directly with third parties and are not currently required to post collateral or other security for credit risk. Subject to the terms of our $2 billion RBL credit facility, collateral or other securities are not exchanged in relation to derivatives activities with the parties in the RBL credit facility.

79

6.  Property, Plant and Equipment

Unproved Oil and Natural Gas Properties (Successor).  As of the Acquisition date and December 31, 2012, we had $3.0 billion and $2.3 billion of unproved oil and natural gas properties on our balance sheet primarily a result of the allocation of the purchase price in conjunction with the Acquisition.  The reduction is largely attributable to transferring approximately $0.7 billion from unproved properties to proved properties. In addition, we recorded $23 million of amortization of unproved leasehold costs in exploration expense in our income statement. Suspended well costs were not material as of December 31, 2012.

Unevaluated Capitalized Costs (Predecessor). As of December 31, 2011 unevaluated capitalized costs related to oil and natural gas properties were $399 million in the U.S. and $82 million in Egypt and Brazil. The predecessor excluded capitalized costs of oil and natural gas properties from amortization that were in various stages of evaluation or were part of a major development project.

Presented below is an analysis of the capitalized costs of oil and natural gas properties by year of expenditure that were not being amortized as of December 31, 2011 pending determination of proved reserves (in millions):

	CumulativeBalanceDecember 31,		Costs Excludedfor Years EndedDecember 31(1)				CumulativeBalanceJanuary 1,
	2011		2011		2010		2010
U.S.
Acquisition	$	301	$	20	$	206	$	75
Exploration	98		80		4		14
Total U.S.(2)	399		100		210		89
Egypt & Brazil
Acquisition	36		1		—		35
Exploration	46		8		20		18
Total Egypt & Brazil(3)	82		9		20		53
Worldwide	$	481	$	109	$	230	$	142

(1)Included capitalized interest of $2 million and $6 million for the years ended December 31, 2011 and 2010.

(2)Included $155 million related to the Wolfcamp Shale and $94 million related to the Eagle Ford Shale at December 31, 2011.

(3)Included $8 million related to Brazil at December 31, 2011.

Asset Retirement Obligations.  We have legal obligations associated with the retirement of our oil and natural gas wells and related infrastructure. We have obligations to plug wells when production on those wells is exhausted, when we no longer plan to use them or when we abandon them. We accrue a liability on those legal obligations when we can estimate the timing and amount of their settlement and include obligations where we will be legally required to replace, remove or retire the associated assets.

80

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

	Successor March 23 (inception) to December 31. 2012			Predecessor January 1 to December 31. 2011
	(In millions)
Net asset retirement liability at beginning of period	$	—		$	135
Fair value of asset retirement liability at Acquisition date(1)	241			—
Liabilities settled	(3		)	(16		)
Property sale(2)	(64		)	(9		)
Accretion expense	9			13
Liabilities incurred	7			3
Changes in estimate	—			27
Net asset retirement liability at December 31	$	190		$	153

(1)Includes a fair value adjustment at Acquisition date of approximately $34 million.

(2)For the succesor period, property sales relate to the sale of properties in the Gulf of Mexico.

Capitalized Interest.  Interest expense is reflected in our financial statements net of capitalized interest. We capitalize interest primarily on the costs associated with drilling and completing wells until production begins. The interest rate used is the weighted average interest rate of our outstanding borrowings. Capitalized interest for the successor period from March 23, 2012 (inception) to December 31, 2012 was $12 million. Capitalized interest for the predecessor periods from January 1, 2012 to May 24, 2012, the year ended December 31, 2011 and 2010 was $4 million, $13 million and $9 million.

81

7.  Long Term Debt

In conjunction with the Acquisition, we issued or obtained approximately $4.25 billion of debt and repaid predecessor amounts outstanding with an equity contribution from El Paso. During 2012, we also re-priced our $750 million term loan at an effective interest rate of 5.0% from 6.5%, issued an additional $350 million of senior unsecured notes and obtained an additional $400 million through a senior secured term loan.  Proceeds were primarily used to paydown amounts outstanding under our RBL credit facility.  Listed below are additional details related to each of our debt obligations and their book values as of the periods presented:

	Interest Rate	SuccessorDecember 31, 2012		PredecessorDecember 31,2011
		(In millions)
$1 billion revolving credit facility - due June 2, 2016	Variable	$	—	$	850
Senior notes - due June 1, 2013	7.75%	—		1
$2 billion RBL credit facility - due May 24, 2017	Variable	105		—
$750 million term loan - due April 24, 2018 (1) (3)	Variable	742		—
$400 million senior secured term loan - due April 30, 2019 (2) (3)	Variable	399		—
$750 million senior secured note - due May 1, 2019 (3)	6.875%	750		—
$2.0 billion senior unsecured note - due May 1, 2020	9.375%	2,000		—
$350 million senior unsecured note - due September 1, 2022	7.75%	350		—
Total		$	4,346	$	851

(1)The Term Loan was issued at 99 percent of par and carries a specified margin over the LIBOR of 4.00%, with a minimum LIBOR floor of 1.00%. As of December 31, 2012 the effective interest rate of the note was 5.00%.

(2)The Term Loan carries a specified margin over the LIBOR of 3.50%, with a minimum LIBOR floor of 1.00%.

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

As of December 31, 2012 we have $134 million in deferred financing costs as a result of our 2012 financings. During 2012 we amortized $7 million of deferred financing costs in the predecessor period and $13 million in the succesor period.  These costs are included in interest expense.  We also recorded a $14 million loss on debt extinguishment in our income statement reflecting the pro-rata portion of deferred financing costs written off, debt discount and call premiums paid related to lenders who exited or reduced their loan commitments in conjunction with our $750 million term loan repricing.

$2.0 Billion Reserve-based Loan (RBL). We have a $2.0 billion credit facility in place which allows us to borrow funds or issue letters of credit (LCs). Our credit facility is collateralized by certain of our oil and natural gas properties and has a borrowing base subject to redetermination semi-annually beginning in April 2013. A downward revision of our oil and natural gas reserves due to future declines in commodity prices, performance revisions or otherwise, could require a redetermination of the borrowing base and could negatively impact our ability to borrow funds from such facilities in the future.  Our borrowing base is also impacted if certain other additional debt is incurred.  As of December 31, 2012, the RBL borrowing base was approximately $1.8 billion. As of December 31, 2012, we had borrowings outstanding under the credit facility of $105 million, approximately $9 million of letters of credit issued, and we had remaining capacity of approximately $1.7 billion. As of February 27, 2013, we had an additional $160 million drawn under our RBL Facility. Listed below is a further description of our credit facility as of December 31, 2012:

Credit Facility	Maturity Date	Interest Rate	Commitment fees
$2.0 billion RBL	May 24, 2017	LIBOR + 1.50%(1) 1.50% for LCs	0.375% commitment fee on unused capacity

(1)  Based on our December 31, 2012 borrowing level. Amounts outstanding under the $2.0 billion RBL facility bear interest at specified margins over the LIBOR of between 1.50% and 2.50% for Eurodollar loans or at specified margins over the Alternative Base Rate (ABR) of between 0.50% and 1.50% for ABR loans. Such margins will fluctuate based on the utilization of the facility.

82

Guarantees.  Our obligations under the RBL, term loan, secured and unsecured notes are fully and unconditionally guaranteed, jointly and severally, by the Company’s present and future direct and indirect wholly owned material domestic subsidiaries. Our foreign wholly-owned subsidiaries are not parties to the guarantees. As of December 31, 2012, foreign subsidiaries that will not guarantee the notes held approximately 2% of our consolidated assets and had no outstanding indebtedness, excluding intercompany obligations. For the period from March 23, 2012 (inception) to December 31, 2012 these non-guarantor subsidiaries generated approximately 7% of our revenue including the impacts of financial derivatives.  We have provided consolidating financial statements which include the separate results of our guarantor and non-guarantor subsidiaries in Note 12.

Restrictive Provisions/Covenants.The availability of borrowings under our credit agreements and our ability to incur additional indebtedness is subject to various financial and non-financial covenants and restrictions. Our most restrictive financial covenant requires that our debt to EBITDAX ratio, as defined in the credit agreement, must not exceed 5.0 to 1.0 during the current period. Certain other covenants and restrictions, among other things, also limit our ability to incur or guarantee additional indebtedness; make any restricted payments or pay any dividends on equity interests or redeem, repurchase or retire parent entities’ equity interests or subordinated indebtedness; sell assets; make investments; create certain liens; prepay debt obligations; engage in transactions with affiliates; and enter into certain hedge agreements. As of December 31, 2012, we were in compliance with our debt covenants.

8.  Commitments and Contingencies

Legal Proceedings and Other Contingencies

We and our subsidiaries and affiliates are named defendants in numerous legal proceedings that arise in the ordinary course of our business. There are also other regulatory rules and orders in various stages of adoption, review and/or implementation. For each of these matters, we evaluate the merits of the case or claim, our exposure to the matter, possible legal or settlement strategies and the likelihood of an unfavorable outcome. We disclose matters that are reasonably possible of negative outcome and material to our financial statements. If we determine that an unfavorable outcome is probable and can be estimated, we establish the necessary accruals. While the outcome of our current matters cannot be predicted with certainty and there are still uncertainties related to the costs we may incur, based upon our evaluation and experience to date, we believe we have established appropriate reserves. It is possible, however, that new information or future developments could require us to reassess our potential exposure related to these matters and adjust our accruals accordingly, and these adjustments could be material. As of December 31, 2012, we had approximately $20 million accrued for all outstanding legal proceedings and other contingent matters, including a reserve related to an audit of sales and use taxes in the State of Texas.

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

83

Environmental Matters

We are subject to existing federal, state and local laws and regulations governing environmental air, land and water quality.  The environmental laws and regulations to which we are subject also require us to remove or remedy the effect on the environment of the disposal or release of specified substances at current and former operating sites. As of December 31, 2012, we had accrued less than $1 million for related environmental remediation costs associated with onsite, offsite and groundwater technical studies and for related environmental legal costs. Our accrual represents a combination of two estimation methodologies. First, where the most likely outcome can be reasonably estimated, that cost has been accrued. Second, where the most likely outcome cannot be estimated, a range of costs is established and if no one amount in that range is more likely than any other, the lower end of the expected range has been accrued. Our exposure could be as high as $1 million.  Our environmental remediation projects are in various stages of completion. The liabilities we have recorded reflect our current estimates of amounts that we will expend to remediate these sites. However, depending on the stage of completion or assessment, the ultimate extent of contamination or remediation required may not be known. As additional assessments occur or remediation efforts continue, we may incur additional liabilities.

Climate Change and other Emissions.  The EPA and several state environmental agencies have adopted regulations to regulate greenhouse gas (GHG) emissions. Although the EPA has adopted a “tailoring” rule to regulate GHG emissions, at this time we do not expect a material impact to our existing operations. There have also been various legislative and regulatory proposals and final rules at the federal and state levels to address emissions from power plants and industrial boilers. Although such rules and proposals will generally favor the use of natural gas over other fossil fuels such as coal, it remains uncertain what regulations will ultimately be adopted and when they will be adopted. In addition, any regulations regulating GHG emissions would likely increase our costs of compliance by potentially delaying the receipt of permits and other regulatory approvals; requiring us to monitor emissions, install additional equipment or modify facilities to reduce GHG and other emissions; purchase emission credits; and utilize electric-driven compression at facilities to obtain regulatory permits and approvals in a timely manner.

Air Quality Regulations. In August 2010, the EPA finalized a rule that impacts emissions of hazardous air pollutants from reciprocating internal combustion engines and requires us to install emission controls on engines across our operations. Engines subject to the regulations have to be in compliance by October 2013. We currently estimate we will incur capital expenditures in 2013 to complete the required modifications and testing of less than $1 million.

In August 2012, EPA finalized New Source Performance Standard regulations to reduce various air pollutants from the oil and natural gas industry. These regulations will limit emissions from the hydraulic fracturing of certain natural gas wells and equipment including compressors, storage vessels and natural gas processing plants. We do not anticipate a material impact associated with compliance to these new requirements.

In the State of Utah we are currently obtaining or amending air quality permits for a number of small oil and natural gas production facilities. As part of this permitting process we anticipate the installation of tank emission controls that will require approximately $3 million capital expenditures starting in 2013 and extending through 2014.

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

84

Comprehensive Environmental Response, Compensation and Liability Act (CERCLA) Matters. As part of our environmental remediation projects, we have received notice that we could be designated, or have been asked for information to determine whether we could be designated as a Potentially Responsible Party (PRP) with respect to the Casmalia Remediation site located in California under the CERCLA or state equivalents. As of December 31, 2012, we have estimated our share of the remediation costs at this site to be less than $1 million. Because the clean-up costs are estimates and are subject to revision as more information becomes available about the extent of remediation required, and in some cases we have asserted a defense to any liability, our estimates could change. Moreover, liability under the federal CERCLA statute may be joint and several, meaning that we could be required to pay in excess of our pro rata share of remediation costs. Our understanding of the financial strength of other PRPs has been considered, where appropriate, in estimating our liabilities. Accruals for these matters are included in the environmental reserve discussed above.

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

Lease Obligations

We maintain operating leases in the ordinary course of our business activities.  These leases include those for office space and various equipment.  The terms of the agreements vary from 2012 until 2017.  Future minimum annual rental commitments under non-cancelable future operating lease commitments at December 31, 2012, were as follows:

Year Ending December 31,	Operating Leases
	(In millions)
2013	$	14
2014	13
2015	14
2016	13
2017	8
Total	$	62

Rental expense for the successor period from March 23, 2012 (inception) to December 31, 2012 was $10 million. Rental expense for the predecessor periods from January 1, 2012 to May 24, 2012, the years ended December 31, 2011 and 2010 was $1 million, $2 million and $2 million, respectively.

Other Commercial Commitments

At December 31, 2012, we have various commercial commitments totaling $1,074 million primarily related to commitments and contracts associated with volume and transportation, drilling rigs, completion activities, seismic activities and management fees. Our annual obligations under these arrangements are $161 million in 2013, $134 million in 2014, $108 million in 2015, $114 million in 2016, $104 million in 2017 and $453 million thereafter.

85

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

EP Energy LLC Long Term Incentive Compensation Programs. Upon the closing of the Acquisition, we adopted new long term incentive (LTI) programs, including an annual performance-based cash incentive payment program and certain long-term equity based programs:

·Cash-Based Long Term Incentive.  In addition to annual bonus payments, we provide a long term cash-based incentive program to certain of our employees linking annual performance-based cash incentive payments to the financial performance of the company as approved by the Compensation Committee of the board of managers of our parent, EPE Acquisition, LLC, and individual performance for the year. Cash-based LTI awards are expected to be granted annually and have a three-year vesting schedule (50% vesting at the end of the first year, and 25% vesting at the end of each of the succeeding two years). For accounting purposes, these performance based cash incentive awards have been treated as liability awards with a fair value on the grant date of approximately $23 million. For the period from March 23, 2012 to December 31, 2012, we recorded approximately $8 million in expense related to these awards.  As of December 31, 2012, we had unrecognized compensation expense of $12 million related to these awards of which approximately $8 million will be recognized in 2013 and the remainder on an accelerated basis over the remaining requisite service period.

·Long Term Equity Incentive Awards.  We provide certain individuals with two forms of long term equity incentive awards as follows:

·Class A “Matching” Grants.  In conjunction with the Acquisition, our employees purchased a total of approximately 24,000 Class A units (at a purchase price of $1,000 per Class A unit). In connection with their purchase of these units, these employees were awarded (i)  “matching” Class A unit grants in an amount equal to 50% of the Class A units purchased (approximately 12,000 units) and (ii) a “guaranteed cash bonus” to be paid in early 2013 equivalent to the amount of the “matching” Class A unit grant.  Matching units are subject to repurchase by the company in the event of certain termination scenarios. For accounting purposes, we treated the “guaranteed cash bonus” amounts as liability awards to be settled in cash and the “matching” Class A unit grants as compensatory equity awards. These awards had a combined fair value of approximately $24 million on the grant date. For the “guaranteed cash bonus”, we will recognize the fair value as compensation cost over the period from the date of grant (May 24, 2012) through the anticipated cash payout date in early 2013. For the “matching” Class A unit grant, we will recognize the fair value as compensation cost ratably over the four year period from the date of grant through the period over which the requisite service is provided and the time period at which certain transferability restrictions are removed. For the period from March 23, 2012 to December 31, 2012, we recognized approximately $11 million related to both of these awards.  As of December 31, 2012, we had unrecognized compensation expense of $13 million related to both of these awards, of which we will recognize $6 million in 2013 and the remainder ratably thereafter as noted above.

·Management Incentive Units.  In addition to the Class A “matching” awards described above, certain employees were awarded approximately 808,000 Management Incentive Units (“MIPs”). These MIPs are intended to constitute profits interests. The MIPs are scheduled to vest ratably over 5 years subject to certain forfeiture provisions based on continued employment with the company, although 25% of any vested awards are forfeitable in the event of certain termination events. The MIPs become payable based on the achievement of certain predetermined performance measures, including, without limitation, the occurrence of certain specified capital transactions. The MIPs were issued at no cost and have value only to the extent the value of the company increases. For accounting purposes, these profits interests were treated as compensatory equity awards. The grant date fair value of this award was determined using a non-controlling, non-marketable option pricing model which valued these management incentive units

86

assuming a 0.77 %  risk free rate, a 5 year time to expiration, and a 73 percent volatility rate.  Based on these factors, we determined a grant date fair value of $74 million. For the period from March 23, 2012 to December 31, 2012, we recognized approximately $15 million related to these awards.  As of December 31, 2012, we had unrecognized compensation expense of $59 million. Of this amount, $40 million of the unrecognized compensation expense, net of forfeitures, will continue to be recognized on an accelerated basis for each tranche of the award, over the remainder of the five year requisite service period. The remaining $19 million will be recognized upon a specified capital transaction when the right to such amounts become nonforfeitable.

Retirement 401(k) Plan.  We sponsor a tax-qualified defined contribution retirement plan for a broad-based group of employees.  We make matching contributions (dollar for dollar up to 6% of eligible compensation) and non-elective employer contributions (5% of eligible compensation) to the plan, and individual employees are also eligible to contribute to the defined contribution plan. As of December 31, 2012, we had contributed $7 million of matching contributions.

Equity Awards Outstanding Prior to Acquisition.Prior to the merger between KMI and El Paso, certain of our employees held vested and unvested stock options, restricted shares and performance shares granted under El Paso’s equity plan. Pursuant to the terms of the merger agreement between El Paso and KMI, each outstanding El Paso stock option, restricted share and performance share automatically vested upon completion of the merger. In the case of outstanding performance shares, performance was deemed to be attained at target. On the merger date, each outstanding stock option, restricted share and performance share was converted into the right to receive either cash or a mixture of cash and shares of KMI common stock for all shares subject to such awards (in the case of stock options, less the aggregate exercise price), pursuant to the terms of the El Paso/KMI merger agreement. Each holder also received warrants as part of the merger consideration in respect of such equity awards. Through the merger date, the predecessor recorded as general and administrative expense in the income statements, amounts billed directly by El Paso for compensation expense related to these stock-based compensation awards granted directly to its employees, as well as its proportionate share of El Paso’s corporate compensation expense. However, compensation cost associated with the acceleration of vesting as a result of the merger between El Paso and KMI was assumed by El Paso and KMI and is not reflected in the predecessor financial statements.

10.  Investments in Unconsolidated Affiliates

We hold investments in two unconsolidated affiliates, Four Star Oil & Gas Company (Four Star) and Black Warrior Transmission Corporation, which we account for using the equity method of accounting. Our income statement reflects (i) our share of net earnings directly attributable to these unconsolidated affiliates, and (ii) other adjustments, such as the amortization of the excess of the carrying value of our investment relative to the underlying equity in the net assets of the entity.  As of December 31, 2012 and December 31, 2011, our total investment in unconsolidated affiliates was $226 million and $346 million ($281 million net of related deferred income taxes).  Included in these amounts was approximately $125 million and $272 million ($207 million net of related deferred income taxes) related to the excess of the carrying value of our investment in Four Star relative to the underlying equity in its net assets.

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

	Successor		Predecessor
	March 23 (inception) to December 31, 2012		January 1 to May 24, 2012		2011		2010
	(In millions)		(In millions)
Operating results:
Operating revenues	$	108	$	75	$	257	$	249
Operating expenses	89		58		167		151
Net income	11		11		60		63

87

	Successor As of December 31, 2012		Predecessor As of December 31, 2011
	(In millions)
Financial position data:
Current assets	$	73	$	77
Non-current assets	246		290
Current liabilities	52		64
Non-current liabilities	134		148
Equity in net assets	133		155

We hold an approximate 49 percent ownership investment in Four Star.  In conjunction with the Acquisition and purchase price allocation, we adjusted our basis in Four Star to approximately $235 million.

We amortize the excess of our investment in Four Star over the underlying equity in its net assets using the unit-of-production method over the life of our estimate of Four Star’s oil and natural gas reserves which are predominantly natural gas reserves. Amortization of our investment for the successor period from March 23, 2012 to December 31, 2012 was $7 million. Amortization for the predecessor period from January 1, 2012 to May 24, 2012 and for the years ended December 31, 2011 and 2010 was $12 million, $34 million and $38 million, respectively. Based on changes in the outlook for natural gas prices, the fair value of our investment in Four Star could decline which may require us to record an impairment of the carrying value of our investment in the future if that loss is determined to be other than temporary.

We received dividends from Four Star for the period from March 23, 2012 (inception) to December 31, 2012 of approximately $13 million. For the predecessor periods from January 1, 2012 to May 24, 2012 and years ended December 31, 2011 and 2010, we received dividends of $8 million, $46 million and $50 million.

11.  Related Party Transactions

Transaction Fee Agreement. In connection with the Acquisition, we were subject to a transaction fee agreement with certain of our Sponsors (the “Service Providers”) for the provision of certain structuring, financial, investment banking and other similar advisory services. At the time of the Acquisition, we paid one-time transaction fees of $71.5 million (recorded as general and administrative expense in our income statement) to the Service Providers in the aggregate in exchange for services rendered in connection with structuring, arranging the financing and performing other services. In the event of any future transactions (including any merger, consolidation, recapitalization or sale of assets or equity interests resulting in a change of control of the equity and voting securities, or sale of all or substantially all of the assets or which is in connection with one or more public offerings, each as further defined in the Transaction Fee Agreement), we would pay an additional transaction fee equal to the lesser of (i) 1% of the aggregate enterprise value paid or provided and (ii) $100 million.

Management Fee Agreement. We entered into a management fee agreement with certain of our Sponsors for the provision of certain management consulting and advisory services which terminates on the twelve-year anniversary of the Acquisition date (May 24, 2012) if not terminated earlier by mutual agreement of the parties, or upon a change in control or specified initial public offering transaction. Under the agreement, we pay a non-refundable annual management fee of $25 million. For the period from March 23, 2012 to December 31, 2012, we recognized approximately $16 million in general and administrative expense related to management fees.

Affiliate Supply Agreement.  In November 2012, we entered into a supply agreement with an Apollo affiliate through October 2014 to provide certain fracturing materials for our Eagle Ford drilling operations.  As of December 31, 2012, we recorded approximately $21 million as capital expenditures for amounts provided under this agreement.

88

Related Party Transactions Prior to the Acquisition.At the time of the Acquisition, El Paso made total contributions of approximately $1.5 billion to the predecessor including a non-cash contribution of approximately $0.5 billion to satisfy its then current and deferred income tax balances and a cash contribution to facilitate repayment of approximately $960 million of then outstanding debt of the predecessor under its revolving credit facility. Additionally, prior to the completion of the Acquisition, the predecessor entered into transactions during the ordinary course of conducting its business with affiliates of El Paso, primarily related to the sale, transportation and hedging of its oil, natural gas and NGL production.

Other than continuing transition services agreements with KMI, the agreements noted below ceased on the date of Acquisition and included the following services:

·General. El Paso billed the predecessor directly for certain general and administrative costs and allocated a portion of its general and administrative costs. The allocation was based on the estimated level of resources devoted to its operations and the relative size of its earnings before interest and taxes, gross property and payroll. These expenses were primarily related to management, legal, financial, tax, consultative, administrative and other services, including employee benefits, pension benefits, annual incentive bonuses, rent, insurance, and information technology. El Paso also billed the predecessor directly for compensation expense related to certain stock-based compensation awards granted directly to the predecessor’s employees, and allocated to the predecessor a proportionate share of El Paso’s corporate compensation expense.

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

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

·Marketing. Prior to the completion of the Acquisition, the predecessor sold natural gas primarily to El Paso Marketing at spot market prices. Substantially all of the affiliated accounts receivable at December 31, 2011 related to sales of natural gas to El Paso Marketing. The predecessor was also a party to a hedging contract with El Paso Marketing. Realized gains and losses on these hedges were included in operating revenues.

·Transportation and Related Services. Prior to the completion of the Acquisition, the predecessor contracted for services with El Paso’s regulated interstate pipelines that provided transportation and related services for natural gas production. At December 31, 2011, contractual deposits were $8 million associated with El Paso’s regulated interstate pipelines.

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

	Predecessor
	January 1, 2012 to May 24,		Years ended December 31,
	2012		2011		2010
Operating revenues	$	143	$	634	$	746
Operating expenses	44		138		132
Reimbursements of operating expenses	—		3		2

89

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

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

90

12. Consolidating Financial Statements

As discussed in Note 7, our secured and unsecured notes are fully and unconditionally guaranteed, jointly and severally, by the Company’s present and future direct and indirect wholly owned material domestic subsidiaries. Our foreign wholly-owned subsidiaries are not parties to the guarantees (the ‘‘Non-Guarantor Subsidiaries’’). The following reflects consolidating financial information of the issuer, guarantor subsidiaries, non-guarantor subsidiaries, eliminating entries (to combine the entities) and consolidated results as of and for the same periods our consolidated financial statements are presented herein.

EP ENERGY LLC

CONSOLIDATING STATEMENT OF INCOME

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

(In millions)

	Successor
	Issuer			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Eliminations			Consolidated
Operating revenues
Oil and condensate	$	—		$	535		$	32		$	—		$	567
Natural gas	—			357			44			—			401
NGL	—			41			—			—			41
Financial derivatives	(50		)	(12		)	—			—			(62		)
Total operating revenues	(50		)	921			76			—			947
Operating expenses
Transportation costs	—			73			—			—			73
Lease operating expense	—			111			25						136
General and administrative	206			161			12			—			379
Depreciation, depletion and amortization	—			260			8			—			268
Impairments	—			1			—			—			1
Exploration expense	—			45			7			—			52
Taxes, other than income taxes	—			51			10			—			61
Total operating expenses	206			702			62			—			970
Operating (loss) income	(256		)	219			14			—			(23		)
Loss from unconsolidated affiliates	—			(1		)	—			—			(1		)
Other income	1			—			2			—			3
Loss on extinguishment of debt	(14		)	—			—			—			(14		)
Interest (expense) income
Third party	(218		)	—			—			—			(218		)
Affiliated	—			3			(3		)	—			—
(Loss) income before income taxes	(487		)	221			13			—			(253		)
Income tax expense	—			1			1			—			2
(Loss) income before earnings from consolidated subsidiaries	(487		)	220			12			—			(255		)
Earnings from consolidated subsidiaries	232			12			—			(244		)	—
Net (loss) income	$	(255	)	$	232		$	12		$	(244	)	$	(255	)

91

EP ENERGY LLC

CONSOLIDATING STATEMENT OF INCOME AND COMPREHENSIVE INCOME

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

(In millions)

	Predecessor
	Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Eliminations		Consolidated
Operating revenues
Oil and condensate	$	310		$	12		$	—	$	322
Natural gas	228			34			—		262
NGL	29			—			—		29
Financial derivatives	365			—			—		365
Total operating revenues	932			46			—		978
Operating expenses
Transportation costs	45			—			—		45
Lease operating expense	80			16			—		96
General and administrative	69			6			—		75
Depreciation, depletion and amortization	307			12			—		319
Ceiling test charge	—			62			—		62
Taxes, other than income taxes	31			14			—		45
Total operating expenses	532			110			—		642
Operating income (loss)	400			(64		)	—		336
Loss from unconsolidated affiliates	(5		)	—			—		(5		)
Other income (expense)	1			(4		)	—		(3		)
Interest (expense) income
Third party	(14		)	—			—		(14		)
Affiliated	2			(2		)	—		—
Income (loss) before income taxes	384			(70		)	—		314
Income tax expense	135			1			—		136
Income (loss) before earnings from consolidated subsidiaries	249			(71		)	—		178
Loss from consolidated subsidiaries	(71		)	—			71		—
Net income (loss)	$	178		$	(71	)	$	71	$	178
Cash flow hedging activities:
Reclassification adjustment(1)	3			—			—		3
Comprehensive income (loss)	$	181		$	(71	)	$	71	$	181

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

92

EP ENERGY LLC

CONSOLIDATING STATEMENT OF INCOME AND COMPREHENSIVE INCOME

FOR THE YEAR ENDED DECEMBER 31, 2011

(In millions)

	Predecessor
	Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Eliminations			Consolidated
Operating revenues
Oil and condensate	$	513		$	39		$	—		$	552
Natural gas	901			72			—			973
NGL	57			—			—			57
Financial derivatives	284			—			—			284
Other	1			—			—			1
Total operating revenues	1,756			111			—			1,867
Operating expenses
Transportation costs	85			—			—			85
Lease operating expense	176			41			—			217
General and administrative	187			14			—			201
Depreciation, depletion and amortization	581			31			—			612
Impairments/Ceiling test charge	30			128			—			158
Taxes, other than income taxes	76			15			—			91
Total operating expenses	1,135			229			—			1,364
Operating income (loss)	621			(118		)	—			503
Loss from unconsolidated affiliates	(7		)	—			—			(7		)
Other income (expense)	1			(3		)	—			(2		)
Interest (expense) income
Third party	(10		)	—			1			(9		)
Affiliated	8			(10		)	(1		)	(3		)
Income (loss) before income taxes	613			(131		)	—			482
Income tax expense (benefit)	228			(8		)	—			220
Income (loss) before earnings from consolidated subsidiaries	385			(123		)	—			262
Loss from consolidated subsidiaries	(123		)	—			123			—
Net income (loss)	$	262		$	(123	)	$	123		$	262
Cash flow hedging activities:
Reclassification adjustment(1)	7			—			—			7
Comprehensive (loss) income	$	269		$	(123	)	$	123		$	269

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

93

EP ENERGY LLC

CONSOLIDATING STATEMENT OF INCOME AND COMPREHENSIVE INCOME

FOR THE YEAR ENDED DECEMBER 31, 2010

(In millions)

	Predecessor
	Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Eliminations			Consolidated
Operating revenues
Oil and condensate	$	316		$	30		$	—		$	346
Natural gas	919			55			—			974
NGL	60			—			—			60
Financial derivatives	390			—			—			390
Other	19			—			—			19
Total operating revenues	1,704			85			—			1,789
Operating expenses
Transportation costs	73			—			—			73
Lease operating expense	156			37			—			193
General and administrative	176			14			—			190
Depreciation, depletion and amortization	450			27			—			477
Ceiling test charge	—			25			—			25
Taxes, other than income taxes	73			12			—			85
Other	15			—			—			15
Total operating expenses	943			115			—			1,058
Operating income (loss)	761			(30		)	—			731
Loss from unconsolidated affiliates	(7		)	—			—			(7		)
Other income	1			2			—			3
Interest expense
Third party	(17		)	—			1			(16		)
Affiliated	(3		)	(1		)	(1		)	(5		)
Income (loss) before income taxes	735			(29		)	—			706
Income tax expense	253			10			—			263
Income (loss) before earnings from consolidated subsidiaries	482			(39		)	—			443
Loss from consolidated subsidiaries	(39		)	—			39			—
Net income (loss)	$	443		$	(39	)	$	39		$	443
Cash flow hedging activities:
Reclassification adjustment(1)	7			—			—			7
Comprehensive income (loss)	$	450		$	(39	)	$	39		$	450

(1)Reclassification adjustments are stated net of tax. Taxes recognized for the predecessor period related to the year ended December 31, 2010 are $4 million.

94

EP ENERGY LLC

CONSOLIDATING BALANCE SHEET

AS OF DECEMBER 31, 2012

(In millions)

	Successor
	Issuer		GuarantorSubsidiaries		Non- GuarantorSubsidiaries		Eliminations			Consolidated
ASSETS
Current assets
Cash and cash equivalents	$	—	$	49	$	14	$	—		$	63
Accounts receivable Customer, net of allowance of less than $1	6		194		26		—			226
Affiliates	—		3		—		(3		)	—
Other, net of allowance of $1	—		20		1		—			21
Materials and supplies	—		22		—		—			22
Derivatives	108		—		—		—			108
Prepaid assets	—		12		8		—			20
Other	—		—		4		—			4
Total current assets	114		300		53		(3		)	464
Property, plant and equipment, at cost
Oil and natural gas properties	—		7,441		92		—			7,533
Other property, plant and equipment	—		102		1		—			103
	—		7,543		93		—			7,636
Less accumulated depreciation, depletion and amortization	—		260		6		—			266
Total property, plant and equipment, net	—		7,283		87		—			7,370
Other assets
Investments in unconsolidated affiliates	—		226		—		—			226
Investments in consolidated affiliates	7,124		46		—		(7,170		)	—
Derivatives	88		—		—		—			88
Notes receivable from consolidated affiliate	45		—		—		(45		)	—
Deferred income taxes	—		—		6		—			6
Unamortized debt issue cost	134		—		—		—			134
Other	—		5		—		—			5
	7,391		277		6		(7,215		)	459
Total assets	$	7,505	$	7,860	$	146	$	(7,218	)	$	8,293

95

EP ENERGY LLC

CONSOLIDATING BALANCE SHEET

AS OF DECEMBER 31, 2012

(In millions)

	Successor
	Issuer		GuarantorSubsidiaries		Non- GuarantorSubsidiaries		Eliminations			Consolidated
LIABILITIES AND EQUITY
Current liabilities
Accounts payable
Trade	$	—	$	126	$	—	$	—		$	126
Affiliates	—		—		3		(3		)	—
Other accrued liabilities	—		314		44		—			358
Derivatives	10		7		—		—			17
Accrued taxes other than income	—		15		8		—			23
Accrued interest	57		—		—		—			57
Accrued taxes	—		19		—		—			19
Asset retirement obligations	—		10		—		—			10
Other	—		45		3		—			48
Total current liabilities	67		536		58		(3		)	658
Long-term debt	4,346		—		—		—			4,346
Notes payable to consolidated affiliate	—		45		—		(45		)	—
Other long-term liabilities
Derivatives	7		7		—		—			14
Asset retirement obligations	—		144		36		—			180
Other	—		4		6		—			10
Total non-current liabilities	4,353		200		42		(45		)	4,550
Commitments and contingencies
Member’s equity	3,085		7,124		46		(7,170		)	3,085
Total liabilities and equity	$	7,505	$	7,860	$	146	$	(7,218	)	$	8,293

96

EP ENERGY LLC

CONSOLIDATING BALANCE SHEET

AS OF DECEMBER 31, 2011

(In millions)

	Predecessor
	Guarantor Subsidiaries		Non- GuarantorSubsidiaries		Eliminations			Consolidated
ASSETS
Current assets
Cash and cash equivalents	$	6	$	19	$	—		$	25
Accounts receivable
Customer, net of allowance of less than $1	119		16		—			135
Affiliates	132		—		—			132
Other, net of allowance of $7	38		1		—			39
Materials and supplies	21		7		—			28
Derivatives	272		—		—			272
Prepaid assets	4		8		—			12
Other	14		1		—			15
Total current assets	606		52		—			658
Property, plant and equipment, at cost
Oil and natural gas properties, of which $481 was excluded from amortization	20,671		1,252		—			21,923
Other property, plant and equipment	142		5		—			147
	20,813		1,257		—			22,070
Less accumulated depreciation, depletion and amortization	17,026		977		—			18,003
Total property, plant and equipment, net	3,787		280		—			4,067
Other assets
Investments in unconsolidated affiliates	346		—		—			346
Investment in consolidated affiliates	2		—		(2		)	—
Derivatives	9		—		—			9
Deferred income taxes	—		7		—			7
Unamortized debt issue cost	8		—		—			8
Note receivable from consolidated affiliate	251		—		(251		)	—
Other	4		—		—			4
	620		7		(253		)	374
Total assets	$	5,013	$	339	$	(253	)	$	5,099

97

EP ENERGY LLC

CONSOLIDATING BALANCE SHEET

AS OF DECEMBER 31, 2011

(In millions)

	Predecessor
	Guarantor Subsidiaries			Non- GuarantorSubsidiaries			Eliminations			Consolidated
LIABILITIES AND EQUITY
Current liabilities
Accounts payable
Trade	$	140		$	—		$	—		$	140
Affiliates	47			—			—			47
Other	210			48			—			258
Derivatives	7			—			—			7
Accrued taxes other than income	24			9			—			33
Deferred income taxes	91			—			—			91
Asset retirement obligations	5			—			—			5
Other	8			—			—			8
Total current liabilities	532			57			—			589
Long-term debt	851			—			—			851
Note payable to consolidated affiliate	—			251			(251		)	—
Other long-term liabilities
Derivatives	73			—			—			73
Asset retirement obligations	126			22			—			148
Deferred income taxes	291			—			—			291
Other	40			7			—			47
Total non-current liabilities	1,381			280			(251		)	1,410
Commitments and contingencies
Stockholders’ equity
Common stock, par value $1 per share; 1,000 share authorized and outstanding	—			381			(381		)	—
Preferred stock	—			4			(4		)	—
Additional paid-in capital	4,580			393			(393		)	4,580
Accumulated deficit	(1,476		)	(776		)	776			(1,476		)
Accumulated other comprehensive loss	(4		)	—			—			(4		)
Total stockholder’s equity	3,100			2			(2		)	3,100
Total liabilities and equity	$	5,013		$	339		$	(253	)	$	5,099

98

EP ENERGY LLC

CONSOLIDATING STATEMENT OF CASH FLOWS

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

(In millions)

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

99

EP ENERGY LLC

CONSOLIDATING STATEMENT OF CASH FLOWS

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

(In millions)

	Predecessor
	Guarantor Subsidiaries			Non- GuarantorSubsidiaries			Eliminations			Consolidated
Cash flows from operating activities
Net income (loss)	$	178		$	(71	)	$	71		$	178
Adjustments to reconcile net income (loss) to net cash from operating activities
Depreciation, depletion and amortization	307			12			—			319
Deferred income tax expense	199			—			—			199
Loss from unconsolidated affiliates, adjusted for cash distributions	12			—			—			12
Earnings from consolidated affiliates	71			—			(71		)	—
Ceiling test charges	—			62			—			62
Amortization of debt issuance cost	7			—			—			7
Asset and liability changes
Accounts receivable	132			2			(2		)	132
Accounts payable	(54		)	(4		)	2			(56		)
Affiliate income taxes	3			1			—			4
Derivatives	(201		)	—			—			(201		)
Accrued interest	(1		)	—			—			(1		)
Other asset changes	(3		)	—			—			(3		)
Other liability changes	(70		)	(2		)	—			(72		)
Net cash provided by operating activities	580			—			—			580
Cash flows from investing activities
Capital expenditures	(628		)	(8		)	—			(636		)
Net proceeds from the sale of assets	9			—			—			9
Cash paid for acquisitions, net of cash acquired	(1		)	—			—			(1		)
Change in note receivable with affiliates	(1		)	—			1			—
Net cash (used in) provided by investing activities	(621		)	(8		)	1			(628		)
Cash flows from financing activities
Proceeds from long term debt	215			—			—			215
Repayment of long term debt	(1,065		)	—			—			(1,065		)
Contribution from parent	960			—			—			960
Change in note payable with affiliate	—			1			(1		)	—
Net cash provided by (used in) financing activities	110			1			(1		)	110
Change in cash and cash equivalents	69			(7		)	—			62
Cash and cash equivalents
Beginning of period	6			19			—			25
End of period	$	75		$	12		$	—		$	87

100

EP ENERGY LLC

CONSOLIDATING STATEMENT OF CASH FLOWS

FOR THE YEAR ENDED DECEMBER 31, 2011

(In millions)

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

101

EP ENERGY LLC

CONSOLIDATING STATEMENT OF CASH FLOWS

FOR THE YEAR ENDED DECEMBER 31, 2010

(In millions)

	Predecessor
	GuarantorSubsidiaries			Non- GuarantorSubsidiaries			Eliminations			Consolidated
Cash flows from operating activities
Net income (loss)	$	443		$	(39	)	$	39		$	443
Adjustments to reconcile net income (loss) to net cash from operating activities
Depreciation, depletion and amortization	450			27			—			477
Deferred income tax expense (benefit)	328			(8		)	—			320
Earnings from unconsolidated affiliates, adjusted for cash distributions	57			—			—			57
Earnings from consolidated affiliates	39			—			(39		)
Ceiling test charges	—			25			—			25
Amortization of debt issuance costs	5			—			—			5
Asset and liability changes
Accounts receivable	(16		)	(1		)	—			(17		)
Accounts payable	105			(15		)	—			90
Affiliate income taxes	(172		)	—			—			(172		)
Derivatives	(99		)	—			—			(99		)
Accrued interest	1			—			—			1
Other asset changes	11			5			—			16
Other liability changes	(93		)	14			—			(79		)
Net cash provided by operating activities	1,059			8			—			1,067
Cash flows from investing activities
Capital expenditures	(1,161		)	(77		)	—			(1,238		)
Net proceeds from the sale of assets	155			—			—			155
Cash paid for acquisitions, net of cash acquired	(51		)	—			—			(51		)
Investment in subsidiary	(17		)	—			17			—
Change in note receivable with affiliate	(50		)	—			50			—
Other	4			—			—			4
Net cash (used in) provided by investing activities	(1,120		)	(77		)	67			(1,130		)
Cash flows from financing activities
Proceeds from long term debt	500			—			—			500
Repayment of long term debt	(1,034		)	—			—			(1,034		)
Change in note payable with affiliate	489			50			(50		)	489
Other	(1		)	17			(17		)	(1		)
Net cash (used in) provided by financing activities	(46		)	67			(67		)	(46		)
Change in cash and cash equivalents	(107		)	(2		)	—			(109		)
Cash and cash equivalents
Beginning of period	174			9			—			183
End of period	$	67		$	7		$	—		$	74

102

Supplemental Selected Quarterly Financial Information (Unaudited)

Financial information by quarter is summarized below.

	Predecessor				Successor
	Quarters Ended
			June 30
2012	March 31		April 1 to May 24		April 1 to June 30			September 30			December 31		Total
Operating revenues	$	484	$	494	$	200		$	229		$	518	$	1,925
Operating income (loss)	62		274		(97		)	(95		)	169		313
Net income (loss)	15		163		(150		)	(196		)	91		(77		)

	Predecessor
2011	March 31			June 30		September 30		December 31		Total
Operating revenues	$	250		$	535	$	653	$	429	$	1,867
Operating (loss) income	(30		)	250		190		93		503
Net income (loss)	(18		)	170		61		49		262

Below are significant items affecting comparability of amounts reported in the respective periods of 2012 and 2011:

December 31, 2012. We recorded $62 million of gains related to changes in fair value of our derivatives.

September 30, 2012. We recorded $181 million of losses related to changes in fair value of our derivatives.

June 30, 2012. For the successor period from April 1 to June 30 we recorded $57 million of gains related to changes in the fair value of our derivatives and $173 million of transaction costs related to the Acquisition. For the predecessor period from April 1 to May 24, we recorded $289 million or gains related to changes in the fair value of our derivatives.

March 31, 2012. We recorded $76 million of gains related to changes in the fair value of our derivatives and a $62 million non-cash Egyptian ceiling test charge.

December 31, 2011. We recorded $10 million of gains related to changes in fair value of our derivatives.

September 30, 2011. We recorded $251 million of gains related to changes in fair value of our derivatives and a $152 million non-cash Brazilian ceiling test charge.

June 30, 2011. We recorded $132 million of gains related to changes in the fair value of our derivatives.

March 31, 2011. We recorded $109 million of losses related to changes in the fair value of our derivatives.

103

Supplemental Oil and Natural Gas Operations (Unaudited)

We are engaged in the exploration for, and the acquisition, development and production of oil, natural gas and NGL, in the United States (U.S.) and Brazil.

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

	U.S.		Brazil andEgypt(1)		Worldwide
2012 Consolidated(2):
Oil and natural gas properties	$	7,441	$	92	$	7,533
Less accumulated depreciation, depletion and amortization	249		6		255
Net capitalized costs	$	7,192	$	86	$	7,278
2012 Unconsolidated Affiliate — Four Star(3):
Oil and natural gas properties	$	627	$	—	$	627
Less accumulated depreciation, depletion and amortization	510		—		510
Net capitalized costs	$	117	$	—	$	117
2011 Consolidated:
Oil and natural gas properties:
Costs subject to amortization	$	20,156	$	1,284	$	21,440
Costs not subject to amortization	399		82		481
	20,555		1,366		21,921
Less accumulated depreciation, depletion and amortization	16,837		1,087		17,924
Net capitalized costs	$	3,718	$	279	$	3,997
2011 Unconsolidated Affiliate — Four Star(3):
Oil and natural gas properties	$	628	$	—	$	628
Less accumulated depreciation, depletion and amortization	489		—		489
Net capitalized costs	$	139	$	—	$	139

(1)Capitalized costs for Egypt were $74 million as of December 31, 2011, included in costs not subject to amortization. We sold our interests in Egypt in June 2012.  During 2012 we recorded a ceiling test charge of $62 million in our Egyptian full cost pool. During 2011 we recorded a ceiling test charge of $152 million in our Brazilian full cost pool.

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

(3)Amounts represent our approximate 49 percent equity interest in the underlying oil and gas assets of Four Star. Four Star applies the successful efforts method of accounting for its oil and gas properties.

104

Total Costs Incurred. Costs incurred in oil and natural gas producing activities, whether capitalized or expensed, were as follows for the successor period from March 23, 2012 (inception) to December 31, 2012 and the predecessor periods from January 1, 2012 to May 24, 2012 and the years ended December 31, 2011 and 2010 (in millions):

	U.S.		Braziland Egypt(1)		Worldwide
Successor
Consolidated from March 23, 2012 (inception) to December 31, 2012:
Property acquisition costs
Proved properties	$	—	$	—	$	—
Unproved properties	20		—		20
Exploration costs (capitalized and expensed)	120		6		126
Development costs	787		3		790
Costs expended	927		9		936
Asset retirement obligation costs	28		3		31
Total costs incurred	$	955	$	12	$	967
Unconsolidated Affiliate from March 23, 2012 (inception) to December 31, 2012:
Development costs expended	$	2	$	—	$	2
Predecessor
Consolidated from January 1, 2012 to May 24, 2012:
Property acquisition costs
Proved properties	$	—	$	—	$	—
Unproved properties	31		—		31
Exploration costs	79		3		82
Development costs	503		—		503
Costs expended	613		3		616
Asset retirement obligation costs	21		10		31
Total costs incurred	$	634	$	13	$	647
Unconsolidated Affiliate from January 1, 2012 to May 24, 2012:
Development costs expended	$	3	$	—	$	3
2011 Consolidated:
Property acquisition costs
Proved properties	$	—	$	—	$	—
Unproved properties	45		—		45
Exploration costs	858		15		873
Development costs	694		12		706
Costs expended	1,597		27		1,624
Asset retirement obligation costs	25		—		25
Total costs incurred	$	1,622	$	27	$	1,649
2011 Unconsolidated Affiliate:
Development costs expended	$	12	$	—	$	12
2010 Consolidated:
Property acquisition costs
Proved properties	$	51	$	—	$	51
Unproved properties	269		—		269
Exploration costs	600		58		658
Development costs	276		28		304
Costs expended	1,196		86		1,282
Asset retirement obligation costs	7		—		7
Total costs incurred	$	1,203	$	86	$	1,289
2010 Unconsolidated Affiliate:
Development costs expended	$	20	$	—	$	20

105

(1)Costs incurred for Egypt were less than $1 million for the successor period from March 23, 2012 to December 31, 2012 and $2 million, $8 million and $20 million for the predecessor periods from January 1, 2012 to May 24, 2012 and the years ended December 31, 2011 and 2010.  In June of 2012 we sold our Egyptian oil and gas properties.

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

106

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

Pursuant to the full cost method of accounting, the predecessor capitalized certain general and administrative expenses directly related to property acquisition, exploration and development activities and interest costs incurred and attributable to unproved oil and natural gas properties and major development projects of oil and natural gas properties. The table above includes capitalized internal general and administrative costs incurred in connection with the acquisition, development and exploration of oil and natural gas reserves of $31 million for the period from January 1, 2012 to May 24, 2012 and $81 million for each of the years ended December 31, 2011 and 2010. The predecessor also capitalized interest of $4 million, $13 million and $9 million for the period from January 1, 2012 to May 24, 2012 and the years ended December 31, 2011 and 2010.

During 2011 the predecessor was informed that its environmental permit request for the Pinauna Field in the Camamu Basin was denied. As a result, $94 million of unevaluated capitalized costs related to this field were released into the Brazilian full cost pool. Additionally, during 2011, approximately $86 million of unevaluated capitalized costs were released into the Brazilian full cost pool related to the Espirito Santo Basin upon completion of the evaluation of exploratory wells drilled in 2009 and 2010 without any additions to proved reserves.

Oil and Natural Gas Reserves. Net quantities of proved developed and undeveloped reserves of natural gas, oil and condensate and NGL and changes in these reserves at December 31, 2012 presented in the tables below are based on our internal reserve report. Net proved reserves exclude royalties and interests owned by others and reflect contractual arrangements and royalty obligations in effect at the time of the estimate. Our 2012 consolidated proved reserves were consistent with estimates of proved reserves filed with other federal agencies in 2012 except for differences of less than five percent resulting from actual production, acquisitions, property sales, necessary reserve revisions and additions to reflect actual experience.

Ryder Scott Company, L.P. (Ryder Scott), conducted an audit of the estimates of the proved reserves prepared by us as of December 31, 2012. In connection with its audit, Ryder Scott reviewed 81 percent (by value) of the total proved reserves on a natural gas equivalent basis representing 90 percent of the total discounted future net cash flows of these proved reserves. Ryder Scott also conducted an audit of the estimates we prepared of the proved reserves of Four Star as of December 31, 2012. In connection with the audit of these proved reserves, Ryder Scott reviewed 85 percent of the properties associated with Four Star’s total proved reserves on a natural gas equivalent basis, representing 92 percent of the total discounted future net cash flows. For the reviewed properties, 97 percent of our total proved undeveloped reserves were evaluated and our overall proved reserves estimates are within 10 percent of Ryder Scott’s estimates. Ryder Scott’s report is included as an exhibit to this Annual Report on Form 10-K.

							Oil and Condensate						NGL		Equivalent
	Natural Gas (in Bcf)						(in MBbls)						(in MBbls)		Volumes
	U.S.		Brazil		Worldwide		U.S.		Brazil		Worldwide		U.S.		(in Bcfe)
Consolidated:
January 1, 2010	2,052		105		2,157		60,849		4,196		65,045		304		2,549
Revisions due to prices	108		3		111		8,719		88		8,807		105		164
Revisions other than price	(58	)	(13	)	(71	)	7,873		(1,246	)	6,627		6,977		11
Extensions and discoveries(1)	506		—		506		28,141		—		28,141		3,088		693
Purchases of reserves in place	25		—		25		3,045		—		3,045		—		43
Sales of reserves in place	(21	)	—		(21	)	(1,024	)	—		(1,024	)	—		(27	)
Production	(216	)	(10	)	(226	)	(4,363	)	(384	)	(4,747	)	(1,423	)	(263	)
December 31, 2010	2,396		85		2,481		103,240		2,654		105,894		9,051		3,170
Revisions due to prices	(9	)	—		(9	)	713		3		716		—		(5	)
Revisions other than price	44		6		50		(1,630	)	(34	)	(1,664	)	(1,124	)	34
Extensions and discoveries(2)	519		—		519		90,128		—		90,128		7,525		1,105
Purchases of reserves in place	—		—		—		13		—		13		—		—
Sales of reserves in place	(153	)	—		(153	)	(8,983	)	—		(8,983	)	(139	)	(207	)
Production	(231	)	(10	)	(241	)	(5,680	)	(354	)	(6,034	)	(1,068	)	(284	)
December 31, 2011	2,566		81		2,647		177,801		2,269		180,070		14,245		3,813
Revisions due to prices	(718	)	—		(718	)	(604	)	1		(603	)	(371	)	(724	)
Revisions other than price	55		(3	)	52		(18,451	)	288		(18,163	)	10,267		5
Extensions and discoveries(3)	119		—		119		109,125		—		109,125		13,450		854
Purchases of reserves in place	—		—		—		3		—		3		2		—
Sales of reserves in place	(72	)	—		(72	)	(2,501	)	—		(2,501	)	(1,358	)	(95	)
Production	(223	)	(10	)	(233	)	(9,131	)	(406	)	(9,537	)	(1,904	)	(302	)
December 31, 2012	1,727		68		1,795		256,242		2,152		258,394		34,331		3,551

107

						Oil and Condensate					NGL		Equivalent
	Natural Gas (in Bcf)					(in MBbls)					(in MBbls)		Volumes
	U.S.		Brazil	Worldwide		U.S.		Brazil	Worldwide		U.S.		(in Bcfe)
Unconsolidated Affiliate — Four Star:
January 1, 2010	158		—	158		1,907		—	1,907		5,264		201
Revisions due to prices	8		—	8		44		—	44		87		9
Revisions other than price	6		—	6		36		—	36		(325	)	4
Extensions and discoveries	—		—	—		—		—	—		5		—
Production	(17	)	—	(17	)	(364	)	—	(364	)	(573	)	(22	)
December 31, 2010	155		—	155		1,623		—	1,623		4,458		192
Revisions due to prices	(5	)	—	(5	)	31		—	31		(28	)	(5	)
Revisions other than price	2		—	2		221		—	221		1,034		9
Extensions and discoveries	—		—	—		—		—	—		—		—
Production	(17	)	—	(17	)	(306	)	—	(306	)	(556	)	(22	)
December 31, 2011	135		—	135		1,569		—	1,569		4,908		174
Revisions due to prices	(13	)	—	(13	)	(37	)	—	(37	)	(310	)	(15	)
Revisions other than price	19		—	19		803		—	803		1,710		35
Extensions and discoveries	25		—	25		95		—	95		137		26
Production	(16	)	—	(16	)	(282	)	—	(282	)	(478	)	(21	)
December 31, 2012	150		—	150		2,148		—	2,148		5,967		199
Total Combined:
December 31, 2010	2,551		85	2,636		104,863		2,654	107,517		13,509		3,362
December 31, 2011	2,701		81	2,782		179,370		2,269	181,639		19,153		3,987
December 31, 2012	1,877		68	1,945		258,390		2,152	260,542		40,298		3,750
Consolidated:
Proved developed reserves:
January 1, 2012	1,488		81	1,569		46,797		2,269	49,066		5,168		1,895
December 31, 2012	1,189		68	1,257		55,924		2,152	58,076		9,080		1,660
Proved undeveloped reserves:
January 1, 2012	1,078		—	1,078		131,004		—	131,004		9,077		1,918
December 31, 2012	538		—	538		200,318		—	200,318		25,251		1,891
Unconsolidated Affiliate — Four Star:
Proved developed reserves:
January 1, 2012	116		—	116		1,520		—	1,520		4,066		150
December 31, 2012	140		—	140		2,111		—	2,111		5,289		185
Proved undeveloped reserves:
January 1, 2012	19		—	19		49		—	49		842		24
December 31, 2012	10		—	10		37		—	37		678		14
Total Combined:
Proved developed reserves:
January 1, 2012	1,604		81	1,685		48,317		2,269	50,586		9,234		2,045
December 31, 2012	1,329		68	1,397		58,035		2,152	60,187		14,369		1,845
Proved undeveloped reserves:
January 1, 2012	1,097		—	1,097		131,053		—	131,053		9,919		1,942
December 31, 2012	548		—	548		200,355		—	200,355		25,929		1,905

(1)In 2010, of the 693 Bcfe of extensions and discoveries, 452 Bcfe related to the Central division, of which, 425 Bcfe related to the Haynesville Shale area. There were 238 Bcfe of extensions and discoveries in the Gulf Coast division with 187 Bcfe of that coming from the Eagle Ford Shale. The Western division accounted for 3 Bcfe of extensions and discoveries and there were no extensions and discoveries in the International division.

(2) In 2011, of the 1,105 Bcfe of extensions and discoveries, 428 Bcfe related to the Central division, of which, 389 Bcfe related to the Haynesville Shale area. There were 592 Bcfe of extensions and discoveries in the Southern division with 479 Bcfe of that coming from the Eagle Ford Shale and 113 Bcfe coming from the Wolfcamp Shale. The Western division accounted for 85 Bcfe of extensions and discoveries and there were no extensions and discoveries in the International division.

(3)In 2012, of the 880 Bcfe of combined extensions and discoveries, 50 Bcfe related to the Central division, of which, 37 Bcfe related to the Altamont area. There were 664 Bcfe of extensions and discoveries in the Eagle Ford Shale. There were 141 Bcfe of extensions and discoveries coming from the Wolfcamp Shale.  There were no extensions and discoveries in the International division.  Of the 880 Bcfe of extensions and discoveries, 737 Bcfe were liquids representing 84% of EP Energy’s total extensions and discoveries which is a 26% increase in liquid extensions and discoveries from the previous year.

108

In accordance with SEC Regulation S-X, Rule 4-10 as amended, we use the 12-month average price calculated as the unweighted arithmetic average of the spot price on the first day of each month within the 12-month period prior to the end of the reporting period. The first day 12-month average U.S. price used to estimate our proved reserves at December 31, 2012 was $2.76 per MMBtu for natural gas and $94.61 per barrel of oil. The prices used for our International assets were contractually defined. The aggregate International price used to estimate our proved reserves at December 31, 2012 was $7.53 per MMBtu for natural gas and $111.21 per barrel of oil.

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

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

The meaningfulness of reserve estimates is highly dependent on the accuracy of the assumptions on which they were based. In general, the volume of production from oil and natural gas properties we own declines as reserves are depleted. Except to the extent we conduct successful exploration and development activities or acquire additional properties containing proved reserves, or both, our proved reserves will decline as reserves are produced. Subsequent to December 31, 2012, there have been no major discoveries, favorable or otherwise, that may be considered to have caused a significant change in our estimated proved reserves at December 31, 2012. The current 12-month average natural gas prices used to determine our domestic proved reserves at December 31, 2012 are significantly below the 12-month average price used to determine our domestic proved reserves at December 31, 2011. Domestic natural gas prices did result in a downward revision of proved reserves and a corresponding reduction in the discounted future net cash flows from our natural gas proved reserves.  This downward revision was offset by the company’s emphasis on the development of oil reserves.  The result was a slight downward revision in total proved equivalent reserves, but an increase in overall reserves value.

109

Results of Operations. Results of operations for oil and natural gas producing activities for the successor period from March 23, 2012 (inception) to December 31, 2012 and the predecessor periods from January 1, 2012 to May 24, 2012 and years ended December 31, 2011 and 2010 (in millions):

	U.S.			Brazil and Egypt			Worldwide
Successor
Consolidated from March 23, 2012 (inception) to December 31, 2012:
Net Revenues(1) — Sales to external customers	$	933		$	76		$	1,009
Costs of products and services	(88		)	—			(88		)
Production costs(2)	(160		)	(32		)	(192		)
Depreciation, depletion and amortization(3)	(250		)	(8		)	(258		)
Exploration expense	(45		)	(7		)	(52		)
Results of operations from producing activities	$	390		$	29		$	419
Unconsolidated Affiliate — Four Star from March 23, 2012 (inception) to December 31, 2012(4):
Net Revenues — Sales to external customers	$	52		$	—		$	52
Costs of products and services	(3		)	—			(3		)
Production costs(2)	(24		)	—			(24		)
Depreciation, depletion and amortization(5)	(16		)	—			(16		)
	9			—			9
Income tax expense	(3		)	—			(3		)
Results of operations from producing activities	$	6		$	—		$	6
Predecessor
Consolidated from January 1, 2012 to May 24, 2012:
Net Revenues(1)
Sales to external customers	$	424		$	46		$	470
Affiliated sales	143			—			143
Total	567			46			613
Costs of products and services	(49		)	—			(49		)
Production costs(2)	(115		)	(21		)	(136		)
Ceiling test charges(6)	—			(62		)	(62		)
Depreciation, depletion and amortization(3)	(301		)	(12		)	(313		)
	102			(49		)	53
Income tax expense	(37		)	—			(37		)
Results of operations from producing activities	$	65		$	(49	)	$	16
Unconsolidated Affiliate — Four Star from January 1, 2012 to May 24, 2012(4):
Net Revenues — Sales to external customers	$	35		$	—		$	35
Costs of products and services	(1		)	—			(1		)
Production costs(2)	(15		)	—			(15		)
Depreciation, depletion and amortization(5)	(11		)	—			(11		)
	8			—			8
Income tax expense	(3		)	—			(3		)
Results of operations from producing activities	$	5		$	—		$	5

110

2011 Consolidated:
Net Revenues(1)
Sales to external customers	$	837		$	111		$	948
Affiliated sales	634			—			634
Total	1,471			111			1,582
Costs of products and services	(91		)	(5		)	(96		)
Production costs(2)	(245		)	(53		)	(298		)
Ceiling test charges(6)	—			(152		)	(152		)
Depreciation, depletion and amortization(3)	(563		)	(32		)	(595		)
	572			(131		)	441
Income tax expense	(207		)	—			(207		)
Results of operations from producing activities	$	365		$	(131	)	$	234
2011 Unconsolidated Affiliate — Four Star(4):
Net Revenues — Sales to external customers	$	123		$	—		$	123
Costs of products and services	(4		)	—			(4		)
Production costs(2)	(49		)	—			(49		)
Depreciation, depletion and amortization(5)	(27		)	—			(27		)
	43			—			43
Income tax expense	(15		)	—			(15		)
Results of operations from producing activities	$	28		$	—		$	28
2010 Consolidated:
Net Revenues(1)
Sales to external customers	$	551		$	86		$	637
Affiliated sales	743			—			743
Total	1,294			86			1,380
Costs of products and services	(81		)	(5		)	(86		)
Production costs(2)	(218		)	(46		)	(264		)
Ceiling test charges(6)	—			(25		)	(25		)
Depreciation, depletion and amortization(3)	(432		)	(28		)	(460		)
	563			(18		)	545
Income tax expense	(204		)	—			(204		)
Results of operations from producing activities	$	359		$	(18	)	$	341
2010 Unconsolidated Affiliate — Four Star(4):
Net Revenues — Sales to external customers	$	119		$	—		$	119
Costs of products and services	(4		)	—			(4		)
Production costs(2)	(36		)	—			(36		)
Depreciation, depletion and amortization(5)	(28		)	—			(28		)
Asset impairment	(4		)	—			(4		)
	47			—			47
Income tax expense	(17		)	—			(17		)
Results of operations from producing activities	$	30		$	—		$	30

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

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

(3)Includes accretion expense on asset retirement obligations of $9 million for the successor period from March 23,  2012 to December 31, 2012, $5 million, $13 million and $16 million for the predecessor periods from January 1, 2012 to May 24, 2012 and the years ended December 31, 2011 and 2010, respectively.

(4)Results do not include amortization of $7 million for the successor period from March 23, 2012 to December 31, 2012 and $12 million, $34 million and $38 million for the predecessor periods from January 1, 2012 to May 24, 2012 and years ended December 31, 2011 and 2010 related to cost in excess of our equity interest in the underlying net assets of Four Star.

(5)Includes accretion expense on asset retirement obligations of $1 million for the successor period from March 23, 2012 to December 31, 2012 and $1 million, $2 million and $1 million for the predecessor periods from January 1, 2012 to May 24, 2012 and the years ended December 31, 2011 and 2010, respectively.

(6)Includes $62 million related to Egypt for the predecessor period from January 1, 2012 to May 24, 2012, $152 million related to Brazil for the year ended December 31, 2011 and $25 million related to Egypt for the year ended December 31, 2010.

111

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

	U.S.			Brazil			Worldwide
2012 Consolidated:
Future cash inflows(1)	$	28,488		$	701		$	29,189
Future production costs	(7,487		)	(415		)	(7,902		)
Future development costs	(6,189		)	(71		)	(6,260		)
Future income tax expenses(2)	—			(14		)	(14		)
Future net cash flows	14,812			201			15,013
10% annual discount for estimated timing of cash flows	(7,913		)	(39		)	(7,952		)
Standardized measure of discounted future net cash flows	$	6,899		$	162		$	7,061
2012 Unconsolidated Affiliate — Four Star(3):
Future cash inflows(1)	$	828		$	—		$	828
Future production costs	(392		)	—			(392		)
Future development costs	(54		)	—			(54		)
Future income tax expenses	(139		)	—			(139		)
Future net cash flows	243			—			243
10% annual discount for estimated timing of cash flows	(107		)	—			(107		)
Standardized measure of discounted future net cash flows	$	136		$	—		$	136
2011 Consolidated:
Future cash inflows(1)	$	26,079		$	768		$	26,847
Future production costs	(5,840		)	(415		)	(6,255		)
Future development costs	(6,343		)	(34		)	(6,377		)
Future income tax expenses	(4,086		)	(23		)	(4,109		)
Future net cash flows	9,810			296			10,106
10% annual discount for estimated timing of cash flows	(4,793		)	(97		)	(4,890		)
Standardized measure of discounted future net cash flows	$	5,017		$	199		$	5,216
2011 Unconsolidated Affiliate — Four Star(3):
Future cash inflows(1)	$	938		$	—		$	938
Future production costs	(348		)	—			(348		)
Future development costs	(66		)	—			(66		)
Future income tax expenses	(201		)	—			(201		)
Future net cash flows	323			—			323
10% annual discount for estimated timing of cash flows	(129		)	—			(129		)
Standardized measure of discounted future net cash flows	$	194		$	—		$	194
2010 Consolidated:
Future cash inflows(1)	$	17,145		$	659		$	17,804
Future production costs	(4,768		)	(325		)	(5,093		)
Future development costs	(3,249		)	(67		)	(3,316		)
Future income tax expenses	(2,403		)	(9		)	(2,412		)
Future net cash flows	6,725			258			6,983
10% annual discount for estimated timing of cash flows	(2,905		)	(77		)	(2,982		)
Standardized measure of discounted future net cash flows	$	3,820		$	181		$	4,001
2010 Unconsolidated Affiliate — Four Star(3):
Future cash inflows(1)	$	943		$	—		$	943
Future production costs	(404		)	—			(404		)
Future development costs	(34		)	—			(34		)
Future income tax expenses	(192		)	—			(192		)
Future net cash flows	313			—			313
10% annual discount for estimated timing of cash flows	(131		)	—			(131		)
Standardized measure of discounted future net cash flows	$	182		$	—		$	182

112

(1) The company had no commodity-based derivative contracts designated as accounting hedges at December 31, 2012, 2011 and 2010. Amounts also exclude the impact on future net cash flows of derivatives not designated as accounting hedges.

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

(3)Amounts represent our approximate 49 percent equity interest in Four Star.

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

	Years Ended December 31,(1)
	2012			2011			2010
Consolidated:
Sales and transfers of oil and natural gas produced net of production costs	$	(1,433	)	$	(1,200	)	$	(1,042	)
Net changes in prices and production costs	(871		)	1,057			1,734
Extensions, discoveries and improved recovery, less related costs	2,539			2,140			986
Changes in estimated future development costs	978			(415		)	(226		)
Previously estimated development costs incurred during the period	587			601			199
Revision of previous quantity estimates	(1,863		)	49			315
Accretion of discount	731			430			220
Net change in income taxes	1,683			(599		)	(934		)
Purchases of reserves in place	—			—			73
Sales of reserves in place	(296		)	(587		)	(47		)
Change in production rates, timing and other	(210		)	(261		)	(19		)
Net change	$	1,845		$	1,215		$	1,259
Unconsolidated Affiliate — Four Star:
Sales and transfers of oil and natural gas produced net of production costs	$	(48	)	$	(74	)	$	(83	)
Net changes in prices and production costs	(112		)	62			70
Extensions, discoveries and improved recovery, less related costs	25			—			1
Changes in estimated future development costs	5			(14		)	(1		)
Revision of previous quantity estimates	19			6			16
Accretion of discount	22			22			18
Net change in income taxes	39			(9		)	(16		)
Change in production rates, timing and other	(8		)	19			15
Net change	(58		)	$	12		$	20
Representative NYMEX prices:(2)
Oil (Bbl)	$	94.61		$	96.19		$	79.43
Natural gas (MMBtu)	$	2.76		$	4.12		$	4.38
Aggregate International prices:(2)
Oil (Bbl)	$	111.21		$	109.29		$	79.02
Natural gas (MMBtu)	$	7.53		$	5.31		$	5.20

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

(2)Estimated future cash inflows from estimated future production of proved reserves were computed using a first day 12-month average U.S. price and an aggregate international price.

113

SCHEDULE II

EP ENERGY LLC

VALUATION AND QUALIFYING ACCOUNTS

(In millions)

Description	Balance atBeginningof Period		Charged toCosts andExpenses			Deductions			Chargedto OtherAccounts			Balance atEnd ofPeriod
Successor — March 23 (inception) to December 31, 2012
Allowance for doubtful accounts
Customer	$	—	$	—		$	—		$	—		$	—
Other(1)	—		—			(1		)	2			1
Valuation allowance on deferred tax assets(1)	—		(21		)(2)	—			293		(3)	272
Legal reserves(1)(4)	—		—			(4		)	24			20
Environmental reserves	—		—			—			—			—
Predecessor — January 1 to May 24, 2012
Allowance for doubtful accounts
Customer	$	—	$	—		$	—		$	—		$	—
Other	7		(5		)	—			—			2
Valuation allowance on deferred tax assets	313		—			—			—			313
Legal reserves(4)	27		(1		)	(2		)	—			24
Environmental reserves	1		—			(1		)	—			—
Predecessor — Year ended December 31, 2011
Allowance for doubtful accounts
Customer	$	—	$	—		$	—		$	—		$	—
Other	8		—			(1		)	—			7
Valuation allowance on deferred tax assets	290		23		(2)	—			—			313
Legal reserves(4)	28		—			(1		)	—			27
Environmental reserves	—		1			—			—			1
Predecessor — Year ended December 31, 2010
Allowance for doubtful accounts
Customer	$	3	$	(1	)	$	(1	)	$	(1	)	$	—
Other	7		1			—			—			8
Valuation allowance on deferred tax assets	284		6		(2)	—			—			290
Legal reserves(4)	3		26			(1		)	—			28
Environmental reserves	4		—			—			(4		)	—

(1)      We recorded our allowance for doubtful accounts, deferred tax assets and legal reserves, in connection with the Acquisition.

(2)Amounts reflect valuation allowances primarily associated with foreign and state net operating losses and foreign ceiling test charges.

(3)Includes a reduction of $30 million related to the sale of our interests in Egypt.

(4)Includes reserves for an audit of state sales and use taxes — see Item 8, Note 8 to the financial statements.

114

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

None.

ITEM 9A. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

As of December 31, 2012, we carried out an evaluation under the supervision and with the participation of our management, including our Chief Executive Officer (CEO) and our Chief Financial Officer (CFO), as to the effectiveness, design and operation of our disclosure controls and procedures. This evaluation considered the various processes carried out under the direction of our disclosure committee in an effort to ensure that information required to be disclosed in the U.S. Securities and Exchange Commission reports we file or submit under the Exchange Act is accurate, complete and timely. Our management, including our CEO and our CFO, does not expect that our disclosure controls and procedures or our internal controls will prevent and/or detect all errors and all fraud. A control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Further, the design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, within our company have been detected. Our disclosure controls and procedures are designed to provide reasonable assurance of achieving their objectives and our CEO and CFO concluded that our disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) were effective as of December 31, 2012.

Changes in Internal Control over Financial Reporting

There were no changes in our internal control over financial reporting during the fourth quarter of 2012 that have materially affected or are reasonably likely to materially affect our internal control over financial reporting.

ITEM 9B. OTHER INFORMATION

None.

115

PART III

ITEM 10.  DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

Board of Managers and Management

The supervision of our management and the general course of the company’s affairs and business operations is entrusted to the board of managers of our parent, EPE Acquisition, LLC.  The board of managers currently consists of nine managers appointed by our equity sponsors, with: (a) four designated by certain affiliates of Apollo (collectively, the “Apollo Member”); (b) two designated by Riverstone V Everest Holdings, L.P. (the “Riverstone Member”); (c) one designated by an affiliate of Access Industries (the “Access Member”); (d) one designated by an affiliate of Korea National Oil Corporation (the “KNOC Member”); and (e) the President and Chief Executive Officer of EP Energy.  See Item 13 of this Annual Report on Form 10-K for further details.

The following table provides information regarding our executive officers and the members of the board of managers, including the experience, qualifications, attributes or skills of such board members, as of March 1, 2013.

Name	Age	Position
Brent J. Smolik	51	President, Chief Executive Officer and Chairman of the Board
Clayton A. Carrell	47	Executive Vice President and Chief Operating Officer
Joan M. Gallagher	49	Senior Vice President, Human Resources and Administrative Services
John D. Jensen	43	Executive Vice President, Operations Services
Dane E. Whitehead	51	Executive Vice President and Chief Financial Officer
Marguerite N. Woung-Chapman	47	Senior Vice President, General Counsel and Corporate Secretary
Gregory A. Beard	41	Manager
Joshua J. Harris	48	Manager
Pierre F. Lapeyre Jr.	50	Manager
David Leuschen	61	Manager
Sam Oh	42	Manager
Ilrae Park	46	Manager
Donald A. Wagner	49	Manager
Rakesh Wilson	37	Manager

Brent J. Smolik.  Mr. Smolik has been our President and Chief Executive Officer and Chairman of the Board of Managers of our parent, EPE Acquisition, LLC, since May 2012.  He was previously Executive Vice President and a member of the Executive Committee of El Paso Corporation and President of EP Energy Corporation (a/k/a El Paso Exploration & Production Company) since November 2006. Mr. Smolik was President of ConocoPhillips Canada from April 2006 to October 2006. Prior to the Burlington Resources merger with ConocoPhillips, he was President of Burlington Resources Canada from September 2004 to March 2006. From 1990 to 2004, Mr. Smolik worked in various engineering and asset management capacities for Burlington Resources Inc., including the Chief Engineering role from 2000 to 2004. He was a member of Burlington’s Executive Committee from 2001 to 2006. Mr. Smolik also serves on the boards of the American Exploration and Production Council and America’s Natural Gas Alliance.  Mr. Smolik received his Bachelor of Science in Petroleum Engineering from Texas A&M University.  As the President and Chief Executive Officer of EP Energy, Mr. Smolik is the only officer of our company to sit on the board of our parent.  With over 29 years of energy industry experience, Mr. Smolik brings a comprehensive knowledge and understanding of our business and provides the board with essential insight and guidance from an inside perspective on the day-today operations of our company.

116

Clayton A. Carrell.  Mr. Carrell has been our Executive Vice President and Chief Operating Officer since May 2012. He was previously Senior Vice President, Chief Engineer of our predecessor, EP Energy Corporation (a/k/a El Paso Exploration & Production Company), since June 2010. Mr. Carrell joined El Paso Corporation in March 2007 as Vice President, Texas Gulf Coast Division. Prior to that, he was Vice President, Engineering & Operations at Peoples Energy Production from February 2001 to March 2007. Prior to joining Peoples Energy Production, Mr. Carrell worked at Burlington Resources and ARCO Oil and Gas Company from May 1988 to February 2001 in various domestic and international engineering and management roles. He serves on the Industry Board of the Texas A&M Petroleum Engineering Department, is a member of the Society of Petroleum Engineers and a Board Member of the US Oil & Gas Association. Mr. Carrell is also a member of the Center for Hearing and Speech Board of Trustees.

Joan M. Gallagher.  Ms. Gallagher has been our Senior Vice President, Human Resources and Administrative Services, since May 2012. She was previously Vice President, Human Resources of El Paso Corporation since March 2011. From August 2005 until February 2011, she served as Vice President, Human Resources of El Paso Exploration & Production Company. In that capacity, Ms. Gallagher had HR responsibility for El Paso Corporation’s exploration and production business unit and from January 2010 to February 2011, she had added HR responsibilities for shared services and midstream. Prior to 2005, Ms. Gallagher served as Vice President and Chief Administrative Officer of Torch Energy Advisors Incorporated.

John D. Jensen.  Mr. Jensen has been our Executive Vice President, Operations Services, since May 2012. He was previously Senior Vice President, Operations of our predecessor, EP Energy Corporation (a/k/a El Paso Exploration & Production Company), since June 2010. From May 2009 until May 2010 he served as Vice President of Operations of El Paso Exploration & Production Company. Mr. Jensen previously served as Vice President, Strategy and Engineering from April 2007 to May 2009. Prior to joining El Paso, Mr. Jensen served as Vice President, Business Development and Strategic Planning for ConocoPhillips Canada from June 2005 to March 2007. In addition, he held various positions in upstream and midstream engineering, planning, and business development at ConocoPhillips starting in July 1990. He is a board member of the Texas Oil and Gas Association and a member of the Society of Petroleum Engineers and the Society of Petroleum Evaluation Engineers.  Mr. Jensen also serves as a board member for Junior Achievement of Southeast Texas.

Dane E. Whitehead.  Mr. Whitehead has been our Executive Vice President and Chief Financial Officer since May 2012. He was previously Senior Vice President of Strategy and Enterprise Business Development and a member of the Executive Committee of El Paso Corporation since October 2009. He previously served as Senior Vice President and Chief Financial Officer of our predecessor, El Paso Exploration & Production Company, from May 2006 to October 2009. He was the Vice President and Controller of Burlington Resources Inc. from June 2005 to March 2006. From January 2002 to May 2005 he was Senior Vice President and Chief Financial Officer of Burlington Resources Canada. He was a member of the Burlington Resources Executive Committee from 2000 to 2006. From 1984 to 1993, Mr. Whitehead was an independent accountant with Coopers and Lybrand. He is a member of the American Institute of Certified Public Accountants.

Marguerite N. Woung-Chapman.  Ms. Woung-Chapman has been our Senior Vice President, General Counsel and Corporate Secretary since May 2012. She was previously Vice President, Legal Shared Services, Corporate Secretary and Chief Governance Officer of El Paso Corporation since November 2009. Ms. Woung-Chapman was Vice President, Chief Governance Officer and Corporate Secretary at El Paso Corporation from May 2007 to November 2009 and from May 2006 to May 2007 served as General Counsel and Vice President of Rates and Regulatory Affairs for El Paso Corporation’s Eastern Pipeline Group. She served as General Counsel of El Paso Corporation’s Eastern Pipeline Group from April 2004 to May 2006. Ms. Woung-Chapman served as Vice President and Associate General Counsel of El Paso Merchant Energy from July 2003 to April 2004. Prior to that time, she held various legal positions with El Paso Corporation and Tenneco Energy starting in 1991.  Ms. Woung-Chapman is also on the Board of Directors for the Girl Scouts of San Jacinto Council.

117

Gregory A. Beard.  Mr. Beard has been a manager of our parent company, EPE Acquisition, LLC, since May 2012. Mr. Beard joined Apollo in 2010 as the Global Head of Natural Resources, based in the New York office. Mr. Beard joined Apollo with 17 years of investment experience, the last ten years with Riverstone Holdings where he was a founding member, Managing Director and lead deal partner in many of the firm’s top oil and gas and energy service investments. While at Riverstone, Mr. Beard was involved in all aspects of the investment process including sourcing, structuring, monitoring and exiting transactions. Mr. Beard began his career as a Financial Analyst at Goldman Sachs, where he played an active role in that firm’s energy-sector principal investment activities. Mr. Beard has served on the board of directors of many oil and gas companies including Athlon Energy, Belden & Blake Corporation, Canera Resources, Cobalt International Energy, Eagle Energy, Legend Natural Gas I - IV, Mariner Energy, Phoenix Exploon, Pinnacle Agriculture, Talos Energy, Titan Operating, and Vantage Energy. Mr. Beard has served on the Board of various oilfield services companies, including CDM Max, CDM Resource Management, and International Logging. Mr. Beard received his BA from the University of Illinois at Urbana. Mr. Beard was appointed to the board of our parent company by the Apollo Member.

Joshua J. Harris.  Mr. Harris has been a manager of our parent company, EPE Acquisition, LLC, since May 2012. Mr. Harris is a Senior Managing Director of Apollo Global Management, LLC and Managing Partner of Apollo Management, L.P., which he co-founded in 1990. Prior to 1990, Mr. Harris was a member of the Mergers and Acquisitions Group of Drexel Burnham Lambert Incorporated. Mr. Harris currently serves on the boards of directors of Apollo Global Management, LLC, Berry Plastics Group Inc., LyondellBasell Industries, CEVA Group plc, Momentive Performance Materials and the holding company for Constellium and is the Managing Partner of the Philadelphia 76ers. During the past five years, Mr. Harris has served on the boards of directors of Verso Paper, Metals USA, Nalco, Covalence Specialty Materials, United Agri Products, Quality Distribution, Whitmire Distribution, and Noranda Aluminum and served as a general partner of AP Alternative Assets, L.P. Mr. Harris is actively involved in charitable and political organizations. Mr. Harris graduated summa cum laude and Beta Gamma Sigma from the University of Pennsylvania’s Wharton School of Business with a Bachelor of Science degree in Economics and received his MBA from the Harvard Business School, where he graduated as a Baker and Loeb Scholar. Mr. Harris was appointed to the board of our parent company by the Apollo Member.

Pierre F. Lapeyre Jr.  Mr. Lapeyre has been a manager of our parent company, EPE Acquisition, LLC, since May 2012. Mr. Lapeyre is a founder and Senior Managing Director of Riverstone. Prior to co-founding Riverstone, Mr. Lapeyre was a Managing Director at Goldman, Sachs & Co. in its Global Energy & Power Group. Mr. Lapeyre joined Goldman, Sachs & Co. in 1986 and spent his 14-year investment banking career focused on energy and power, particularly the midstream/pipeline and oil service sectors. Mr. Lapeyre’s responsibilities included client coverage and leading the execution of a wide variety of mergers and acquisitions, initial public offerings, strategic advisory and capital markets financings for clients across all sectors of the industry. Mr. Lapeyre serves on the boards of directors of Legend Natural Gas, Dynamic Industries, Quorum Technologies, Enduro Resource Partners LLC, Enduro Resource Partners II, L.P., Meritage Midstream Services II, LLC, Sage Midstream, LLC and Three Rivers Operating Company II LLC.  He is also a director of various internal Riverstone fund-related entities. Mr. Lapeyre received his Bachelor of Science in Finance and Economics from the University of Kentucky and his Master of Business Administration from the University of North Carolina at Chapel Hill.  Mr. Lapeyre was appointed to the board of our parent by the Riverstone Member.

David Leuschen.  Mr. Leuschen has been a manager of our parent company, EPE Acquisition, LLC, since May 2012. Mr. Leuschen is a founder and Senior Managing Director of Riverstone. Prior to co-founding Riverstone, Mr. Leuschen was a Partner and Managing Director at Goldman, Sachs & Co. and founder and head of the Goldman, Sachs & Co. Global Energy & Power Group. Mr. Leuschen joined Goldman, Sachs & Co. in 1977 and became head of the Global Energy & Power Group in 1985 and a Partner in 1986. He remained with Goldman, Sachs & Co. until leaving to found Riverstone. Mr. Leuschen has served as a director of Cambridge Energy Research Associates, Cross Timbers Oil Company (predecessor to XTO Energy), J. Aron Resources, Mega Energy, Inc. and Natural Meats Montana. He currently serves on the boards of directors of Legend Natural Gas, Dynamic Industries, Canera Resources and on the board of managers of Enduro Resource Partners LLC and Enduro Resource Partners II, L.P.  Mr. Leuschen is a director of various internal Riverstone fund-related entities. He is also president of Switchback Ranch LLC and has served on a number of non-profit boards of directors. Mr. Leuschen received his

118

Bachelor of Arts from Dartmouth and his Master of Business Administration from Dartmouth’s Amos Tuck School of Business.  Mr. Leuschen was appointed to the board of our parent by the Riverstone Member.

Sam Oh.  Mr. Oh has been a manager of our parent company, EPE Acquisition, LLC, since May 2012. Mr. Oh joined Apollo in 2008. He is a Senior Partner and one of the original founding members of Apollo’s Natural Resources Group. Prior to that time, Mr. Oh was with Morgan Stanley’s Commodities Department where he led principal investments for the group. While at Morgan Stanley, Mr. Oh launched a successful oil and gas fund, Helios Energy/Royalty Partners, and sat on the board of several portfolio companies. Mr. Oh has 18 years of experience, including 13 years of principal investing. He also has a broad range of experience in the commodities markets including risk management and structured products. Since joining Apollo, Mr. Oh has been actively involved in E&P investments made by Apollo managed funds, including leading the Parallel Petroleum acquisition in 2009. Mr. Oh was formerly Chairman of the Board of Parallel Petroleum and is a Director of Athlon Energy. Mr. Oh received a BS from the University of Pennsylvania’s Wharton School of Business and an MBA from the Yale School of Management. He is also a Certified Public Accountant and a Chartered Financial Analyst.  Mr. Oh was appointed to the board of our parent by the Apollo Member.

Ilrae Park.  Mr. Park has been a manager of our parent company, EPE Acquisition, LLC since December 2012. Mr. Park joined KNOC in 1990 and worked in the areas of new ventures, asset management worldwide and field operations, spending most of his career in Korea, Indonesia, United Arab Emirates, Yemen and the US.  He is currently the Representative and Managing Director of the US Business Unit of KNOC under which three subsidiaries are running E&P businesses.  At the same time, in the US he is serving as President and board member for KNOC Eagle Ford Corporation, President and board member for KNOC EPE Corporation, and Vice President and board member for Ankor E&P Holdings Corporation. Mr. Park received his bachelor degree in Petroleum & Minerals Engineering from Hanyang University, a master degree in Petroleum Engineering from Hanyang University and a PhD ABD in Petroleum Engineering from Hanyang University.  Mr. Park was appointed to the board of our parent by the KNOC Member.

Donald A. Wagner.  Mr. Wagner has been a manager of our parent company, EPE Acquisition, LLC, since May 2012. Mr. Wagner is a Managing Director of Access Industries, having been with Access since 2010. He is responsible for sourcing and executing new investment opportunities in North America, and he oversees Access’ current North American investments. From 2000 to 2009, Mr. Wagner was a Senior Managing Director of Ripplewood Holdings L.L.C., responsible for investments in several areas and heading the industry group focused on investments in basic industries. Previously, Mr. Wagner was a Managing Director of Lazard Freres & Co. LLC and had a 15-year career at that firm and its affiliates in New York and London. He is a board member of Access portfolio companies Warner Music Group and Boomerang Tube and was on the board of NYSE-listed RSC Holdings from November 2006 until August 2009. Mr. Wagner graduated summa cum laude with an A.B. in physics from Harvard College.  Mr. Wagner was appointed to the board of our parent by the Access Member.

Rakesh Wilson.  Mr. Wilson has been a manager of our parent company, EPE Acquisition, LLC, since May 2012. Mr. Wilson joined Apollo in 2009, where he is currently a senior member of the natural resources team. Prior to joining Apollo, Mr. Wilson was at Morgan Stanley’s Commodities Department in the principal investing group responsible for generating, evaluating and executing investment ideas across the energy sector with deals including Wellbore Capital and Helios Energy/Royalty Partners. Mr. Wilson began his career at Goldman Sachs in equity research and then moved to its investment banking division in New York and Asia. Mr. Wilson currently serves on the boards of directors of Athlon Energy and Talos Energy and previously served as a director of Parallel Petroleum. Mr. Wilson graduated from the University of Texas at Austin and received his MBA from INSEAD, Fontainebleau, France. He has also taught business courses at universities in China.  Mr. Wilson was appointed to the board of our parent by the Apollo Member.

119

Committees of the Board of Managers

Audit Committee.  The Audit Committee consists of seven members: Messrs. Oh (as Chairman), Beard, Harris, Lapeyre, Park, Wagner and Wilson.  In light of our status as a privately-held company and the absence of a public trading market for our common stock, there are no requirements that we have an independent audit committee and the board of managers of our parent has not designated any member of the Audit Committee as an “audit committee financial expert”.

Compensation Committee.  The Compensation Committee consists of seven members: Messrs. Oh (as Chairman), Beard, Harris, Leuschen, Park, Wagner and Wilson. The Compensation Committee is responsible for formulating, evaluating and approving the compensation and employment arrangements of the senior officers of the Issuer.

Budget Committee.  The Budget Committee consists of two members: Messrs. Lapeyre and Oh.  The Budget Committee is responsible for authorizing certain capital expenditures, acquisitions and dispositions by us and our subsidiaries.

Code of Ethics

We have adopted a code of ethics, referred to as our “Code of Conduct,” that applies to all of our employees, including our Chief Executive Officer, Chief Financial Officer and senior financial and accounting officers. In addition to other matters, our Code of Conduct establishes policies to deter wrongdoing and to promote honest and ethical conduct.  A copy of our Code of Conduct is available on our website at www.epenergy.com. We will post to our website all waivers to or amendments of our Code of Conduct, which are required to be disclosed by applicable law.

120

ITEM 11.  EXECUTIVE COMPENSATION

Compensation Discussion and Analysis

The following compensation discussion and analysis, or CD&A, provides information relevant to understanding the 2012 compensation of the executive officers identified in the Summary Compensation Table below, who we refer to as our named executive officers.  They include our Chief Executive Officer, Mr. Brent J. Smolik, our Chief Financial Officer, Mr. Dane E. Whitehead, and our other three most highly compensated executive officers, Mr. Clayton A. Carrell, Mr. John D. Jensen, and Ms. Marguerite N. Woung-Chapman.  The focus of this CD&A relates to the executive compensation policies and decisions of EP Energy following the closing of the sale of EP Energy Global LLC (f/k/a EP Energy Corporation and EP Energy, L.L.C. after its conversion into a Delaware limited liability company) by El Paso Corporation (“El Paso”) to our parent company EPE Acquisition, LLC in May 2012.  Where applicable, however, we have noted certain compensatory items made by El Paso to our named executive officers during 2012 prior to the closing of the sale relating to their service with El Paso prior to such time.  The discussion is divided into the following sections:

I.Compensation Objectives

II.Role of Compensation Committee, Compensation Consultant and Management

III.Elements of Total Compensation

IV.2012 Compensation Decisions

V.Other Compensation Matters

I.Compensation Objectives

In connection with the closing of the sale of EP Energy Global to EPE Acquisition, LLC in May 2012, we adopted new compensation programs designed to achieve the following objectives:

·attract, retain and motivate the high-performing executive talent necessary at a new privately-held operating company, and

·align the interests of our executive officers with both the short-term and long-term interests of our equity holders.

We believe these designs are accomplished by providing our executives with a competitive mix of short-term and long-term compensation, by rewarding superior performance, and by linking a significant portion of pay to measurable performance goals.

II.Role of Compensation Committee, Compensation Consultant and Management

Compensation Committee

The compensation committee of the Board of Managers of our parent, EPE Acquisition, LLC (“Compensation Committee”) is responsible for overseeing and approving all compensation for our CEO and those executive officers reporting directly to him, which includes all of our named executive officers.  The Compensation Committee receives information and advice from its compensation consultant as well as from our human resources department and management to assist in compensation determinations.

121

Compensation Consultant

In late 2012, the Compensation Committee retained Frederic W. Cook & Co., Inc. (“FW Cook”) as its independent compensation consultant. FW Cook advised the committee on incentive plan design and ongoing performance metrics.  FW Cook attends meetings of the Compensation Committee, participates in the committee’s executive sessions, and is directly accountable to the committee.  FW Cook is an independent executive compensation consulting firm and outside of the executive compensation consulting services provided to the committee, provides no services to the company.

Role of Management and CEO in Determining Executive Compensation

While the Compensation Committee has the responsibility to approve and monitor all compensation for our named executive officers, we, as management, play a supporting role in determining executive compensation.  At the Compensation Committee’s request, we recommend appropriate company-wide financial and non-financial performance goals. We work with the Compensation Committee to establish the agenda and prepare meeting information for each Compensation Committee meeting. In addition, our CEO assists the Compensation Committee by providing his evaluation of the performance of the executive officers who report directly to him, and recommends compensation levels for such officers.  The Compensation Committee evaluates the performance of the CEO and independently makes compensation decisions for him.

III.  Elements of Total Compensation Program

The table below summarizes the elements of EP Energy’s 2012 executive compensation program.  The primary elements of this program were adopted through negotiations between our management team and our equity sponsors leading up to the closing of the sale of EP Energy Global in May 2012.

Compensation Element	Objective	Key Features
Base Salary	To provide a minimum, fixed level cash compensation	Reviewed annually with adjustments made based on individual performance and anticipated inflation
Performance-Based Annual Cash Incentive Awards	To motivate and reward named executive officers’ contributions to achievement of pre-established performance goals, as well as individual performance	Target bonus opportunity established for each named executive officer; actual bonus payable from 0% to 200% of target Paid after year end once the Compensation Committee has determined company performance relative to pre-established performance goals and reviewed individual performance
Long-Term Equity Awards	To align interests of executive officers with our equity owners and encourage retention	Grant of equity awards following closing of the sale consisting of following: Management Incentive Units: ·intended to constitute profits interests ·issued at no cost and have value only to the extent the value of company increases ·vest ratably over 5 years and supervest in connection with certain liquidity events ·become payable only upon occurrence of certain liquidity events

122

Compensation Element	Objective	Key Features
		Class A Unit “Matching” Grant: ·each named executive officer purchased with own funds Class A units in our parent company following closing of the sale ·named executive officers awarded a “matching” Class A unit grant equal to 50% of the Class A units purchased ·Class A units are vested, but subject to transferability restrictions until earlier of 4 years from grant or certain liquidity events and subject to repurchase at the company’s election in certain termination scenarios
401(k) Plan	To provide retirement savings in a tax-efficient manner	Retirement benefits are provided under the following plan: 401(k) Retirement Plan ·401(k) plan covering all employees ·company contributes an amount equal to 100% of each participant’s voluntary contributions under the plan, up to a maximum of 6% of eligible compensation ·company contributes a “retirement contribution” equal to 5% of each participant’s eligible compensation annually
Health & Welfare Benefits	To provide reasonable health and welfare benefits to executives and their dependents and promote healthy living	Health and welfare benefits available to all employees, including medical, dental, vision and disability coverage Named executive officers also participate in our Senior Executive Survivor Benefits Plan Senior Executive Survivor Benefits Plan: ·provides executive officers with survivor benefit coverage in lieu of the coverage provided generally to employees under our group life insurance plan in the event of a named executive officer’s death ·amount of survivor benefit is 2½ X the executive officer’s annual salary

123

Compensation Element	Objective	Key Features
Severance	To provide a measure of financial security in the event an executive’s employment is terminated without cause	Severance payable in the event of an executive’s involuntary termination of employment without cause or termination for good reason, as set forth under the terms of the executive’s employment agreement. Benefits include 3X annual salary + target bonus for CEO; 2X annual salary + target bonus for other named executive officers
Perquisites	Limited perquisites provided to assist executives in carrying out duties and increase productivity	Includes financial planning assistance and subsidized annual physical examinations

IV.2012 Compensation Decisions

2012 Annual Base Salaries and 2012 Target Bonus Opportunities

Our named executive officers entered into employment agreements with EP Energy in connection with the closing of the sale of EP Energy Global to EPE Acquisition, LLC in May 2012.  The employment agreements provide for, among other things, base salaries and annual performance bonus targets.  Under the agreements, base salary levels for our named executive officers are reviewed on an annual basis by the Compensation Committee and may be increased at the committee’s discretion.  The following table sets forth the base salaries and annual target bonus opportunities for our named executive officers for 2012.

Annual Base Salaries and

Target Bonus Opportunities

Name	2012Base Salary($)(1)	2012 Target Bonus Opportunity (% of salary)(2)
Brent J. Smolik	850,000	100	%
Dane E. Whitehead	450,000	100	%
Clayton A. Carrell	400,000	100	%
John D. Jensen	400,000	100	%
Marguerite N. Woung-Chapman	370,000	55	%

(1)

Base salary amounts became effective as of the closing of the sale of EP Energy Global to EPE Acquisition, LLC on May 24, 2012. Prior to such time, our named executive officers received base salary amounts from El Paso in accordance with the position each held at El Paso prior to the sale. The annualized base salary levels payable to Messrs. Smolik, Whitehead, Carrell and Jensen and Ms. Woung-Chapman by El Paso prior to the sale were $600,000, $406,008, $352,284, $352,284 and $306,180, respectively.

(2)

Actual bonus amounts may be anywhere from 0% - 200% of target.

124

Annual Cash Incentive Awards for 2012 Performance

2012 Scorecard.  Shortly following the closing of the sale of EP Energy Global in May 2012, the Compensation Committee approved the company’s 2012 scorecard for use in determining 2012 cash incentive awards.  The 2012 scorecard is comprised of four categories of company-wide financial, operational and non-financial performance goals. These scorecard goals were set in alignment with our strategic plan and objectives for the year.  Each category includes between five to nine individual goals, each with a threshold, target and maximum achievement level.  The 2012 scorecard categories and weightings are set forth in the following table.

Scorecard Category	Weighting
Current Period Returns	45%
Long-Term Value Creation	35%
Health, Safety and Ethics	10%
Transition Milestones	10%

Range of Individual Bonus Amounts.  In addition to the company scorecard, individual performance plays an important role in determining annual incentives.  Each named executive officer has individual scorecard metrics which are evaluated and taken into account in determining their specific bonus amounts.  Pursuant to the terms of the executives’ employment agreements, the actual percentage of cash incentive bonuses could be at any level between 0% to 200% of target, based on the scorecard achievement level and individual performance adjustments.

125

EP Energy Scorecard Results.  In February 2013, the Compensation Committee reviewed the actual performance of our company relative to the 2012 scorecard and based on this review approved a 2012 company scorecard achievement level of 119%, reflecting above-target scorecard performance.

The Compensation Committee also evaluated each executive officer’s individual performance and contributions during 2012 and discussed with our CEO his recommendation as to the appropriate bonus levels for the executive officers reporting to him.

2012 Annual Incentives.  Based on the policies described above, the Compensation Committee approved the following annual incentive bonuses for our named executive officers, reflecting both 2012 scorecard achievement as well as individual performance.

Annual Cash Incentives

for 2012 Performance

	ActualIncentive Bonus ($)(1)
Brent J. Smolik	1,147,500
Dane E. Whitehead	630,000
Clayton A. Carrell	540,000
John D. Jensen	510,000
Marguerite N. Woung-Chapman	280,000

(1) Cash incentive awards for the named executive officers will be paid on or prior to March 15, 2013.

2012 Long-Term Incentive Award Grants

We provided our named executive officers with two forms of long-term equity incentive awards, each of which is designed to align the interests of our named executive officers with that of our equity investors, as described below.  These awards were granted at or shortly following the closing of the sale of EP Energy Global.

Management Incentive Units.  At the time of the closing of the sale, we issued Management Incentive Units (“MIPs”) to our executive officers, which units are intended to constitute profits interests.  The number of MIPs awarded to each named executive officer is set forth in the table below.

Management Incentive Units

(profits interests)

Name	MIPs(#)(1)
Brent J. Smolik	207,985
Dane E. Whitehead	69,328
Clayton A. Carrell	69,328
John D. Jensen	69,328
Marguerite N. Woung-Chapman	27,731

(1) The MIPs were issued on May 24, 2012.

126

Each award of MIPs represents a share in any future appreciation of the company, subject to certain limitations, after the date of grant and once certain shareholder returns have been achieved.  The MIPs are subject to time-based vesting requirements and vest ratably over 5 years (20% each year) based on the executive’s continued employment with the company.  In addition, the MIPs will supervest and become payable based on the achievement of certain predetermined performance measures, including the occurrence of certain liquidity events where our equity sponsors receive a return of at least one times their invested capital in our company.  The MIPs were issued at no cost to the executive and have value only to the extent the value of the company increases and a liquidity event occurs.  If the named executive officer voluntarily terminates his or her employment without good reason, 25% of the vested award and all unvested awards will be forfeited.  See the Potential Payments upon Termination or Change in Control section for further detail.

Class A Investment Units.  In addition to the MIPs described above, each of our named executive officers purchased with their own funds Class A units (capital interests) in our parent company (in an amount equal to 200%-400% of the executive’s base salary, based on position) shortly following the closing of the sale, at a price of $1,000 per unit.  In connection with this purchase, each named executive officer was awarded a “matching” Class A unit grant in an amount equal to 50% of the Class A units purchased.  The purchase of the Class A units by our named executive officers represented a significant commitment by our executive team to the future success of our company and the corresponding grant of the matching units was made to recognize such commitment and further align the interests of our executive team with that of our equity sponsors.  The matching units are vested, but along with the buy-in units, are subject to transferability restrictions until the earlier of 4 years from grant or certain liquidity events.  In addition, the Class A units (both buy-in and matching) are subject to repurchase by the company in the event of certain termination scenarios, as described in the Potential Payments upon Termination or Change in Control section.  The number of Class A units issued to each named executive officer is set forth in the table below.

Class A Investment Units

Name	Buy-InUnits(#)(1)	Matching Units(#)(2)	Total Units(#)
Brent J. Smolik	4,000	2,000	6,000
Dane E. Whitehead	1,700	850	2,550
Clayton A. Carrell	1,200	600	1,800
John D. Jensen	1,200	600	1,800
Marguerite N. Woung-Chapman	740	370	1,110

(1)	This column reflects the number of Class A units of our parent company that each named executive officer purchased with his or her own funds following the closing of the sale of EP Energy Global to EPE Acquisition, LLC.
(2)	This column reflects the matching Class A units awarded to each named executive officer in connection with his or her buy-in of Class A units.

V.Other Compensation Matters

Employment Agreements

In connection with the closing of the sale of EP Energy Global to EPE Acquisition, LLC, EP Energy entered into employment agreements with each of our named executive officers.  These agreements provide us and the executives with certain rights and obligations during and following a termination of employment. We believe these agreements are necessary to protect our legitimate business interests, as well as to protect

127

the executives in the event of certain termination events.  The employment agreements provide for, among other things, base salaries, annual performance bonuses and severance benefits in the event of a termination of employment under certain circumstances. The employment agreements became effective as of the closing of the sale.  The employment agreements have an initial term that expires on the fifth anniversary of their effective date, but the term of each agreement will automatically be extended for successive additional one-year periods unless either the executive or company provides written notice to the other at least 60 days prior to the end of the then-current initial term or extension term that no such automatic extension will occur.  In addition, in connection with entering into the agreement, the executives agreed to waive any rights relating to their participation in El Paso’s change in control severance plan.  Additional detail regarding the employment agreements is set forth following the Grants of Plan-Based Awards Table below.

2013 Guaranteed Bonus

In connection with the purchase by our named executive officers of Class A units of our parent company following the closing of the sale, each of our named executive officers was awarded a “guaranteed cash bonus” payable in March 2013, contingent upon the executive’s continued employment with the company through such date.  The guaranteed bonus was awarded in an amount equal to 50% of the value of the Class A units purchased by such executive.  The guaranteed bonus was designed to further motivate the executive officers to participate in the buy-in of Class A units of our parent company and to encourage retention during the formative months following the closing of the sale. The guaranteed bonus is not a substitute for the annual incentive bonus program described earlier in this CD&A.  The amount of each named executive officer’s guaranteed bonus payable in 2013 is set forth below.

2013 Guaranteed Bonus

Name	($)
Brent J. Smolik	2,000,000
Dane E. Whitehead	850,000
Clayton A. Carrell	600,000
John D. Jensen	600,000
Marguerite N. Woung-Chapman	370,000

The amount of the guaranteed bonus will be reflected in next year’s Summary Compensation Table under the “bonus” column as part of 2013 compensation in accordance with SEC reporting requirements.

Retention Plan

Our named executive officers participated in a retention plan that was established by El Paso in late 2011.  The plan was adopted, in consultation with Kinder Morgan, Inc. (“KMI”), for full-time employees of El Paso who primarily provided services to El Paso’s exploration and production business (the “Retention Plan”) which was subsequently sold to EPE Acquisition, LLC in May 2012.  Based on the level of gross sales proceeds received by El Paso/KMI in respect of the sale of the EP Energy business assets and on the specific time at which such assets were sold, a retention bonus pool in the aggregate amount of $1,750,000 was established for EP Energy officers.  Prior to the determination of actual pool funding in 2012, each of our named executive officers was awarded a percentage interest in the overall pool.  In accordance with this allocation, Mr. Smolik received $226,937, Mr. Whitehead received $153,564, Mr. Carrell received $127,085, Mr. Jensen received $127,085, and Ms. Woung-Chapman received $111,762.  These retention amounts were the obligation of El Paso/KMI, not EP Energy, and were paid by El Paso/KMI to our executive officers following the closing of the sale.

128

Outstanding El Paso Equity Awards

All of our named executive officers held vested and unvested stock options to purchase shares of El Paso common stock, restricted shares and performance shares granted under El Paso’s equity plan prior to the closing of the sale on May 24, 2012 of EP Energy Global to EPE Acquisition, LLC.  Pursuant to the terms of the merger agreement between El Paso and KMI, which merger became effective on May 25, 2012, each outstanding El Paso stock option, restricted share and performance share automatically vested and was converted into merger consideration in accordance with the terms of the El Paso/KMI merger agreement.  Our named executive officers were deemed to remain in the employ of El Paso up to the effective time of the merger between El Paso and KMI for purposes of the treatment of their outstanding El Paso equity awards, which vested and were converted into merger consideration as described above.  No new equity grants were made by El Paso in 2012 to our named executive officers prior to the closing of the sale.

129

COMPENSATION COMMITTEE REPORT

We have prepared this Compensation Committee Report as required by the Securities and Exchange Commission. We have reviewed and discussed with EP Energy’s management the Compensation Discussion and Analysis required by Item 402(b) of Regulation S-K.  Based on that review and discussion, we recommended to the Board of Managers that the Compensation Discussion and Analysis be included in EP Energy’s Annual Report on Form 10-K.

COMPENSATION COMMITTEE

Sam Oh, Chairman

Gregory A. Beard

Joshua J. Harris

David Leuschen

Ilrae Park

Donald A. Wagner

Rakesh Wilson

130

EXECUTIVE COMPENSATION

Summary Compensation Table

The following table and the narrative text that follows it provide a summary of the compensation earned or paid to our named executive officers on or following the closing of the sale of EP Energy Global to EPE Acquisition, LLC on May 24, 2012 according to applicable SEC regulations.  The principal position listed for each named executive officer below reflects the current position each executive holds at EP Energy.  The compensation reflected for each individual was for his or her services provided in all capacities to us and our parent and subsidiaries.

Summary Compensation Table

Name and Principal Position	Year	Salary($) (1)	Bonus($)	StockAwards($) (2)	OptionAwards($)	Non-EquityIncentive PlanCompensation($) (3)	Change inPensionValue andNonqualifiedDeferredCompensationEarnings($)	All Other Compensation ($) (4)	Total ($)
Brent J. Smolik	2012	511,063	—	20,951,593	—	1,147,500	—	8,050	22,618,206
President &
Chief Executive Officer
Dane E. Whitehead	2012	270,395	—	7,167,167	—	630,000	—	8,592	8,076,154
Executive Vice President &
Chief Financial Officer
Clayton A. Carrell	2012	240,372	—	6,917,167	—	540,000	—	21,179	7,718,718
Executive Vice President &
Chief Operating Officer
John D. Jensen	2012	240,372	—	6,917,167	—	510,000	—	17,222	7,684,761
Executive Vice President
Operations Services
Marguerite N. Woung-Chapman	2012	222,382	—	2,896,849	—	280,000	—	16,907	3,416,138
Senior Vice President, General Counsel & Corporate Secretary

(1)

The amount in this column reflects base salary amounts earned by our named executive officers on or after the closing of the sale of EP Energy Global to EPE Acquisition, LLC on May 24, 2012, and as such, represents approximately seven months of base salary. The annualized base salary levels for each our named executive officers following the closing of the sale are as follows: $850,000 for Mr. Smolik; $450,000 for Mr. Whitehead; $400,000 for Mr. Carrell; $400,000 for Mr. Jensen; and $370,000 for Ms. Woung-Chapman. Please see the Compensation Discussion and Analysis for further detail.

(2)

The amount in this column includes the aggregate grant date fair value of the stock awards granted to each named executive officer during 2012 computed in accordance with the Financial Accounting Standards Board Accounting Standards Codification Topic 718, “Compensation — Stock Compensation” (“FASB ASC Topic 718”). This includes the Management Incentive Units (profits interests), or MIPs, and the “matching” Class A unit awards. The grant date fair value used to calculate these amounts is the same as that used for our stock-based compensation disclosure in Note 9 to our financial statements included in this Annual Report on Form 10-K. The aggregate grant date fair value of the MIPs awarded to Messrs.  Smolik, Whitehead, Carrell and Jensen and Ms. Woung-Chapman was $18,951,593, $6,317,167, $6,317,167, $6,317,167 and $2,526,849, respectively. The aggregate grant date fair value of the matching Class A units awarded to Messrs.  Smolik, Whitehead, Carrell and Jensen and Ms. Woung-Chapman was $2,000,000, $850,000, $600,000, $600,000 and $370,000, respectively. See the Compensation Discussion and Analysis for further detail on these grants.

131

(3)	The amount in this column reflects each named executive officer’s annual cash incentive bonus earned for 2012 performance. Amounts for 2012 will be paid to the named executive officers on or prior to March 15, 2013.
(4)	The compensation reflected in the “All Other Compensation” column for 2012 for each of our named executive officers includes company matching and retirement contributions to EP Energy’s 401(k) Retirement Plan, annual executive physicals and financial planning assistance, which are listed in the table immediately below.

All Other Compensation included in the Summary Compensation Table for 2012

Name	Company Contributions to the 401(k) Retirement Plan($)	Annual Executive Physicals($) (A)	Financial Planning($) (B)	Total($)
Brent J. Smolik	6,750	1,300	—	8,050
Dane E. Whitehead	7,292	1,300	—	8,592
Clayton A. Carrell	16,042	—	5,137	21,179
John D. Jensen	9,634	1,300	6,288	17,222
Marguerite N. Woung-Chapman	15,549	1,358	—	16,907

(A)

The amounts in this column for 2012 reflect the cost to EP Energy for executive officer annual physicals.

(B)

The amounts in this column for 2012 reflect the cost for financial and tax planning assistance provided by EP Energy to our named executive officers. This amount is imputed as income and no tax gross-up is provided. Messrs. Smolik and Whitehead also received financial planning services during 2012; however, those services were paid for by El Paso pursuant to agreements in place prior to the sale of EP Energy and are therefore not reflected in this column. Ms. Woung-Chapman elected not to receive financial planning services during 2012.

132

2012 Realized Pay Table

The table below supplements the Summary Compensation Table that appears above.  This table shows the compensation actually realized by our named executive officers in 2012 for service to EP Energy on or after the closing of the sale on May 24, 2012.  This table is supplementary in nature and is not intended to replace the detailed disclosures set forth in the Summary Compensation Table above.  The primary difference between this supplemental table and the standard Summary Compensation Table is the removal of the “stock awards” column from this table.  SEC rules require that the grant date fair value of all stock awards be reported in the Summary Compensation Table for the year in which they were granted.  As noted in the Summary Compensation Table and discussed in detail in the Compensation Discussion and Analysis, in 2012 our named executive officers were awarded Management Incentive Units (profits interests), or MIPs, and were also awarded a “matching” Class A unit grant in connection with their purchase of Class A units in our parent company.  As a result, a significant portion of the total compensation amounts reported in the Summary Compensation Table relate to stock awards that are either not vested or are subject to significant transferability restrictions, are not publicly traded, and for which the value is uncertain (and with respect to the MIPs, which may end up having no value at all).  In contrast, the supplemental table below only includes amounts actually realized by our named executive officers for service to EP Energy in 2012 following the closing of the sale.

Name and Principal Position	Year	Salary($) (1)	Annual Incentive Bonus($) (2)	All Other Compensation ($) (3)	Total ($)
Brent J. Smolik	2012	511,063	1,147,500	8,050	1,666,613
President &
Chief Executive Officer
Dane E. Whitehead	2012	270,395	630,000	8,592	908,987
Executive Vice President &
Chief Financial Officer
Clayton A. Carrell	2012	240,372	540,000	21,179	801,551
Executive Vice President &
Chief Operating Officer
John D. Jensen	2012	240,372	510,000	17,222	767,594
Executive Vice President
Operations Services
Marguerite N. Woung-Chapman	2012	222,382	280,000	16,907	519,289
Senior Vice President, General Counsel & Corporate Secretary

(1)	Amounts shown equal the amounts reported in the “Salary” column of the Summary Compensation Table.
(2)	Amounts shown equal the amounts reported in the “Non-Equity Incentive Plan Compensation” column of the Summary Compensation Table.
(3)	Amounts shown equal the amounts reported in the “All Other Compensation” column of the Summary Compensation Table.

133

Grants of Plan-Based Awards

The following table sets forth the range of potential annual cash incentive bonuses for 2012 performance as a dollar amount for each of the named executive officers.  The table also sets forth the number of MIPs and the number of matching Class A units of our parent awarded during 2012 to the named executive officers.  In satisfaction of the applicable SEC regulations, the table further sets forth the date of grant of each award.

Grants of Plan-Based Awards

During the Year Ended December 31, 2012

						All Other	Grant Date
						Stock	Fair
		Estimated Possible Payouts				Awards:	Value
		Under Non-Equity Incentive				Number of	of Stock
		Plan Awards (1)				Shares of	and
		Threshold				Stock or	Option
	Grant	Not Met	Threshold	Target	Maximum	Units	Awards
Name	Date (2)	($)	($)	($)	($)	(#) (3)	($) (4)
Brent J. Smolik
Short-Term Incentive	N/A	—	425,000	850,000	1,700,000
MIPs (profits interests)	5/24/2012					207,985	18,951,593
Class A Units (matching grant)	5/24/2012					2,000	2,000,000
Dane E. Whitehead
Short-Term Incentive	N/A	—	225,000	450,000	900,000
MIPs (profits interests)	5/24/2012					69,328	6,317,167
Class A Units (matching grant)	5/24/2012					850	850,000
Clayton A. Carrell
Short-Term Incentive	N/A	—	200,000	400,000	800,000
MIPs (profits interests)	5/24/2012					69,328	6,317,167
Class A Units (matching grant)	5/24/2012					600	600,000
John D. Jensen
Short-Term Incentive	N/A	—	200,000	400,000	800,000
MIPs (profits interests)	5/24/2012					69,328	6,317,167
Class A Units (matching grant)	5/24/2012					600	600,000
Marguerite N. Woung-Chapman
Short-Term Incentive	N/A	—	101,750	203,500	407,000
MIPs (profits interests)	5/24/2012					27,731	2,526,849
Class A Units (matching grant)	5/24/2012					370	370,000

(1)	These columns show the potential value of the payout of the annual cash incentive bonuses for 2012 performance for each named executive officer if the threshold, target and maximum performance levels are achieved. The actual amount of the annual cash incentive bonuses paid for 2012 performance is shown in the Summary Compensation Table under the “Non-Equity Incentive Plan Compensation” column.
(2)	In accordance with FASB ASC Topic 718, the grant date of the MIPs and matching Class A unit awards was determined to be May 24, 2012. However, the actual transfer of Class A units (both buy-in and matching) to the named executive officers did not occur until July 23, 2012 following the receipt by our parent company of the buy-in proceeds from the named executive officers relating to their purchase of the Class A units.
(3)	This column shows the number of MIPs (profits interests) and the number of matching Class A units of our parent granted in 2012 to our named executive officers. The MIPs are scheduled to vest in five equal annual installments beginning one year from the date of grant. The Class A units are fully vested, but subject to transferability restrictions for a period of four years from the date of grant.
(4)	This column shows the grant date fair value of the MIPs and Class A matching units computed in accordance with FASB ASC Topic 718 granted to our named executive officers during 2012.

134

Description of Plan-Based Awards

Non-Equity Incentive Plan Awards

The material terms of the non-equity incentive plan awards reported in the above table are described in the Compensation Discussion and Analysis section above.

Equity Awards

The equity awards reported in the above table are likewise described in the Compensation Discussion and Analysis section of this Annual Report on Form 10-K.  They include the MIPs (profits interests) granted to our named executive officers at the time of the closing of the sale, as well as the “matching” Class A units of our parent company that our named executive officers received in connection with their purchase of Class A units following the closing of the sale.

The MIPs reflected in the table are scheduled to vest ratably over five years based on the executive’s continued employment with the company, although 25% of any vested awards are forfeitable in the event of certain termination events.  In addition, the MIPs will supervest and become payable based on the achievement of certain predetermined performance measures, including the occurrence of certain liquidity events where our equity sponsors receive a return of at least one times their invested capital in our company.  The MIPs were issued at no cost and have value only to the extent the value of the company increases and a liquidity event occurs.  The grant date fair value per MIP granted on May 24, 2012 was $91.12, computed using a reverse option pricing model based on several assumptions.  In accordance with FASB ASC Topic 718, 75% of the aggregate grant date fair value of the MIPs will be expensed over the five year vesting period, with the remaining 25% expensed upon a liquidity event when the right to such amounts become nonforfeitable.  See Note 9 to our financial statements included in this Annual Report on Form 10-K for further detail.

The matching Class A units reflected in the table are vested, but along with the buy-in units purchased by the executives, are subject to transferability restrictions until the earlier of four years from grant or certain liquidity events.  In addition, the Class A units are not publicly-traded and are subject to repurchase by the company in the event of certain termination scenarios.  The grant date fair value of each Class A unit was $1,000.

Class A Unit Distribution

In December 2012, the board of managers of our parent company authorized a cash distribution to all Class A unitholders of our parent on a pro-rata basis.  Our named executive officers, as owners of Class A units (buy-in units and matching award) received their pro-rata share of the distribution, which was treated as non-taxable return of investment.  The board, in its sole discretion, may authorize further cash distributions to its unitholders from time to time as it deems appropriate.

Employment Agreements

As discussed in the Compensation Discussion and Analysis, we entered into employment agreements with our named executive officers in connection with the closing of the sale of EP Energy Global to EPE Acquisition, LLC.  The employment agreements are effective as of May 24, 2012 and have a five year term.  Additional detail regarding the employment agreements is set forth below.

Brent J. Smolik

We entered into an employment agreement with Mr. Smolik, effective May 24, 2012, to serve as our President and Chief Executive Officer, as well as the Chairman of the Board of Managers of our parent EPE Acquisition, LLC.  Under the terms of the agreement, Mr. Smolik’s annual base salary is $850,000, with an annual cash bonus target equal to 100% of his annual base salary, with higher or lower amounts (0%

135

to 200% of target) payable depending on performance relative to targeted results.  Mr. Smolik is also entitled to an additional one-time guaranteed bonus of $2,000,000 payable in the first quarter of 2013.  Mr. Smolik is eligible to participate in all benefit plans and programs that are available to other senior executives of our company.  Mr. Smolik’s employment agreement contains provisions related to the payment of benefits upon certain termination events, as well as non-compete, non-solicitation and confidentiality restrictions.

Dane E. Whitehead

We entered into an employment agreement with Mr. Whitehead, effective May 24, 2012, to serve as our Executive Vice President and Chief Financial Officer.  Under the terms of the agreement, Mr. Whitehead’s annual base salary is $450,000, with an annual cash bonus target equal to 100% of his annual base salary, with higher or lower amounts (0% to 200% of target) payable depending on performance relative to targeted results.  Mr. Whitehead is also entitled to an additional one-time guaranteed bonus of $850,000 payable in the first quarter of 2013.  Mr. Whitehead is eligible to participate in all benefit plans and programs that are available to other senior executives of our company.  Mr. Whitehead’s employment agreement contains provisions related to the payment of benefits upon certain termination events, as well as certain non-compete, non-solicitation and confidentiality restrictions.

Clayton A. Carrell

We entered into an employment agreement with Mr. Carrell, effective May 24, 2012, to serve as our Executive Vice President and Chief Operating Officer.  Under the terms of the agreement, Mr. Carrell’s annual base salary is $400,000, with an annual cash bonus target equal to 100% of his annual base salary, with higher or lower amounts (0% to 200% of target) payable depending on performance relative to targeted results.  Mr. Carrell is also entitled to an additional one-time guaranteed bonus of $600,000 payable in the first quarter of 2013.  Mr. Carrell is eligible to participate in all benefit plans and programs that are available to other senior executives of our company.  Mr. Carrell’s employment agreement contains provisions related to the payment of benefits upon certain termination events, as well as certain non-compete, non-solicitation and confidentiality restrictions.

John D. Jensen

We entered into an employment agreement with Mr. Jensen, effective May 24, 2012, to serve as our Executive Vice President, Operations Services.  Under the terms of the agreement, Mr. Jensen’s annual base salary is $400,000, with an annual cash bonus target equal to 100% of his annual base salary, with higher or lower amounts (0% to 200% of target) payable depending on performance relative to targeted results.  Mr. Jensen is also entitled to an additional one-time guaranteed bonus of $600,000 payable in the first quarter of 2013.  Mr. Jensen is eligible to participate in all benefit plans and programs that are available to other senior executives of our company.  Mr. Jensen’s employment agreement contains provisions related to the payment of benefits upon certain termination events, as well as certain non-compete, non-solicitation and confidentiality restrictions.

Marguerite N. Woung-Chapman

We entered into an employment agreement with Ms. Woung-Chapman, effective May 24, 2012, to serve as our Senior Vice President, General Counsel & Corporate Secretary.  Under the terms of the agreement, Ms. Woung-Chapman’s annual base salary is $370,000, with an annual cash bonus target equal to 55% of her annual base salary, with higher or lower amounts (0% to 200% of target) payable depending on performance relative to targeted results.  Ms. Woung-Chapman is also entitled to an additional one-time guaranteed bonus of $370,000 payable in the first quarter of 2013.  Ms. Woung-Chapman is eligible to participate in all benefit plans and programs that are available to other senior executives of our company.  Ms. Woung-Chapman’s employment agreement contains provisions related to the payment of benefits upon certain termination events, as well as certain non-compete, non-solicitation and confidentiality restrictions.

136

Outstanding Equity Awards

The following table sets forth the total number and aggregate market value of unvested MIPs held by our named executive officers as of December 31, 2012.

Outstanding Equity Awards

at December 31, 2012

	Stock Awards
	Number of	Market Value
	Shares or	of Shares or
	Units of	Units of
	Stock That	Stock That
	Have Not	Have Not
	Vested	Vested
Name	(#) (1)	($) (2)
Brent J. Smolik	207,985	18,951,593
Dane E. Whitehead	69,328	6,317,167
Clayton A. Carrell	69,328	6,317,167
John D. Jensen	69,328	6,317,167
Marguerite N. Woung-Chapman	27,731	2,526,849

(1)

Number of unvested MIPs as of December 31, 2012. The MIPs are subject to time-based vesting requirements and are scheduled to vest ratably over 5 years, with 20% vesting on each of May 24, 2013, 2014, 2015, 2016 and 2017.

(2)

The values represented in this column have been calculated by multiplying $91.12, the grant date fair value per MIP, by the number of MIPs awarded. However, the actual value of the MIPs is dependent upon future appreciation of the company and the occurrence of certain predetermined liquidity events, and consequently, is not determinable at this time. See Note 9 to our financial statements included in this Annual Report on Form 10-K for further detail.

Option Exercises and Stock Vested Table

The following table sets forth the number of matching Class A units of our parent company awarded to each of our named executive officers during 2012.

Option Exercises and Stock Vested

During Fiscal Year 2012

	Stock Awards
Name	Number of SharesAcquired on Vesting (#) (1)	Value Realizedon Vesting($) (2)
Brent J. Smolik	2,000	2,000,000
Dane E. Whitehead	850	850,000
Clayton A. Carrell	600	600,000
John D. Jensen	600	600,000
Marguerite N. Woung-Chapman	370	370,000

137

(1)

Reflects the number of matching Class A units awarded in connection with each executive officer’s purchase of Class A units following the close of the sale. While vested, the units are subject to transferability restrictions until earlier of four years from grant or certain liquidity events and are subject to repurchase at the company’s election in certain termination scenarios. See “Potential Payments upon Termination or Change in Control” for further detail about the company’s repurchase rights.

(2)

Reflects the grant date value of the award as of the date of issuance. While the Class A units were valued at $1,000 per unit at the time of issuance, the units are not transferable and there is no public market for the units. As such, the actual value to be received by the named executive officers relating to these units is not determinable at this time.

Pension Benefits Table

We do not sponsor a defined benefit pension plan or supplemental executive retirement plan.

Nonqualified Defined Contribution and Other Nonqualified Deferred Compensation Plan

We do not sponsor a nonqualified deferred compensation plan.

Potential Payments upon Termination or Change in Control

The following section describes the benefits that may become payable to our named executive officers in connection with a termination of their employment.

Potential Payments under Employment Agreements

As discussed above, we have entered into employment agreements with our named executive officers. The agreements contain provisions for the payment of severance benefits following certain termination events. Below is a summary of the payments and benefits these named executive officers would receive in connection with various employment termination scenarios.

Under the terms of each employment agreement, if the executive’s employment is terminated by us without cause or by the executive for good reason then the executive is entitled to receive:

·any accrued obligations;

·a lump-sum payment equal to 200% (or 300% in the case of Mr. Smolik) of the sum of the executive’s (a) annual base salary and (b) target annual bonus for in the year in which the termination of employment occurs;

·a prorated annual bonus based on the executive’s target bonus opportunity for the year of termination; and

·continuation of basic life and health insurance following termination for 24 months (or 36 months in the case of Mr. Smolik).

If the executive’s employment is terminated for any other reason, our only obligation is the payment of any accrued obligations.

Potential Payments under Welfare Benefit Plans

We sponsor a welfare benefit plan available to all employees that provides long-term disability benefits in the event of an employee’s permanent disability.  In the event of a named executive officer’s permanent disability, disability income would be payable on a monthly basis as a long as the executive officer qualified as permanently disabled.  Long-term disability benefits are equal to 60% of the executive’s base salary in effect immediately prior to the disability, with a maximum monthly benefit equal to $25,000.  In the event of a named executive officer’s permanent disability, he or she may also elect to maintain basic life and health

138

insurance coverage under our welfare benefit plan at active-employee rates for as long as the individual qualifies as permanently disabled or until he or she reaches age 65.

In addition, our named executive officers participate in our Senior Executive Survivor Benefits Plan, which provides each of our named executive officers with survivor benefits coverage in the event of the executive’s death in lieu of the coverage provided generally under our group life insurance plan.  The amount of benefits provided is 2.5 times the executive’s annual salary.

Estimated Severance, Disability and Survivor Benefits

The following table presents the company’s estimate of the amount of the benefits to which each of the named executive officers would have been entitled had his or her employment been terminated or a change in control occurred on December 31, 2012 under the scenarios noted below.

Name	Voluntary Terminationor with Cause ($)	Death($)	Disability ($) (1)	Involuntary Termination without Cause or for Good Reason ($)	Change in Control (no termination) ($)
Brent J. Smolik
Severance Payment	—	—	—	5,950,000	—
Continued Medical	—	—	15,810	47,430	—
Disability Income	—	—	300,000	—	—
Survivor Benefit	—	2,125,000	—	—	—
Dane E. Whitehead
Severance Payment	—	—	—	2,250,000	—
Continued Medical	—	—	15,810	31,620	—
Disability Income	—	—	270,000	—	—
Survivor Benefit	—	1,125,000	—	—	—
Clayton A. Carrell
Severance Payment	—	—	—	2,000,000	—
Continued Medical	—	—	15,810	31,620	—
Disability Income	—	—	240,000	—	—
Survivor Benefit	—	1,000,000	—	—	—
John D. Jensen
Severance Payment	—	—	—	2,000,000	—
Continued Medical	—	—	15,810	31,620	—
Disability Income	—	—	240,000	—	—
Survivor Benefit	—	1,000,000	—	—	—
Marguerite N. Woung-Chapman
Severance Payment	—	—	—	1,350,500	—
Continued Medical	—	—	7,614	15,228	—
Disability Income	—	—	222,000	—	—
Survivor Benefit	—	925,000	—	—	—

(1) Disability income would be payable on a monthly basis as long as the executive officer qualifies as permanently disabled. The amounts in this column assume disability income and continued benefit coverage for a period of one year.

139

Treatment of Equity Awards

In addition to the severance and welfare benefits described above, our named executive officers’ outstanding equity awards may be impacted in the event of certain termination scenarios, as described below.

Class A Units

As discussed in the Compensation Discussion and Analysis, the Class A units of our parent issued to the named executive officers during 2012, including the buy-in units purchased by the executives and “matching” units awarded in connection with such purchase, are 100% vested, but subject to transferability restrictions until earlier of four years from grant or certain liquidity events.  In addition, the units are subject to repurchase at the company’s election in certain termination scenarios as follows:

Voluntary Termination or Termination with Cause

In the event of a named executive officer’s voluntary termination or if the executive’s employment is terminated by the company with cause, then for a period of one year following the termination, the company may elect (but is not required) to repurchase the Class A units held by such executive for a purchase price equal to the lesser of the original cost paid by the executive to purchase the units or the fair market value of the units (as determined by the board) on the repurchase date.  As the “matching” Class A units were awarded to the executives at no cost, this repurchase option would result in the options being repurchased for no consideration.

Involuntary Termination without Cause or for Good Reason or Termination due to Death or Disability

In the event of a named executive officer’s involuntary termination by the company without cause or termination by the executive with good reason, or in the event of the named executive officer’s death or disability, the company may elect (but is not required) to repurchase the Class A units held by such executive for a purchase price equal to the fair market value of the units (as determined by the board) on the repurchase date.

Management Incentive Units (MIPs)

As discussed in the Compensation Discussion and Analysis, the MIPs (profits interests) awarded to the named executive officers during 2012 vest ratably over five years.  Below is a description of the impact of certain termination scenarios on the MIP awards.

Termination with Cause

In the event of a named executive officer’s termination with cause, all MIPs held by such executive (whether vested or unvested) are forfeited without consideration.

Voluntary Termination

In the event of a named executive officer’s voluntary termination, 25% of the executive’s vested MIPs and all unvested MIPs are forfeited without consideration.  In such event, the company may elect (but is not required) to redeem the non-forfeited MIPs held by such executive at the fair market value of such MIPs (as determined by the Board) on the repurchase date.

Involuntary Termination without Cause or for Good Reason or Termination due to Death or Disability

In the event of a named executive officer’s involuntary termination by the company without cause or termination by the executive with good reason, or in the event of the named executive officer’s death or

140

disability, a pro-rata portion of the unvested MIPs will vest as of the termination date (pro-rata vesting relating solely to the single tranche of MIPs that would have vested as of the next vesting date).  All remaining unvested MIPs are forfeited without consideration.  In such event and for a period of one year following the termination, the company may elect (but is not required) to redeem the non-forfeited MIPs held by such executive at the fair market value of such MIPs (as determined by the board) on the repurchase date.

Director Compensation

Members of the board of managers of our parent, EPE Acquisition, LLC, do not receive a retainer or board meeting fees from EPE Acquisition, LLC or us for serving on the board.  Members of the board are reimbursed for their reasonable expenses for attending board functions.

Compensation Committee Interlocks and Insider Participation

The Compensation Committee is currently composed of Messrs. Oh (as Chairman), Beard, Harris, Leuschen, Park, Wagner and Wilson.  During 2012, no member of the Compensation Committee was a former or current officer or employee of EP Energy or any of its subsidiaries.  In addition, during 2012, none of our executive officers served (i) as a member of the compensation committee or board of directors of another entity, one of whose executive officers served on our Compensation Committee, or (ii) as a member of the compensation committee of another entity, one of whose executive officers served on our board.

141

ITEM 12.  SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

All of our equity interests are held indirectly by EPE Acquisition, LLC. The following table sets forth information regarding the beneficial ownership of our equity interests as of March 1, 2013, and shows the percentage owned by:

· each person known to beneficially own more than 5% of our equity interests;

· each of our named executive officers;

· each member of the board of managers of our parent; and

· all of the executive officers and members of the board of managers as a group.

The percentages of our equity interests beneficially owned are reported on the basis of regulations of the SEC governing the determination of beneficial ownership of securities. Under the rules of the SEC, a person is deemed to be a “beneficial owner” of a security if that person has or shares “voting power,” which includes the power to vote or to direct the voting of such security, or “investment power,” which includes the power to dispose of or to direct the disposition of such security. A person is also deemed to be a beneficial owner of any securities of which that person has a right to acquire beneficial ownership within 60 days. Under these rules, more than one person may be deemed a beneficial owner of the same securities and a person may be deemed a beneficial owner of securities as to which he has no economic interest. Except as otherwise indicated in the footnotes below, each of the beneficial owners has, to our knowledge, sole voting and investment power with respect to the indicated equity interests, and has not pledged any such equity interests as security.

	Beneficial Ownership of Equity Interests
Name of Beneficial Owner	Percentage of Ownership
EPE Acquisition, LLC(1)	100.0%
Brent J. Smolik(2)	—
Dane E. Whitehead(3)	—
Clayton A. Carrell(4)	—
John D. Jensen(5)	—
Marguerite N. Woung-Chapman(6)	—
Gregory A. Beard(7)	—
Joshua J. Harris(7)	—
Ilrae Park(8)	—
Pierre F. Lapeyre Jr.(9)	—
David Leuschen(9)	—
Sam Oh(7)	—
Donald A. Wagner(10)	—
Rakesh Wilson(7)	—
All managers and executive officers as a group	—

(1)All of our equity interests are held by EPE Holdings LLC. EPE Intermediate LLC is the sole member of EPE Holdings LLC, and EPE Acquisition, LLC (“EPE Acquisition”) is the sole member of EPE Intermediate LLC. ANRP (EPE AIV), L.P. (“ANRP EPE”), AIF PB VII (LS AIV), L.P. (“AIF PB”),

142

AIF VII (AIV), L.P. (“AIF VII”), Apollo (EPE Intermediate DC I), LLC (“Intermediate I”) and Apollo (EPE Intermediate DC II), LLC (“Intermediate II,” and together with ANRP EPE, AIF PB, AIF VII and Intermediate I, the “Apollo Funds”) have the right to appoint five out of ten members to EPE Acquisition’s board of managers and may thus be deemed to control actions that EPE Acquisition’s board of managers may take with respect to our equity interests that require approval of a majority of EPE Acquisition’s managers, as no actions could be authorized without the affirmative vote of the Apollo Funds. Apollo Management VII, L.P. (“Management VII”) is the manager of each of ANRP EPE, AIF PB and AIF VII, and a manager of Intermediate I and Intermediate II along with Apollo Commodities Management, L.P. (“Commodities Management”), which also serves as a manager of Intermediate I and Intermediate II. The general partner of Management VII is AIF VII Management, LLC (“AIF VII LLC”) and the general partner of Commodities Management is Apollo Commodities Management GP, LLC (“Commodities GP”). Apollo Management, L.P. (“Apollo Management”) is the sole member-manager of AIF VII LLC. Apollo Management GP, LLC (“Management GP”) is the general partner of Apollo Management. Apollo Management Holdings, L.P. (“Management Holdings”) is the sole member and manager of Management GP and of Commodities GP. Apollo Management Holdings GP, LLC (“Management Holdings GP”) is the general partner of Management Holdings. Leon Black, Joshua J. Harris and Marc Rowan are the managers, as well as principal executive officers, of Management Holdings GP, and as such may be deemed to have voting and dispositive control of our equity interests that are beneficially owned by EPE Acquisition. The address of EPE Holdings LLC, EPE Intermediate LLC and EPE Acquisition, LLC is c/o EP Energy LLC, 1001 Louisiana Street, Houston, Texas 77002. The address of each of the Apollo Funds other than ANRP EPE is One Manhattanville Road, Suite 201, Purchase, New York 10577. The address of ANRP EPE, Management VII, Commodities Management, AIF VII LLC, Commodities GP, Apollo Management, Management GP, Management Holdings and Management Holdings GP, and Messrs. Black, Harris and Rowan, is 9 West 57th Street, 43rd Floor, New York, New York 10019.

(2)Mr. Smolik holds 6,000 Class A units of EPE Acquisition, LLC, which accounts for less than 1% of the issued and outstanding equity interests of EPE Acquisition, LLC. The address of Mr. Smolik is c/o EP Energy LLC, 1001 Louisiana Street, Houston, Texas 77002.

(3)Mr. Whitehead holds 2,550 Class A units of EPE Acquisition, LLC, which accounts for less than 1% of the issued and outstanding equity interests of EPE Acquisition, LLC. The address of Mr. Whitehead is c/o EP Energy LLC, 1001 Louisiana Street, Houston, Texas 77002.

(4)Mr. Carrell holds 1,800 Class A units of EPE Acquisition, LLC, which accounts for less than 1% of the issued and outstanding equity interests of EPE Acquisition, LLC. The address of Mr. Carrell is c/o EP Energy LLC, 1001 Louisiana Street, Houston, Texas 77002.

(5)Mr. Jensen holds 1,800 Class A units of EPE Acquisition, LLC, which accounts for less than 1% of the issued and outstanding equity interests of EPE Acquisition, LLC. The address of Mr. Jensen is c/o EP Energy LLC, 1001 Louisiana Street, Houston, Texas 77002.

(6)Ms. Woung-Chapman holds 1,100 Class A units of EPE Acquisition, LLC, which accounts for less than 1% of the issued and outstanding equity interests of EPE Acquisition, LLC. The address of Ms. Woung-Chapman is c/o EP Energy LLC, 1001 Louisiana Street, Houston, Texas 77002.

(7)The address of each of the managers is c/o Apollo Global Management, LLC, 9 West 57th Street, New York, New York 10019.

(8)The address of the manager is c/o Korea National Oil Corporation, 5555 San Felipe St., Suite 1175, Houston, Texas 77056.

(9)The address of each of the managers is c/o Riverstone Holdings LLC, 712 Fifth Avenue, 19th Floor, New York, New York 10019.

143

(10)The address of the manager is c/o Access Industries Holdings LLC, 730 Fifth Avenue, 20th Floor, New York, New York 10019.

144

ITEM 13.  CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE

Second Amended and Restated Limited Liability Company Agreement of Parent

In connection with the closing of the sale of EP Energy Global, certain affiliates of Apollo (collectively, the “Apollo Member”), EPE 892 and TE Co-Investors (DC), LLC (the “EPE 892 Member”), EPE Domestic Co-Investors, L.P. (the “EPE Domestic Member”), EPE Overseas Co-Investors (DC), LLC (the “EPE Overseas Member,” and together with the EPE 892 Member and EPE Domestic Member, the “Co-Investment Members”), an affiliate of Access Industries (the “Access Member”), a vehicle through which management holds class A common units (“Class A Units”) of EPE Acquisition, LLC (the “EMI Member”), an affiliate of Korea National Oil Corporation (the “KNOC Member”), Riverstone V Everest Holdings, L.P. (the “Riverstone Member” and, together with the KNOC Member and the Access Member, the “Principal Members”), a vehicle through which management holds class B profits interest units (“Class B Units”) of EPE Acquisition, LLC (the “EEH Member”) (collectively, the “Members”) and EPE Acquisition, LLC, entered into a second amended and restated limited liability company agreement of EPE Acquisition, LLC (the “LLC Agreement”). The Apollo Member, the Co-Investment Members, the Principal Members and the EMI Member were issued Class A Units (such Members in their capacity as holders of Class A Units, the “Class A Members”).

The board of managers of EPE Acquisition, LLC consists of nine managers: (a) four designated by the Apollo Member; (b) two designated by the Riverstone Member; (c) one designated by the Access Member; (d) one designated by the KNOC Member; and (e) the Chief Executive Officer of EP Energy.

The number of managers that each such Member is entitled to designate is subject to such Member maintaining a certain Class A Unit ownership threshold. All decisions of the board of managers of our parent require a majority vote of the managers, other than certain extraordinary specified matters, which require the approval of a majority of the managers, which majority must include the affirmative vote by a manager designated by a Principal Member or its replacement elected in accordance with the LLC Agreement.

The LLC Agreement provides for customary rights of first refusal, drag-along rights, tag-along rights and preemptive rights for all Class A Members.

If, by the fifth anniversary of the consummation of the closing of the sale, EPE Acquisition, LLC or a successor entity of EPE Acquisition, LLC has not consummated an initial public offering or a change of control transaction, the Apollo Member or the Class A Members holding 40% of the then outstanding Class A units shall have the right to cause EPE Acquisition, LLC to consummate a qualified initial public offering (“QIPO”) without the approval of the board of our parent and without the consent of the other Members.

Related Party Transaction Policy

Under the LLC Agreement, the consummation of any transaction or series of related transactions involving EPE Acquisition, LLC or any of its subsidiaries, on the one hand, and any Member, manager or an affiliate of any Member or manager, on the other hand (each such transaction, a “Related Party Transaction”), requires the approval of a majority of the board of managers, other than those managers that are (or whose affiliates are) party to such Related Party Transaction or that have been designated by the Class A Members that are party, or whose affiliates are party to, such Related Party Transaction. This voting requirement does not apply to (among other things): (i) any transaction consummated in the ordinary course of business, on arm’s length terms and de minimis in nature; and (ii) an acquisition of additional securities by a Class A Member pursuant to an exercise of its preemptive rights pursuant to the LLC Agreement.

145

Transaction Fee Agreement

In connection with the closing of the sale of EP Energy Global, Apollo Global Securities, LLC, the Riverstone Member (together, the “Initial Service Providers”), Access and KNOC (collectively with the Initial Service Providers, the “Service Providers”) entered into a transaction fee agreement with EP Energy Global and EPE Acquisition, LLC (the “Transaction Fee Agreement”) relating to the provision of certain structuring, financial, investment banking and other similar advisory services by the Service Providers to EPE Acquisition, LLC, its direct and indirect divisions and subsidiaries, parent entities or controlled affiliates (collectively, the “Company Group”) in connection with the closing of the sale of EP Energy Global and future transactions.  We paid the Initial Service Providers a one-time transaction fee of $71.5 million in the aggregate in exchange for services rendered in connection with structuring the closing of the sale of EP Energy Global, arranging the financing and performing other services in connection with the closing of the sale of EP Energy Global. Subject to the terms and conditions of the Transaction Fee Agreement, we will pay to the Service Providers an additional transaction fee equal to the lesser of (i) 1% of the aggregate enterprise value paid or provided by the Company Group and (ii) $100,000,000 in connection with any transaction (including any merger, consolidation, recapitalization or sale of assets or equity interests) effected by a member of the Company Group after the consummation of the closing of the sale of EP Energy Global and (x) which results in a change of control of the equity and voting securities, or sale of all or substantially all of the assets of, the Company Group, or (y) which is in connection with one or more public offerings of any class of equity securities of EPE Acquisition, LLC, EP Energy Global or any other member of the Company Group.

Management Fee Agreement

In connection with the closing of the sale of EP Energy Global, Apollo Management VII, L.P., Apollo Commodities Management, L.P., with respect to Series I, the Riverstone Member, Access and KNOC (collectively, the “Management Service Providers”) entered into a management fee agreement with EPE Acquisition, LLC and EP Energy Global (the “Management Fee Agreement”) relating to the provision of certain management consulting and advisory services to the members of the Company Group following the consummation of the closing of the sale. In exchange for the provision of such services, we will pay the Management Service Providers a non-refundable annual management fee of $25 million in the aggregate.  For 2012, we paid a pro-rata management fee of approximately $15.2 million.

Participation of Apollo Global Securities, LLC in Offerings

Apollo Global Securities, LLC (“AGS”) is an affiliate of Apollo, one of our equity sponsors, and acted as an initial purchaser in the sales of three note offerings we made during 2012.  AGS received $937,500, $2,500,000 and $131,250 of the gross spread in the sales of our 6.875% senior secured notes due 2019, our 9.375% senior notes due 2020, and our 7.750% senior notes due 2022, respectively.  In addition, AGS participated as an arranger and underwriter in connection with our October 2012 issuance of $450 million of incremental term loans and received $100,000 for services rendered in connection with this transaction.

146

ITEM 14.  PRINCIPAL ACCOUNTANT FEES AND SERVICES

Ernst & Young LLP audited our financial statements for fiscal year 2012, including the audit of EP Energy LLC from its inception on March 23, 2012 through December 31, 2012, as well as the audit of our predecessor, EP Energy Global LLC (f/k/a EP Energy Corporation and EP Energy, L.L.C. after its conversion into a Delaware limited liability company) from January 1, 2012 through the closing of the sale on May 24, 2012.  Included in the table below are the aggregate fees for professional services rendered to us by Ernst & Young LLP for the year ended December 31, 2012.

Principal Accountant Fees and Services

Aggregate fees for professional services rendered to us by Ernst & Young LLP for the year ended December 31, 2012 were (in thousands):

Audit	$	2,982
Audit Related	2
Tax	160
Total	$	3,144

Audit Fees for the year ended December 31, 2012 were primarily for professional services rendered for the audit of consolidated financial statements of EP Energy LLC; the review of documents filed with the SEC; consents; the issuance of comfort letters; and certain financial accounting and reporting consultations.

Audit Related fees for the year ended December 31, 2012 were primarily for professional services and other advisory services rendered not included in Audit fees above.

Tax Fees for the year ended December 31, 2012 were for professional services related to tax compliance, tax planning and advisory services.

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

147

PART IV

ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

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

1. Financial statements.

The following consolidated financial statements are included in Part II, Item 8 of this report:

	Page
EP Energy LLC
Reports of Independent Registered Public Accounting Firms	61
Consolidated Statements of Income	63
Consolidated Statements of Comprehensive Income	64
Consolidated Balance Sheets	65
Consolidated Statements of Cash Flows	67
Consolidated Statements of Changes in Equity	68
Notes to Consolidated Financial Statements	69
Supplemental Selected Quarterly Financial Information (Unaudited)	103
Supplemental Oil and Natural Gas Operations (Unaudited)	104
2. Financial statement schedules and supplementary information required to be submitted
Schedule II — Valuation and Qualifying Accounts	114
3. and (b). Exhibits	151

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

The agreements included as exhibits to this report are intended to provide information regarding their terms and not to provide any other factual or disclosure information about us or the other parties to the agreements. The agreements may contain representations and warranties by the parties to the agreements, including us, solely for the benefit of the other parties to the applicable agreements and:

·should not in all instances be treated as categorical statements of fact, but rather as a way of allocating the risk to one of the parties if those statements prove to be inaccurate;

·may have been qualified by disclosures that were made to the other party in connection with the negotiation of the applicable agreement, which disclosures are not necessarily reflected in the agreement;

·may apply standards of materiality in a way that is different from what may be viewed as material to certain investors; and

·were made only as of the date of the applicable agreement or such other date or dates as may be specified in the agreement and are subject to more recent developments. Accordingly, these representations and warranties may not describe the actual state of affairs as of the date they were made or at any other time.

148

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, EP Energy LLC has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized on the 1st day of March 2013.

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

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

Signature	Title	Date
/s/ Brent J. Smolik
Brent J. Smolik	President and Chief Executive Officer  (Principal Executive Officer)	March 1, 2013
/s/ Dane E. Whitehead
Dane E. Whitehead	Executive Vice President and Chief Financial Officer (Principal Financial Officer)	March 1, 2013
/s/ Francis C. Olmsted III
Francis C. Olmsted III	Vice President and Controller (Principal Accounting Officer)	March 1, 2013
/s/ Gregory A. Beard
Gregory A. Beard	Manager, EPE Acquisition, LLC	March 1, 2013
/s/ Joshua J. Harris
Joshua J. Harris	Manager, EPE Acquisition, LLC	March 1, 2013
/s/ Pierre F. Lapeyre, Jr.
Pierre F. Lapeyre, Jr.	Manager, EPE Acquisition, LLC	March 1, 2013
/s/ David Leuschen
David Leuschen	Manager, EPE Acquisition, LLC	March 1, 2013
/s/ Sam Oh
Sam Oh	Manager, EPE Acquisition, LLC	March 1, 2013
/s/ Ilrae Park
Ilrae Park	Manager, EPE Acquisition, LLC	March 1, 2013
/s/ Brent J. Smolik
Brent J. Smolik	Manager, EPE Acquisition, LLC	March 1, 2013
/s/ Donald A. Wagner
Donald A. Wagner	Manager, EPE Acquisition, LLC	March 1, 2013
/s/ Rakesh Wilson
Rakesh Wilson	Manager, EPE Acquisition, LLC	March 1, 2013

149

EP ENERGY LLC

EXHIBIT INDEX

Each exhibit identified below is filed as part of this report. Exhibits filed with this Report are designated by “*”. All exhibits not so designated are incorporated herein by reference to a prior filing as indicated. Exhibits designated with a “+” constitute a management contract or compensatory plan or arrangement.

Exhibit No.	Exhibit Description
2.1	Purchase and Sale Agreement among EP Energy Corporation, EP Energy Holding Company and El Paso Brazil, L.L.C., as sellers, and EPE Acquisition, LLC, as purchaser, dated as of February 24, 2012 (Exhibit 2.1 to our Registration Statement on Form S-4, filed with the SEC on September 11, 2012).
2.2	Amendment No. 1 to Purchase and Sale Agreement, dated as of April 16, 2012, among EP Energy, L.L.C. (f/k/a EP Energy Corporation), EP Energy Holding Company, El Paso Brazil, L.L.C. and EPE Acquisition LLC (Exhibit 2.2 to our Registration Statement on Form S-4, filed with the SEC on September 11, 2012).
2.3	Amendment No. 2 to Purchase and Sale Agreement, dated as of May 24, 2012, among EP Energy, L.L.C. (f/k/a EP Energy Corporation), EP Energy Holding Company, El Paso Brazil, L.L.C., EP Production International Cayman Company, EPE Acquisition, LLC and solely for purposes of Sections 2 and 5 thereunder, El Paso LLC (Exhibit 2.3 to our Registration Statement on Form S-4, filed with the SEC on September 11, 2012).
3.1	Certificate of Formation of EP Energy LLC (Exhibit 3.1 to our Registration Statement on Form S-4, filed with the SEC on September 11, 2012).
3.2	Limited Liability Company Agreement of EP Energy LLC (Exhibit 3.2 to our Registration Statement on Form S-4, filed with the SEC on September 11, 2012).
4.1	Indenture, dated as of April 24, 2012, between EP Energy LLC (f/k/a Everest Acquisition LLC) and Everest Acquisition Finance Inc., as Co-Issuers, and Wilmington Trust, National Association, as Trustee, in respect of 6.875% Senior Secured Notes due 2019 (Exhibit 4.1 to our Registration Statement on Form S-4, filed with the SEC on September 11, 2012).
4.2	Indenture, dated as of April 24, 2012, between EP Energy LLC (f/k/a Everest Acquisition LLC) and Everest Acquisition Finance Inc., as Co-Issuers, and Wilmington Trust, National Association, as Trustee, in respect of 9.375% Senior Notes due 2020 (Exhibit 4.2 to our Registration Statement on Form S-4, filed with the SEC on September 11, 2012).
4.3	Indenture, dated as of August 13, 2012, between EP Energy LLC and Everest Acquisition Finance Inc., as Co-Issuers, and Wilmington Trust, National Association, as Trustee, in respect of 7.750% Senior Notes due 2022 (Exhibit 4.3 to our Registration Statement on Form S-4, filed with the SEC on September 11, 2012).
4.4	Registration Rights Agreement, dated as of April 24, 2012, between EP Energy LLC (f/k/a Everest Acquisition LLC), Everest Acquisition Finance Inc. and Citigroup Global Markets Inc. and J.P. Morgan Securities LLC, as representatives of the several initial purchasers, in respect of 6.875% Senior Secured Notes due 2019 (Exhibit 4.4 to our Registration Statement on Form S-4, filed with the SEC on September 11, 2012).
4.5	Registration Rights Agreement, dated as of April 24, 2012, between EP Energy LLC (f/k/a Everest Acquisition LLC), Everest Acquisition Finance Inc. and Citigroup Global Markets Inc. and J.P. Morgan Securities LLC, as representatives of the several initial purchasers, in respect of 9.375% Senior Notes due 2020 (Exhibit 4.5 to our Registration Statement on Form S-4, filed with the SEC on September 11, 2012).
4.6	Registration Rights Agreement, dated as of August 13, 2012, between EP Energy LLC, Everest Acquisition Finance Inc. and Citigroup Global Markets Inc., as representative of the several initial purchasers, in respect of 7.750% Senior Notes due 2022 (Exhibit 4.6 to our Registration Statement on Form S-4, filed with the SEC on September 11, 2012).
10.1	Credit Agreement, dated as of May 24, 2012, by and among EPE Holdings, LLC, as Holdings, EP Energy LLC (f/k/a Everest Acquisition LLC), as the Borrower, the Lenders party thereto, JPMorgan Chase Bank, N.A., as Administrative Agent and Collateral Agent, and the other parties party thereto (Exhibit 10.1 to our Registration Statement on Form S-4, filed with the SEC on September 11, 2012).
10.2	Guarantee Agreement, dated as of May 24, 2012, by and among EPE Holdings LLC, the Domestic Subsidiaries of the Borrower signatory thereto and JPMorgan Chase Bank, N.A., as collateral agent for the Secured Parties referred to therein (Exhibit 10.2 to our Registration Statement on Form S-4, filed

150

Exhibit No.	Exhibit Description
	with the SEC on September 11, 2012).
10.3	Collateral Agreement, dated as of May 24, 2012, by and among EPE Holdings LLC, EP Energy LLC (f/k/a Everest Acquisition LLC), each Subsidiary of EP Energy LLC identified therein and JPMorgan Chase Bank, N.A., as Collateral Agent (Exhibit 10.3 to our Registration Statement on Form S-4, filed with the SEC on September 11, 2012).
10.4	Pledge Agreement, dated as of May 24, 2012, by and among EP Energy LLC (f/k/a Everest Acquisition LLC), each Subsidiary of EP Energy LLC identified therein and JPMorgan Chase Bank, N.A., as Collateral Agent (Exhibit 10.4 to our Registration Statement on Form S-4, filed with the SEC on September 11, 2012).
10.5	Pledge Agreement, dated as of May 24, 2012, by and among El Paso Brazil, L.L.C., as Pledgor, and JPMorgan Chase Bank, N.A., as Collateral Agent (Exhibit 10.5 to our Registration Statement on Form S-4, filed with the SEC on September 11, 2012).
10.6	Senior Lien Intercreditor Agreement, dated as of May 24, 2012, among JPMorgan Chase Bank, N.A., as RBL Facility Agent and Applicable First Lien Agent, Citibank, N.A., as Term Facility Agent, Senior Secured Notes Collateral Agent and Applicable Second Lien Agent, Wilmington Trust, National Association, as Trustee under the Senior Secured Notes Indenture, EP Energy LLC and the Subsidiaries of EP Energy LLC named therein (Exhibit 10.6 to our Registration Statement on Form S-4, filed with the SEC on September 11, 2012).
10.7	Term Loan Agreement, dated as of April 24, 2012, by and among EP Energy LLC (f/k/a Everest Acquisition LLC), as Borrower, the Lenders party thereto, Citibank, N.A., as Administrative Agent and Collateral Agent, and Citigroup Global Markets Inc. and J.P. Morgan Securities LLC, as Co-Lead Arrangers (Exhibit 10.7 to our Registration Statement on Form S-4, filed with the SEC on September 11, 2012).
10.8	Guarantee Agreement, dated as of April 24, 2012, by and between Everest Acquisition Finance Inc., as Guarantor, and Citibank, N.A., as collateral agent for the Secured Parties referred to therein (Exhibit 10.8 to our Registration Statement on Form S-4, filed with the SEC on September 11, 2012).
10.9	Collateral Agreement, dated as of May 24, 2012, by and among EP Energy LLC (f/k/a Everest Acquisition LLC), each Subsidiary of EP Energy LLC identified therein and Citibank, N.A., as Collateral Agent (Exhibit 10.9 to our Registration Statement on Form S-4, filed with the SEC on September 11, 2012).
10.10	Pledge Agreement, dated as of May 24, 2012, by and among EP Energy LLC (f/k/a Everest Acquisition LLC), each Subsidiary of EP Energy LLC identified therein and Citibank, N.A., as Collateral Agent (Exhibit 10.10 to our Registration Statement on Form S-4, filed with the SEC on September 11, 2012).
10.11	Pledge Agreement, dated as of May 24, 2012, by and among EP Energy Brazil, L.L.C. (f/k/a El Paso Brazil, L.L.C.), as Pledgor, and Citibank, N.A., as Collateral Agent (Exhibit 10.11 to our Registration Statement on Form S-4, filed with the SEC on September 11, 2012).
10.12	Pari Passu Intercreditor Agreement, dated as of May 24, 2012, among Citibank, N.A., as Second Lien Agent, Citibank, N.A., as Authorized Representative for the Term Loan Agreement, Wilmington Trust, National Association, as the Initial Other Authorized Representative and each additional Authorized Representative from time to time party hereto (Exhibit 10.12 to our Registration Statement on Form S-4, filed with the SEC on September 11, 2012).
10.13	Transaction Fee Agreement, dated as of May 24, 2012, among EP Energy Global LLC, EPE Acquisition, LLC, Apollo Global Securities, LLC, Riverstone V Everest Holdings, L.P., Access Industries, Inc. and Korea National Oil Corporation (Exhibit 10.13 to our Registration Statement on Form S-4, filed with the SEC on September 11, 2012).
10.14	Management Fee Agreement, dated as of May 24, 2012, among EP Energy Global LLC, EPE Acquisition, LLC, Apollo Management VII, L.P., Apollo Commodities Management, L.P., With Respect to Series I, Riverstone V Everest Holdings, L.P., Access Industries, Inc. and Korea National Oil Corporation (Exhibit 10.14 to our Registration Statement on Form S-4, filed with the SEC on September 11, 2012).
10.15	Amendment, dated as of August 17, 2012, to the Credit Agreement, dated as of May 24, 2012, among EPE Holdings LLC, EP Energy LLC, the lenders party thereto and JPMorgan Chase Bank, N.A., as

151

Exhibit No.	Exhibit Description
	administrative agent and collateral agent (Exhibit 10.15 to our Registration Statement on Form S-4, filed with the SEC on September 11, 2012).
10.16	Amendment No. 1, dated as of August 21, 2012, to the Term Loan Agreement, dated as of April 24, 2012, among EP Energy LLC, the lenders party thereto and Citibank, N.A., as administrative agent and collateral agent (Exhibit 10.16 to our Registration Statement on Form S-4, filed with the SEC on September 11, 2012).
10.17	Joinder Agreement, dated as of August 21, 2012, among Citibank, N.A., as Additional Tranche B-1 Lender, EP Energy LLC and Citibank, N.A., as administrative agent (Exhibit 10.17 to our Registration Statement on Form S-4, filed with the SEC on September 11, 2012).
10.18	Incremental Facility Agreement, dated October 31, 2012, to the Term Loan Agreement, dated as of April 24, 2012 and amended by that certain Amendment No. 1 dated as of August 21, 2012, among EP Energy LLC, the lenders from time to time party thereto and Citibank, N.A., as administrative agent and collateral agent. (Exhibit 10.1 to our Current Report on Form 8-K, filed with the SEC on October 31, 2012).
10.19	Reaffirmation Agreement, dated as of October 31, 2012, among EP Energy LLC, each Subsidiary Party party thereto and Citibank, N.A., as administrative agent and collateral agent (Exhibit 10.2 to our Current Report on Form 8-K, filed with the SEC on October 31, 2012).
10.20+	Employment Agreement dated May 24, 2012 for Clayton A. Carrell (Exhibit 10.18 to our Registration Statement on Form S-4, filed with the SEC on September 11, 2012).
10.21+	Employment Agreement dated May 24, 2012 for John D. Jensen (Exhibit 10.19 to our Registration Statement on Form S-4, filed with the SEC on September 11, 2012).
10.22+	Employment Agreement dated May 24, 2012 for Brent J. Smolik (Exhibit 10.20 to our Registration Statement on Form S-4, filed with the SEC on September 11, 2012).
10.23+	Employment Agreement dated May 24, 2012 for Dane E. Whitehead (Exhibit 10.21 to our Registration Statement on Form S-4, filed with the SEC on September 11, 2012).
10.24+	Employment Agreement dated May 24, 2012 for Marguerite N. Woung-Chapman (Exhibit 10.22 to our Registration Statement on Form S-4, filed with the SEC on September 11, 2012).
10.25+	Senior Executive Survivor Benefit Plan adopted as of May 24, 2012 (Exhibit 10.23 to our Registration Statement on Form S-4, filed with the SEC on September 11, 2012).
10.26+	2012 Omnibus Incentive Plan (Exhibit 10.24 to our Registration Statement on Form S-4, filed with the SEC on September 11, 2012).
10.27+	Management Incentive Plan Agreement, dated as of May 24, 2012, between EPE Acquisition, LLC and EPE Employee Holdings, LLC (Exhibit 10.25 to our Registration Statement on Form S-4, filed with the SEC on September 11, 2012).
10.28+	Form of EPE Employee Holdings, LLC Management Incentive Unit Agreement (Exhibit 10.26 to our Registration Statement on Form S-4, filed with the SEC on September 11, 2012).
10.29+	Second Amended and Restated Limited Liability Company Agreement of EPE Employee Holdings, LLC dated as of May 24, 2012 (Exhibit 10.27 to our Registration Statement on Form S-4, filed with the SEC on September 11, 2012).
10.30+	Second Amended and Restated Limited Liability Company Agreement of EPE Management Investors, LLC dated as of May 24, 2012(Exhibit 10.28 to our Registration Statement on Form S-4, filed with the SEC on September 11, 2012).
10.31+	Amended and Restated Subscription Agreement, dated as of May 24, 2012, between EPE Acquisition LLC and EPE Management Investors, LLC (Exhibit 10.29 to our Registration Statement on Form S-4, filed with the SEC on September 11, 2012).
21.1*	Subsidiaries of EP Energy LLC
23.1*	Consent of Ryder Scott Company, L.P.
31.1*	Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
31.2*	Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
32.1*	Certification of Chief Executive Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
32.2*	Certification of Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
99.1*	Ryder Scott Company, L.P. reserve audit report for EP Energy LLC as of December 31, 2012.

152

Exhibit No.	Exhibit Description
101.INS*	XBRL Instance Document.
101.SCH*	XBRL Schema Document.
101.CAL*	XBRL Calculation Linkbase Document.
101.DEF*	XBRL Definition Linkbase Document.
101.LAB*	XBRL Labels Linkbase Document.
101.PRE*	XBRL Presentation Linkbase Document

153