EP Energy 424B3 Prospectus supplement

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Filed pursuant to Rule 424(b)(3)
Registration No. 333-205191

PROSPECTUS

EP Energy LLC
Everest Acquisition Finance Inc.

Exchange Offer for

$800,000,000 6.375% Senior Notes due 2023

The Notes and the Guarantees

•: We are offering to exchange $800,000,000 of our outstanding 6.375% Senior Notes due 2023 and certain related guarantees, which we refer to collectively as the "initial notes," for a like aggregate amount of our registered 6.375% Senior Notes due 2023 and certain related guarantees, which we refer to collectively as the "exchange notes." The exchange notes will be issued under an indenture dated as of May 28, 2015. We refer to the initial notes and the exchange notes collectively as the "notes."
•: The exchange notes will mature on June 15, 2023. We will pay interest on the exchange notes semi-annually on June 15 and December 15 of each year, commencing on December 15, 2015, at a rate of 6.375% per annum, to holders of record on the June 1 or December 1 immediately preceding the interest payment date.
•: Our obligations under the exchange notes will be fully and unconditionally guaranteed, jointly and severally, by our present and future direct or indirect wholly owned material domestic subsidiaries that guarantees our senior reserve-based revolving credit facility (the "RBL Facility").
•: The exchange notes and the related guarantees will be senior unsecured obligations and will rank (i) equally in right of payment to all of our existing and future senior debt and other obligations that are not, by their terms, expressly subordinated in right of payment to the notes, (ii) senior in right of payment to all of our existing and future debt and other obligations that are, by their terms, expressly subordinated in right of payment to the notes, (iii) effectively subordinated to all of our existing and future secured debt (including obligations under our RBL Facility and senior secured term loans), to the extent of the value of the assets securing such indebtedness and (iv) structurally subordinated to all obligations of each of our subsidiaries that is not a guarantor of the notes.

Terms of the Exchange Offer

•: The exchange offer will expire at 5:00 p.m., New York City time, on August 4, 2015, unless we extend it.
•: If all the conditions to this exchange offer are satisfied, we will exchange all of our initial notes that are validly tendered and not withdrawn for the exchange notes.
•: You may withdraw your tender of initial notes at any time before the expiration of this exchange offer.
•: The exchange notes that we will issue you in exchange for your initial notes will be substantially identical to your initial notes except that, unlike your initial notes, the exchange notes will have no transfer restrictions or registration rights.
•: The exchange notes that we will issue you in exchange for your initial notes are new securities with no established market for trading.

Before participating in this exchange offer, please refer to the section in this prospectus entitled "Risk Factors" beginning on page 27.

Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved of these securities or determined if this prospectus is truthful or complete. Any representation to the contrary is a criminal offense.

We have not applied, and do not intend to apply, for listing the notes on any national securities exchange or automated quotation system.

Each broker-dealer that receives exchange notes for its own account pursuant to the exchange offer must acknowledge that it will deliver a prospectus in connection with any resale of those exchange notes. The letter of transmittal states that by so acknowledging and by delivering a prospectus, a broker-dealer will not be deemed to admit that it is an "underwriter" within the meaning of the Securities Act of 1933, as amended (the "Securities Act"). This prospectus, as it may be amended or supplemented from time to time, may be used by a broker-dealer in connection with resales of exchange notes received in exchange for initial notes where those initial notes were acquired by that broker-dealer as a result of market-making activities or other trading activities. We have agreed that, for a period of 180 days after the expiration date, we will make this prospectus available to any broker-dealer for use in connection with any such resale. See "Plan of Distribution."

The date of this prospectus is July 2, 2015.

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		Page

SUMMARY		1
RISK FACTORS		27
MARKET AND INDUSTRY DATA		60
CAUTIONARY STATEMENT CONCERNING FORWARD-LOOKING STATEMENTS		61
USE OF PROCEEDS		62
CAPITALIZATION		63
SELECTED HISTORICAL CONSOLIDATED FINANCIAL DATA		64
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS		66
BUSINESS		102
MANAGEMENT		125
COMPENSATION DISCUSSION AND ANALYSIS		134
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT		165
CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS		170
DESCRIPTION OF OTHER INDEBTEDNESS		173
THE EXCHANGE OFFER		177
DESCRIPTION OF EXCHANGE NOTES		186
BOOK-ENTRY; DELIVERY AND FORM		259
CERTAIN U.S. FEDERAL INCOME TAX CONSIDERATIONS		261
PLAN OF DISTRIBUTION		268
LEGAL MATTERS		269
EXPERTS		269
WHERE YOU CAN FIND MORE INFORMATION		269
GLOSSARY OF OIL AND NATURAL GAS TERMS		A-1
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS		F-1

We have not authorized anyone to give you any information or to make any representations about us or the transactions we discuss in this prospectus other than those contained in this prospectus. If you are given any information or representations about these matters that is not discussed in this prospectus, you must not rely on that information. This prospectus is not an offer to sell or a solicitation of an offer to buy securities anywhere or to anyone where or to whom we are not permitted to offer or sell securities under applicable law. The delivery of this prospectus does not, under any circumstances, mean that there has not been a change in our affairs since the date of this prospectus. Subject to our obligation to amend or supplement this prospectus as required by law and the rules and regulations of the SEC, the information contained in this prospectus is correct only as of the date of this prospectus, regardless of the time of delivery of this prospectus or any sale of these securities.

Until September 30, 2015 (90 days after the date of this prospectus), all dealers effecting transactions in the exchange notes, whether or not participating in the exchange offer, may be required to deliver a prospectus. This is in addition to the obligation of dealers to deliver a prospectus when acting as underwriters and with respect to their unsold allotments or subscriptions.

Each prospective purchaser of the exchange notes must comply with all applicable laws and regulations in force in any jurisdiction in which it purchases, offers or sells the notes or possesses or distributes this prospectus and must obtain any consent, approval or permission required by it for the purchase, offer or sale by it of the additional exchange notes under the laws and regulations in force in any jurisdiction to which it is subject or in which it makes such purchases, offers or sales, and we shall not have any responsibility therefor

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USE OF NON-GAAP FINANCIAL INFORMATION

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

•: EBITDAX—please see "Management's Discussion and Analysis of Financial Condition and Results of Operations—Supplemental Non-GAAP Measures;"
•: Adjusted EBITDAX—please see "Management's Discussion and Analysis of Financial Condition and Results of Operations—Supplemental Non-GAAP Measures;"
•: Pro Forma Adjusted EBITDAX—please see "Management's Discussion and Analysis of Financial Condition and Results of Operations—Supplemental Non-GAAP Measures;"
•: Cash Operating Costs—please see "Management's Discussion and Analysis of Financial Condition and Results of Operations—Results of Operations—Cash Operating Costs and Adjusted Cash Operating Costs";
•: Adjusted Cash Operating Costs—please see "Management's Discussion and Analysis of Financial Condition and Results of Operations—Results of Operations—Cash Operating Costs and Adjusted Cash Operating Costs"; and
•: PV-10—please see "Summary—Summary Pro Forma Operating and Reserve Information."

PRESENTATION OF RESERVES INFORMATION

The SEC permits oil and gas companies, in their filings with the SEC, to disclose only estimated proved, probable and possible reserves that meet the SEC's definitions of such terms. We disclose estimated proved reserves in this prospectus. Our estimates of proved reserves contained in this prospectus were estimated by our internal staff of engineers and comply with the rules and definitions promulgated by the SEC. For the year ended December 31, 2014 we engaged Ryder Scott Company, L.P., an independent petroleum engineering consultant firm, to perform reserve audit services with respect to a substantial portion of our proved reserves.

EQUIVALENCY

This prospectus presents certain production and reserves-related information on an "equivalency" basis. When we refer to oil and natural gas in "equivalents," we are doing so to compare quantities of oil with quantities of natural gas or to express these different commodities in a common unit. In calculating equivalents, we use a generally recognized standard in which one Bbl of oil and/or NGLs is equal to six Mcf of natural gas. Also, when we refer to cubic feet measurements, all measurements are at a pressure of 14.73 pounds per square inch. These conversions are based on energy equivalency conversion methods primarily applicable at the burner tip and do not represent value equivalencies at the wellhead. Although these conversion factors are industry accepted norms, they are not reflective of price or market value differentials between product types.

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SUMMARY

The term "initial notes" refers to the 6.375% Senior Notes due 2023 and certain related guarantees that were issued on May 28, 2015 in a private offering, and the term "exchange notes" refers to the 6.375% Senior Notes due 2023 and certain related guarantees offered by this prospectus. The term "notes" refers to the initial notes and the exchange notes, collectively. Unless otherwise indicated or the context otherwise requires, references in this prospectus to "EP Energy," "we," "our," "us," and the "Company" refer to EP Energy LLC (the "Issuer") and each of its consolidated subsidiaries, including Everest Acquisition Finance Inc. (the "Co-Issuer" and, together with the Issuer, the "Issuers"). This summary highlights information appearing elsewhere in this prospectus. This summary is not complete and does not contain all of the information that you should consider before investing in the notes. You should carefully read the entire prospectus, including the information presented under "Risk Factors" and "Disclosure Regarding Forward-Looking Statements."

Certain oil and gas industry terms used in this prospectus are defined in the "Glossary of Oil and Natural Gas Terms" beginning on page A-1 of this prospectus. Estimates of our oil, natural gas and NGLs reserves, related future net cash flows and the present values thereof as of December 31, 2014 included herein were prepared by our internal staff of engineers and audited by the independent petroleum engineering consultant firm of Ryder Scott Company, L.P. ("Ryder Scott").

Our Company

We are an independent exploration and production company engaged in the acquisition and development of unconventional onshore oil and natural gas properties in the United States. We are focused on creating value through the development of our low-risk drilling inventory located predominantly in four operating areas: the Eagle Ford Shale (South Texas), the Wolfcamp Shale (Permian Basin in West Texas), the Altamont Field in the Uinta Basin (Northeastern Utah) and the Haynesville Shale (North Louisiana). In our operating areas, we have identified 5,673 drilling locations (including 979 drilling locations to which we have attributed proved undeveloped reserves as of December 31, 2014, of which approximately 92% are oil wells). At 2014 activity levels, this represents approximately 21 years of drilling inventory (more than 30 years of drilling inventory at 2015 drilling levels). As of December 31, 2014, we had proved reserves of 622.2 MMBoe (52% oil and 67% liquids) and for the quarter ended March 31, 2015, we had average net daily production of 102,421 Boe/d (59% oil and 70% liquids).

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

Each of our operating areas is characterized by a favorable operating environment, a long-lived reserve base and high drilling success rates. We have established significant contiguous leasehold positions in each area, representing approximately 477,000 net (647,000 gross) acres in total. Beginning in 2012, our capital programs have focused predominantly on the Eagle Ford Shale, the Wolfcamp Shale and Altamont, three of the premier unconventional oil plays in the United States, resulting in oil reserve and production growth of 10% and 51%, respectively, from December 31, 2013 to December 31, 2014.

Prior to 2014, we divested our non-core domestic natural gas assets and an equity investment for a total consideration of approximately $1.5 billion. As a result of these asset sales, we became a growth-oriented, 100% onshore, oil-weighted company with a large inventory of low-risk drilling locations. While we continue to principally focus on the development of our oil-weighted assets, our Haynesville

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Shale position gives us the flexibility to allocate capital to natural gas production based on changes in commodity prices and rates of return.

The following table provides a summary of oil, natural gas and NGLs reserves as of December 31, 2014 and production data for the quarter ended March 31, 2015 for each of our areas of operation. Our estimated proved reserves have been prepared by our internal reserve engineers and audited by Ryder Scott Company, L.P., our independent petroleum engineering consultants since 2004.

	Estimated Proved Reserves(1)

	Estimated Proved Reserves(1)														Average Net Daily Production (MBoe/d)
	Oil (MMBbls)		NGLs (MMBbls)		Natural Gas (Bcf)		Total (MMBoe)		Liquids (%)			Proved Developed (%)			Average Net Daily Production (MBoe/d)
Operating Areas
Eagle Ford Shale		183.1		65.5		398.0		314.9		79	%		32	%		54.7
Wolfcamp Shale		53.9		28.7		158.2		109.0		76	%		47	%		17.9
Altamont		83.8		—		180.4		113.9		74	%		49	%		17.1
Haynesville Shale		—		—		506.1		84.3		—	%		36	%		12.6

Total Areas		320.8		94.2		1,242.7		622.1		67	%		38	%		102.3
Other(2)		—		—		0.3		0.1		—	%		100	%		0.1

Total		320.8		94.2		1,243.0		622.2		67	%		38	%		102.4

(1): Proved reserves were evaluated using first day 12- month prices of $94.99 per barrel of oil (WTI) and $4.34 per MMBtu of natural gas (Henry Hub).
(2): Comprised of outside operated overriding interests in the Gulf of Mexico and Rockies.

Our Properties and Operating Areas

Eagle Ford Shale. The Eagle Ford Shale, located in South Texas, is one of the premier unconventional oil plays in the United States. We were an early entrant into this play in late 2008, and since that time have acquired a leasehold position in the core of the oil window, primarily in La Salle County. The Eagle Ford formation in La Salle county has up to 125 feet of net thickness (165 feet gross). Due to its high carbonate content, the formation is also very brittle, and exhibits high productivity when fractured. As of December 31, 2014, we had 81,753 net (88,890 gross) acres in the Eagle Ford, and we have identified 872 drilling locations.

During 2014, we invested $1,087 million in capital expenditures in our Eagle Ford Shale and operated an average of 5.5 drilling rigs. As of March 31, 2015, we had 439 net producing wells (436 net operated wells) and are currently running three rigs. For the quarter ended March 31, 2015, our average net daily production was 54,709 Boe/d, representing growth of 18% over the same period in 2014. For the year ended December 31, 2014 our average cost per gross well was $7.2 million ($6.8 million per net well).

Wolfcamp Shale. The Wolfcamp Shale is located in the Permian Basin. The Permian Basin is characterized by numerous, stacked oil reservoirs that provide excellent targets for horizontal drilling. In 2009 and 2010, we leased 138,130 net (138,469 gross) acres on the University of Texas Land System in the Wolfcamp Shale, located primarily in Reagan, Crockett, Upton and Irion counties. In 2014, we acquired producing properties and undeveloped acreage in the Southern Midland Basin, of which 37,000 net acres are adjacent to our existing Wolfcamp Shale position. The acquisition represented an approximate 25% expansion of our Wolfcamp acreage.

Our large, contiguous acreage positions are characterized by stacked pay zones, including the Wolfcamp A, B, and C, which combine for over 750 feet of net (approximately 1,000 feet of gross)

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thickness. The Wolfcamp has high organic content and is composed of interbedded shale, silt, and fine-grained carbonate that respond favorably to fracture stimulation. As of December 31, 2014, we have 179,780 net (181,487 gross) acres in the Wolfcamp, in which we have identified approximately 3,300 drilling locations in the Wolfcamp A, B, and C. In the second half of 2014, we initiated drilling in the Wolfcamp A.

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

During 2014, we invested $822 million in capital expenditures (including $158 million of acquisition capital) in our Wolfcamp Shale and operated an average of 3.5 drilling rigs. As of March 31, 2015, we had 214 net operated producing wells. We are currently running one rig. For the quarter ended March 31, 2015, our average net daily production was 17,923 Boe/d, representing growth of 50% over the same period in 2014. For the year ended December 31, 2014, our average cost per gross well was $6.2 million ($6.2 million per net well).

Altamont. The Altamont field is located in the Uinta Basin in northeastern Utah. The Uinta Basin is characterized by naturally fractured, tight-oil sands and carbonates with multiple pay zones. Our operations are primarily focused on developing the Altamont Field Complex (comprised of the Altamont, Bluebell and Cedar Rim fields), which is the largest field in the basin. We own 177,119 net (319,600 gross) acres in Duchesne and Uinta Counties. The Altamont Field Complex has a gross pay interval thickness of over 4,300 feet and we believe the Wasatch and Green River formations are ideal targets for low-risk, infill, vertical drilling and modern fracture stimulation techniques. Our commingled production is from over 1,500 feet of net stimulated rock. Our current activity is mainly focused on the development of our vertical inventory on 80-acre and 160-acre spacing. As of December 31, 2014, we have identified 1,304 drilling locations (1,295 vertical and 9 horizontal). The industry has piloted 80-acre vertical downspacing and in November 2014 the Utah Board of Oil, Gas and Mining approved 80-acre well density on approximately 50,000 acres of our Altamont net acreage. Industry activity has also focused on horizontal drilling in the Wasatch and Green River formations testing tight carbonate and sand intervals. Due to the largely held-by-production nature of our acreage position, if these programs are successful, it will result in additional vertical and horizontal drilling opportunities that could be added to our inventory of drilling locations.

During 2014, we invested $283 million in capital expenditures in the Altamont Field, operated an average of three drilling rigs, and drilled 47 operated gross wells. As of March 31, 2015, we had 368 net producing wells (360 net operated wells). We are currently running two rigs. For the quarter ended March 31, 2015, our average net daily production was 17,079 Boe/d, representing growth of 27% over the same period in 2014. For the year ended December 31, 2014 our average cost per gross well was $5.2 million ($4.4 million per net well).

Haynesville Shale. In addition to our oil programs, we hold significant natural gas assets in the Haynesville Shale, located in East Texas and Northern Louisiana. Our operations are concentrated primarily in Desoto Parish, Louisiana in the Holly Field. We currently have 38,224 net (57,502 gross) acres in this area. As of December 31, 2014, we have identified 197 drilling locations.

During 2014, we invested $8 million in capital expenditures in our Haynesville Shale program. For the quarter ended March 31, 2015, our average net daily production was 76 MMcfe/d. As of March 31, 2015, we had 106 net producing wells. In 2012, we suspended investment in the Haynesville program due to low natural gas prices. In 2015, we have allocated a portion of our capital budget to our Haynesville drilling program based on its returns in the forecasted price environment. Our acreage in the Haynesville Shale is held-by-production.

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The following table provides a summary of acreage and inventory data as of December 31, 2014:

	Acres

	Acres				Drilling Locations(1) (#)			Inventory (Years)(3)		Working Interest (%)
	Gross		Net		Drilling Locations(1) (#)			Inventory (Years)(3)		Working Interest (%)
Operating Areas
Eagle Ford Shale		88,890		81,753		872	136		6.4		89	%	67	%
Wolfcamp Shale		181,487		179,780		3,300	90		36.7		97	%	73	%
Wolfcamp A						1,165					97	%	73	%
Wolfcamp B						1,019					97	%	73	%
Wolfcamp C						1,116					97	%	73	%
Altamont		319,600		177,119		1,304	47		27.7		75	%	62	%
Vertical						1,295					75	%	62	%
Horizontal						9					62	%	48	%
Haynesville Shale		57,502		38,224		197	—		—		81	%	65	%
Holly						116					77	%	62	%
Non-Holly						81					88	%	69	%

Total Operating Areas		647,479		476,876		5,673	273		20.8		90	%	69	%

(1)

Our inventory as of December 31, 2014 does not include the following potential additional locations:

•: In the Wolfcamp Shale area, (i) horizontal drilling locations in the Cline Shale and (ii) vertical drilling locations in the Spraberry and other stacked formations; and
•: In Altamont, (i) additional vertical infill locations and (ii) horizontal drilling locations in the Wasatch and Green River formations.

(2)

Represents gross operated wells completed in 2014.

(3)

Calculated as Drilling Locations divided by 2014 Drilling Locations. At 2015 activity levels, inventory is approximately 30 years.

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Business Strategy

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

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

We have assembled a drilling inventory of 5,673 drilling locations, (including 979 drilling locations to which we have attributed proved undeveloped reserves as of December 31, 2014, of which approximately 92% are oil wells) and across approximately 476,876 net (647,479 gross) acres in the Eagle Ford Shale, the Wolfcamp Shale, Altamont and the Haynesville Shale. The concentration and scale of our leasehold positions, coupled with our technical understanding of the reservoirs, should allow us to efficiently develop our operating areas and allocate capital to maximize the value of our resource base. In 2014, we invested $2.2 billion (99% in our oil areas) of capital expenditures and grew continuing oil production by 19,000 Bbls/d, or 51%, from an average of 36,000 Bbls/d in 2013 to an average of 55,000 Bbls/d in 2014. We also increased proved oil reserves by 29.3 MMBbls, or 10%, from 291.5 MMBbls at December 31, 2013 to 320.8 MMBbls at December 31, 2014. In 2015, we plan to invest approximately $1.2 billion to $1.25 billion of capital expenditures, allocated primarily to our oil programs. We believe that our extensive inventory of low-risk drilling locations, combined with our operating expertise, will enable us to continue to deliver production, cash flow and reserve growth and create value. We consider our inventory of drilling locations to be low-risk because they are in areas where we (and other producers) have extensive drilling and production experience and success.

Maintain an Extensive Low-Risk Drilling Inventory

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

Enhance Returns by Continuously Improving Capital and Operating Efficiencies

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

Identify and Develop Additional Drilling Opportunities in our Portfolio

Our existing asset base provides numerous opportunities for our highly experienced technical team to create value by increasing our inventory beyond our currently identified drilling locations. In the Permian Basin, we have evaluated multiple Wolfcamp horizons, and have drilled at the locations of our

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initial results in the Wolfcamp A horizon. Additionally, this acreage is prospective for the Cline Shale, the Spraberry and other stacked formations. We believe Altamont has a significant inventory of low-risk, vertical infill drilling locations. Altamont is also currently being assessed for 80-acre vertical infill programs in the Wasatch and Green River formations and additional horizontal development potential in multiple shale and tight sands intervals. Our 3-D seismic programs in the Uinta and Permian Basins should further enhance our ability to increase the number of and high grade our drilling locations.

Maintain Liquidity and Financial Flexibility

We intend to fund our organic growth predominantly with internally generated cash flows while maintaining ample liquidity. We will continue to maintain a disciplined approach to spending whereby we allocate capital in order to optimize returns and create value. As of March 31, 2015, after giving effect to the Refinancing Transactions (as defined herein), we had approximately $1.7 billion available to borrow under the RBL facility (after giving effect to issued and undrawn letters of credit). As we pursue our strategy of developing high-return opportunities in our operating areas, we expect our cash flow and borrowing base to grow, thereby further enhancing our liquidity and financial strength.

Competitive Strengths

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

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

We own and operate contiguous leasehold positions in the core areas of three of the premier North American oil resource plays: the Eagle Ford Shale, the Wolfcamp Shale and Altamont. We have approximately 438,651 net (589,977 gross) acres across these three plays that we have substantially de-risked through our ongoing drilling programs. We view this acreage as de-risked because the drilling locations were selected based on our extensive delineation drilling and production history in the area and well-established industry activity surrounding our acreage. Based on our analysis of subsurface data and the production history of our wells and those of offset operators, we have confirmed high quality reservoir characteristics across a broad aerial extent with significant hydrocarbon resources in place. Based upon our well costs and production rates, we believe our oil areas offer some of the best single well rates of return of all North American resource plays.

Multi-Year Inventory of Low-Risk Drilling Opportunities

Our approximately 5,670 low-risk drilling locations across our operating areas provide us with approximately 21 years of drilling inventory (more than 30 years of drilling inventory at 2015 activity levels), of which 92% are oil wells. We have used the subsurface data from our development programs to identify and prioritize our inventory. These drilling locations are included in our inventory after they have passed through a rigorous technical evaluation. In addition to our approximately 5,670 identified drilling locations, we believe we have the potential to increase our multi-year drilling inventory with horizontal drilling locations in the Cline Shale and vertical drilling locations in the Spraberry and other stacked formations in the Permian Basin, and vertical infill and horizontal drilling locations in the Wasatch and Green River formations in Altamont. Our ongoing technical assessment and development activities provide the potential for identification of additional drilling opportunities on our properties.

High-Quality Proved Reserve Base with Substantial Current Production

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was 59% oil and 70% liquids. Our current production provides a stable source of cash flow to fund the development of our operating areas. This significantly reduces our reliance on outside sources of capital. In addition, our extensive inventory improves our ability to replace and grow proved reserves.

Significant Operational Control with Low Cost Operations

Our significant operational control permits us to efficiently manage the amount and timing of our capital outflows, allowing us to continually improve our drilling and operating practices. We operate over 85% of our producing wells and have operational control of approximately 97% of our drilling inventory as of December 31, 2014. We employ a centralized drilling and completion structure to accelerate our internal knowledge transfer around the execution of our drilling and completion programs.

Capital Allocation Flexibility and Scale across Multiple Basins

Our existing assets are geographically diversified among many of the major basins of North America, which helps to insulate us from regional commodity pricing and cost dislocations that occur from time to time. While our existing producing assets are well diversified, they are also of a critical mass which enables us to drive efficiencies and benefit from economies of scale across multiple basins. Furthermore, because of our centralized operational structure, we are able to quickly transfer operational efficiencies from one project to the next. From this deep operational knowledge base and sizeable, concentrated positions in multiple basins, we have the flexibility to allocate significant amounts of capital across our properties in an efficient and value-maximizing manner.

Ability to Direct Capital to the Prolific Haynesville Shale

The Haynesville Shale is a key asset for us and is likely to compete for development capital if natural gas prices improve. Because our operations are surrounded by existing infrastructure, future returns are primarily driven by drilling and completion costs and natural gas prices. Since our Haynesville wells have demonstrated high initial production rates and strong EURs, small movements in natural gas prices can drive significant incremental value creation. Since these leases are held-by-production, we have the ability to redirect capital to this prolific asset and have allocated a portion of our capital budget in 2015 to our Haynesville drilling program based on its returns in the forecasted commodity price environment.

Significant Liquidity and Financial Flexibility

As of March 31, 2015, after giving effect to the Refinancing Transactions, we had approximately $1.7 billion available to borrow under the RBL facility (after giving effect to issued and undrawn letters of credit). We maintain a robust hedging program in order to protect our cash flows through commodity cycles. Based on our hedges in place as of March 31, 2015, we were approximately 96% hedged (based on the midpoint of our 2015 production guidance) at a weighted average price of $91.16 per barrel for the remainder of 2015. We have (i) fixed price swaps on approximately 96% of and 82% of our oil production, at weighted average floor prices of $91.16 and $80.29 in 2015 and 2016, respectively (based on the midpoint of 2015 production guidance) and (ii) hedged basis risk on approximately 50% of our year-to-date Eagle Ford oil production. After giving effect to the Refinancing Transactions (as defined below), we expect that liquidity provided by operating cash flow, availability under the RBL Facility and available cash will give us the financial flexibility to pursue our planned capital expenditures in 2015 and for the foreseeable future.

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Experienced Management Team

With an average of 25 years of experience, our senior management team has built a track record at El Paso Corporation and in former leadership roles with Burlington Resources, ConocoPhillips and other leading energy companies. The majority of our senior management team has worked together for over a decade and has significant experience in identifying, acquiring and developing unconventional oil and natural gas assets, including experience in horizontal drilling and developing shales. Through a combination of invested equity and incentive programs, we believe our management is motivated to deliver high returns, create value and maintain safe and reliable operations.

2015 Capital Budget

For 2015, we expect our total capital budget will be approximately $1.2 billion to $1.25 billion. Our capital program will remain focused on continuing to grow production, cash flows, and reserves in our highest return oil programs. In particular, the Eagle Ford Shale currently generates the highest returns in our portfolio and, as a result we are investing the majority of our capital in this program. We expect that liquidity provided by operating cash flow, availability under the RBL Facility and available cash will be sufficient to fund the 2015 capital plan.

Our 2015 capital expenditures of approximately $1.2 billion to $1.25 billion are allocated primarily to our oil programs: $825 million to Eagle Ford, $190 million to Wolfcamp, $140 million to Altamont and $100 million to Haynesville. We expect well completions between 160-190. For the year ended December 31, 2014, our capital expenditures were approximately $2.2 billion (including approximately $158 million of acquisition capital), and we completed 273 gross wells.

Recent Events

Refinancing Transaction

On May 28, 2015, the Issuers completed the offering of $800 million aggregate principal amount of the initial notes to qualified institutional buyers pursuant to Rule 144A under the Securities Act, and to persons outside of the United States in compliance with Regulation S under the Securities Act. We used the net proceeds from the offering of the initial notes (i) to fund a tender offer (the "Tender Offer") for any and all of our outstanding 6.875% Senior Secured Notes due 2019 Notes (the "2019 Notes"), (ii) to redeem any of our 2019 Notes that remained outstanding upon completion of the Tender Offer, (iii) to repay indebtedness under the RBL Facility, (iv) to pay related fees and expenses and (v) for other general corporate purposes. See "Use of Proceeds" for more information regarding our use of proceeds from the offering of the initial notes.

As used in this prospectus, the term "Refinancing Transactions" refers collectively to the offering of the initial notes and the use of the net proceeds therefrom as described above.

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Corporate Structure

The diagram below sets forth a simplified version of our current organizational structure and our principal indebtedness as of March 31, 2015 after giving effect to the Refinancing Transactions. The diagram is provided for illustrative purposes only and does not represent all legal entities affiliated with, or all obligations of the Issuer and their subsidiaries.

(1): EPE Acquisition, LLC ("EPE Acquisition") has made a non-recourse pledge of the equity of the Issuer to secure the RBL Facility.
(2): As of March 31, 2015, approximately $980 million was drawn and outstanding under the RBL Facility. See "Capitalization" and "Description of Other Indebtedness" for more information regarding borrowings, borrowing base and availability under the RBL Facility.
(3): All operating subsidiaries of the Issuer guarantee and pledge certain assets under the RBL Facility and the senior secured term loans. These subsidiaries also guarantee our existing senior notes on a senior unsecured basis and will guarantee these notes.

Our Sponsors

Apollo Global Management, LLC (together with its subsidiaries, "Apollo"), founded in 1990, is a leading global alternative investment manager with offices in New York, Los Angeles, Houston, Chicago, London, Frankfurt, Luxembourg, Singapore, Mumbai, Hong Kong, Bethesda, Madrid, Delhi and Shanghai. As of March 31, 2015, Apollo had assets under management of approximately $163 billion in private equity, credit and real estate funds invested across a core group of nine industries, including natural resources, where Apollo has considerable knowledge and resources.

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Apollo's team of more than 300 seasoned investment professionals possesses a broad range of transactional, financial, managerial and investment skills, which has enabled the firm to deliver strong long-term investment performance throughout expansionary and recessionary economic cycles.

Riverstone Holdings LLC (together with its affiliates, "Riverstone"), founded in 2000, is an energy and power-focused private equity firm with approximately $30 billion of equity capital raised across seven investment funds and co-investments as of March 31, 2015. Riverstone conducts buyout and growth capital investments in the midstream, exploration & production, oilfield services, power and renewable sectors of the energy industry. With offices in New York, London and Houston, the firm has committed approximately $29 billion to 110 investments in North America, Latin America, Europe, Africa and Asia as of March 31, 2015.

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

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

Corporate Information

Our principal executive offices are located at 1001 Louisiana Street, Houston, Texas 77002. Our telephone number is (713) 997-1000. Our website address is www.epenergy.com. Information on our website or any other website is not incorporated by reference herein and does not constitute a part of this prospectus.

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SUMMARY OF THE EXCHANGE OFFER


Exchange Offer		We are offering to exchange up to $800,000,000 aggregate principal amount of our exchange notes for a like aggregate principal amount of our initial notes.
		In order to exchange your initial notes, you must properly tender them and we must accept your tender. We will exchange all outstanding initial notes that are validly tendered and not validly withdrawn. Initial notes may be exchanged only for a minimum principal denomination of $2,000 and in integral multiples of $1,000 in excess thereof.
Expiration Date		This exchange offer will expire at 5:00 p.m., New York City time, on August 4, 2015, unless we decide to extend it. We do not currently intend to extend the expiration date.
Exchange Notes		The exchange notes will be identical in all material respects to the initial notes except that:
		• the exchange notes have been registered under the Securities Act and will be freely tradable by persons who are not affiliated with us;
		• the exchange notes are not entitled to the registration rights applicable to the initial notes under the registration rights agreement; and
		• our obligation to pay additional interest on the initial notes due to the failure to consummate the exchange offer by a prior date does not apply to the exchange notes.
Conditions to the Exchange Offer		The exchange offer is subject to customary conditions, some of which we may waive, that include the following conditions:
		• there is no change in the laws and regulations which would impair our ability to proceed with this exchange offer,
		• there is no change in the current interpretation of the staff of the SEC permitting resales of the exchange notes, and
		• there is no stop order issued by the SEC which would suspend the effectiveness of the registration statement which includes this prospectus or the qualification of the exchange notes under the Trust Indenture Act of 1939.
		Please refer to the section in this prospectus entitled "The Exchange Offer—Conditions to the Exchange Offer."

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Procedures for Tendering Initial Notes		To participate in this exchange offer, you must complete, sign and date the letter of transmittal or its facsimile and transmit it, together with your initial notes to be exchanged and all other documents required by the letter of transmittal, to Wilmington Trust, National Association, as exchange agent, at its address indicated under "The Exchange Offer—Exchange Agent." In the alternative, you can tender your initial notes by book-entry delivery following the procedures described in this prospectus. For more information on tendering your initial notes, please refer to the section in this prospectus entitled "The Exchange Offer—Procedures for Tendering Initial Notes."
Special Procedures for Beneficial Owners		If you are a beneficial owner of initial notes that are registered in the name of a broker, dealer, commercial bank, trust company or other nominee and you wish to tender your initial notes in the exchange offer, you should contact the registered holder promptly and instruct that person to tender on your behalf.
Guaranteed Delivery Procedures		If you wish to tender your initial notes and you cannot get the required documents to the exchange agent on time, you may tender your initial notes by using the guaranteed delivery procedures described under the section of this prospectus entitled "The Exchange Offer—Procedures for Tendering Initial Notes—Guaranteed Delivery Procedure."
Withdrawal Rights		You may withdraw the tender of your initial notes at any time before 5:00 p.m., New York City time, on the expiration date of the exchange offer. To withdraw, you must send a written or facsimile transmission notice of withdrawal to the exchange agent at its address indicated under "The Exchange Offer—Exchange Agent" before 5:00 p.m., New York City time, on the expiration date of the exchange offer.
Acceptance of Initial Notes and Delivery of Exchange Notes		If all the conditions to the completion of this exchange offer are satisfied, we will accept any and all initial notes that are properly tendered in this exchange offer on or before 5:00 p.m., New York City time, on the expiration date. We will return any initial note that we do not accept for exchange to you without expense promptly after the expiration date. We will deliver the exchange notes to you promptly after the expiration date and acceptance of your initial notes for exchange. Please refer to the section in this prospectus entitled "The Exchange Offer—Acceptance of Initial Notes for Exchange; Delivery of Exchange Notes."

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Federal Income Tax Considerations Relating to the Exchange Offer		Exchanging your initial notes for exchange notes will not be a taxable event to you for United States federal income tax purposes. Please refer to the section of this prospectus entitled "Certain U.S. Federal Income Tax Considerations."
Exchange Agent		Wilmington Trust, National Association is serving as exchange agent in the exchange offer.
Fees and Expenses		We will pay all expenses related to this exchange offer. Please refer to the section of this prospectus entitled "The Exchange Offer—Fees and Expenses."
Use of Proceeds		We will not receive any proceeds from the issuance of the exchange notes. We are making this exchange offer solely to satisfy certain of our obligations under our registration rights agreement entered into in connection with the offering of the initial notes.
Consequences to Holders Who Do Not Participate in the Exchange Offer		If you do not participate in this exchange offer:
		• except as set forth in the next paragraph, you will not necessarily be able to require us to register your initial notes under the Securities Act,
		• you will not be able to resell, offer to resell or otherwise transfer your initial notes unless they are registered under the Securities Act or unless you resell, offer to resell or otherwise transfer them under an exemption from the registration requirements of, or in a transaction not subject to, the Securities Act, and
		• the trading market for your initial notes will become more limited to the extent other holders of initial notes participate in the exchange offer.
		You will not be able to require us to register your initial notes under the Securities Act unless:
		• the initial purchasers request us to register initial notes that are not eligible to be exchanged for exchange notes in the exchange offer; or
		• you are not eligible to participate in the exchange offer; or
		• you may not resell the exchange notes you acquire in the exchange offer to the public without delivering a prospectus and the prospectus contained in the exchange offer registration statement is not appropriate or available for such resales by you; or
		• you are a broker-dealer and hold initial notes that are part of an unsold allotment from the original sale of the initial notes.

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		In these cases, the registration rights agreement requires us to file a registration statement for a continuous offering in accordance with Rule 415 under the Securities Act for the benefit of the holders of the initial notes described in this paragraph. We do not currently anticipate that we will register under the Securities Act any initial notes that remain outstanding after completion of the exchange offer.
		Please refer to the section of this prospectus entitled "Risk Factors—Risks Related to the Exchange Offer."
Resales		It may be possible for you to resell the notes issued in the exchange offer without compliance with the registration and prospectus delivery provisions of the Securities Act, subject to the conditions described under "—Obligations of Broker-Dealers" below.
		To tender your initial notes in this exchange offer and resell the exchange notes without compliance with the registration and prospectus delivery requirements of the Securities Act, you must make the following representations:
		• you are authorized to tender the initial notes and to acquire exchange notes, and that we will acquire good and unencumbered title thereto,
		• the exchange notes acquired by you are being acquired in the ordinary course of business,
		• you have no arrangement or understanding with any person to participate in a distribution of the exchange notes (within the meaning of the Securities Act) and are not participating in, and do not intend to participate in, the distribution of such exchange notes,
		• you are not an "affiliate" (as defined in Rule 405 under the Securities Act) of ours, or if you are an "affiliate", you will comply with the registration and prospectus delivery requirements of the Securities Act to the extent applicable,
		• if you are not a broker-dealer, you are not engaging in, and do not intend to engage in, a distribution of exchange notes, and
		• if you are a broker-dealer, and initial notes to be exchanged were acquired by you as a result of market-making or other trading activities, you will deliver a prospectus in connection with any resale, offer to resell or other transfer of such exchange notes.

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		Please refer to the sections of this prospectus entitled "The Exchange Offer—Procedure for Tendering Initial Notes—Proper Execution and Delivery of Letters of Transmittal," "Risk Factors—Risks Related to the Exchange Offer—Some persons who participate in the exchange offer must deliver a prospectus in connection with resales of the exchange notes" and "Plan of Distribution."
Obligations of Broker-Dealers		If you are a broker-dealer (1) that receives exchange notes, you must acknowledge that you will deliver a prospectus meeting the requirements of the Securities Act in connection with any resales of the exchange notes, (2) who acquired the initial notes as a result of market-making or other trading activities, you may use the exchange offer prospectus as supplemented or amended, in connection with resales of the exchange notes, or (3) who acquired the initial notes directly from us in the initial offering and not as a result of market-making and trading activities, you must, in the absence of an exemption, comply with the registration and prospectus delivery requirements of the Securities Act in connection with resales of the exchange notes.

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SUMMARY OF TERMS OF THE EXCHANGE NOTES

The summary below describes the principal terms of the exchange notes. Certain of the terms and conditions described below are subject to important limitations and exceptions. The "Description of Exchange Notes" section of this prospectus contains a more detailed description of the terms and conditions of the exchange notes.


Issuers		EP Energy LLC and Everest Acquisition Finance Inc.
Notes Offered		$800,000,000 aggregate principal amount of 6.375% Senior Notes due 2023. The forms and terms of the exchange notes are the same as the form and terms of the initial notes except that the issuance of the exchange notes is registered under the Securities Act, the exchange notes will not bear legends restricting their transfer and the exchange notes will not be entitled to registration rights under our registration rights agreement. The exchange notes will evidence the same debt as the initial notes, and both the initial notes and the exchange notes will be governed by the same indenture.
Maturity Date		June 15, 2023.
Interest Rate		Interest on the exchange notes will accrue from May 28, 2015 at a rate of 6.375% per annum and will be payable in cash.
Interest Payment Dates		June 15 and December 15 of each year, commencing December 15, 2015.
Denominations		Minimum denominations of $2,000 and integral multiples of $1,000 in excess thereof; provided that notes may be issued in denominations of less than $2,000 solely to accommodate book-entry positions that have been created by a DTC participant in denominations of less than $2,000.
Guarantees		Our obligations under the exchange notes will be fully and unconditionally guaranteed, jointly and severally, by the Issuers' present and future direct or indirect wholly owned material domestic subsidiaries that guarantee the RBL Facility.
Ranking		The exchange notes will be our senior unsecured obligations and will:
		• rank equally in right of payment to all of our existing and future senior debt and other obligations that are not, by their terms, expressly subordinated in right of payment to the notes;
		• be senior in right of payment to all of our existing and future debt and other obligations that are, by their terms, expressly subordinated in right of payment to the notes;
		• be effectively subordinated to all of our existing and future secured debt (including obligations under our RBL Facility and senior secured term loans), to the extent of the value of the assets securing such indebtedness; and

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		• be structurally subordinated to all obligations of each of our subsidiaries that is not a guarantor of the notes.
		As of March 31, 2015, on a pro forma basis after giving effect to the Refinancing Transactions, the notes would have ranked (1) effectively junior to $1,617 million of senior secured indebtedness, consisting of indebtedness outstanding under our RBL Facility, but excluding issued and undrawn letters of credit, and senior secured term loans and (2) equally to $2,350 million of senior unsecured indebtedness represented by our existing senior notes. Further, we would have had approximately $1.7 billion available (after giving effect to issued and undrawn letters of credit) for additional borrowing under the RBL Facility, all of which would be secured.
Optional Redemption		Prior to June 15, 2018, we may redeem some or all of the exchange notes at a redemption price equal to 100% of the principal amount of the exchange notes plus accrued and unpaid interest and additional interest, if any, to (but not including) the applicable redemption date plus the applicable "make-whole" premium. On or after June 15, 2018, we may redeem some or all of the exchange notes at the redemption prices set forth in this prospectus plus accrued and unpaid interest and additional interest, if any. Additionally, on or prior to June 15, 2018, we may redeem up to 35% of the aggregate principal amount of the exchange notes with the net proceeds of specified equity offerings at the redemption price set forth in this prospectus plus accrued and unpaid interest and additional interest, if any up to (but not including) the applicable redemption date. See "Description of Exchange Notes—Optional Redemption."
Certain Covenants		The indenture governing the exchange notes, among other things, limits our ability and the ability of our restricted subsidiaries to:
		• incur or guarantee additional indebtedness;
		• pay dividends or distributions on, or redeem or repurchase, capital stock and make other restricted payments;
		• make investments;
		• consummate certain asset sales;
		• engage in transactions with affiliates;
		• grant or assume liens; and
		• consolidate, merge or transfer all or substantially all of our assets.

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		These limitations are subject to a number of important qualifications and exceptions as described under "Description of Exchange Notes—Certain Covenants." Certain covenants will cease to apply to the notes during such time that the notes are rated investment grade by Moody's and S&P; provided that no default has occurred and is continuing. EP Energy Corporation, the indirect parent of the Issuers ("Parent"), will not be subject to any of the covenants in the indenture governing the notes.
Form of the Exchange Notes		The exchange notes will be represented by one or more permanent global securities in registered form deposited on behalf of The Depository Trust Company ("DTC") with Wilmington Trust, National Association, as custodian. You will not receive exchange notes in certificated form unless one of the events described in the section of this prospectus entitled "Book-Entry; Delivery and Form" occurs. Instead, beneficial interests in the exchange notes will be shown on, and transfers of these exchange notes will be effected only through, records maintained in book-entry form by DTC with respect to its participants.
Absence of a Public Market for the Exchange Notes		The exchange notes are new securities for which there is no established market. We cannot assure you that a market for these exchange notes will develop or that this market will be liquid. Please refer to the section of this prospectus entitled "Risk Factors—Risks Related to the Exchange Offer—There is no active trading market for the exchange notes."
Use of Proceeds		We will not receive any proceeds from the issuance of the exchange notes in exchange for the outstanding initial notes. We are making this exchange solely to satisfy our obligations under the registration rights agreement entered into in connection with the offering of the initial notes. See "Use of Proceeds"
Risk Factors		You should consider all of the information contained in this prospectus before making an investment in the exchange notes. In particular, you should consider the risks described under "Risk Factors."

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Summary Historical Consolidated Financial Data

Set forth below is the summary historical consolidated financial data and other operating data for the periods and as of the dates indicated for EP Energy LLC. EP Energy LLC (the successor) was formed as a Delaware limited liability company on March 23, 2012 by the Sponsors. On April 24, 2012 we issued approximately $2.75 billion in private placement notes. Proceeds from these notes, along with other sources, were used by the Sponsors to acquire (the "Acquisition") EP Energy Global LLC (formerly known as EP Energy Corporation and EP Energy, L.L.C. after its conversion into a Delaware limited liability company) and subsidiaries for approximately $7.2 billion on May 24, 2012, from El Paso Corporation (El Paso) immediately prior to and in connection with its merger with Kinder Morgan, Inc. (KMI). Historical financial results of EP Energy LLC included elsewhere in this prospectus for the period before the Acquisition on May 24, 2012 are referred to as those of the predecessor and after the Acquisition are referred to as those of the successor in accordance with the required GAAP presentation. See "Management's Discussion and Analysis of Financial Condition and Results of Operations."

We have derived the summary historical consolidated balance sheet data as of December 31, 2014 and December 31, 2013, and the statements of income data and statements of cash flow data for the years ended December 31, 2014 and 2013 and for the period from March 23, 2012 to December 31, 2012 (successor) and the period from January 1, 2012 through May 24, 2012 (predecessor), from the audited consolidated financial statements of EP Energy LLC included elsewhere in this prospectus. The summary unaudited historical consolidated financial data as of and for the quarters ended March 31, 2015 and March 31, 2014 have been derived from the unaudited consolidated financial statements of EP Energy LLC included elsewhere in this prospectus, which have been prepared on a basis consistent with the audited consolidated financial statements. In the opinion of management, such unaudited financial data reflects all adjustments, consisting only of normal and recurring adjustments, necessary for a fair presentation of the results for such period. The results of operations for the interim periods are not necessarily indicative of the results to be expected for the full year or any future period.

All financial statement periods present our Brazilian operations as discontinued operations. Financial statement periods after May 24, 2012 (successor periods) also present certain domestic natural gas assets sold as discontinued operations.

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The following summary historical financial data should be read in conjunction with the information included under the headings "—Corporate Structure," "Use of Proceeds," "Capitalization" and the historical consolidated financial statements and related notes included elsewhere in this prospectus.

	EP Energy LLC


	Successor															Predecessor
	Successor															Predecessor
													March 23 (inception) to December 31, 2012
	Quarter ended March 31, 2015			Quarter ended March 31, 2014			Year ended December 31, 2014			Year ended December 31, 2013						January 1 to May 24, 2012


	(in millions)
Statement of income data							��
Operating revenues:
Oil	$	229		$	406		$	1,705		$	1,254		$	499		$	310
Natural gas		48			78			284			300			216			228
NGLs		13			27			110			74			28			29

Physical sales		290			511			2,099			1,628			743			567
Financial derivatives		203			(135	)		985			(52	)		(62	)		365

Total operating revenues		493			376			3,084			1,576			681			932

Operating expenses:
Natural gas purchases		7			3			23			25			19			—
Transportation costs		27			23			100			85			48			45
Lease operating expense		47			44			193			147			63			80
General and administrative		47			49			160			228			358			69
Depreciation, depletion and amortization		224			192			875			585			188			307
Impairments and ceiling test charges		—			—			2			2			1			62
Exploration and other expense		6			8			25			41			40			—
Taxes, other than income taxes		22			33			129			79			36			31

Total operating expenses		380			352			1,507			1,192			753			594

Operating income (loss)		113			24			1,577			384			(72	)		338
Other income (expense)		—			—			1			(12	)		(1	)		(3	)
Loss on extinguishment of debt		—			—			—			(9	)		(14	)		—
Interest expense, net of capitalized interest		(84	)		(77	)		(316	)		(321	)		(218	)		(14	)

Income (loss) from continuing operations before income taxes		29			(53	)		1,262			42			(305	)		321
Income tax expense		10			—			1,121			—			—			134

Income (loss) from continuing operations		19			(53	)		141			42			(305	)		187
Income (loss) from discontinued operations, net of tax		—			17			7			507			50			(9	)

Net income (loss)	$	19		$	(36	)	$	148		$	549		$	(255	)	$	178



Statement of cash flows data
Net cash provided by (used in):
Operating activities	$	270		$	307		$	1,295		$	975		$	449		$	580
Investing activities		(432	)		(442	)		(2,064	)		(475	)		(7,893	)		(628	)
Financing activities		148			166			742			(515	)		7,507			110
Other financial data
Capital expenditures(1)	$	415		$	474		$	2,203		$	1,925		$	932		$	619
Adjusted EBITDAX(2)		366			350			1,547			1,139			702			520
Pro forma Adjusted EBITDAX(2)		366			350			1,547			1,139			697			437
Cash interest expense		22			18			289			305			145			7

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	Successor

	As of March 31, 2015		As of March 31, 2014		As of December 31, 2014		As of December 31, 2013
	(in millions)
Balance sheet data
Cash and cash equivalents	$	7	$	79	$	21	$	48
Total assets		10,309		8,545		10,194		8,326
Long term total debt		4,726		4,020		4,598		4,039
Member's equity		3,826		3,608		3,782		3,455

(1): Represents accrual based capital expenditures, including acquisition capital, and excludes asset retirement costs.
(2): Adjusted EBITDAX and Pro Forma Adjusted EBITDAX are non-GAAP measures, and are not measurements of operating performance computed in accordance with GAAP and should not be considered as substitutes for operating income (loss), income (loss) from continuing operations, net income (loss) or cash flows provided by operating activities computed in accordance with GAAP. These measures may not be comparable to similarly titled measures of other companies. See "Management's Discussion and Analysis of Financial Condition and Results of Operations—Supplemental Non-GAAP Measures."

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



	Successor															Predecessor
	Successor															Predecessor
	Quarter ended March 31, 2015			Quarter ended March 31, 2014									March 23 (inception) to December 31, 2012
							Year ended December 31, 2014			Year ended December 31, 2013						January 1 to May 24, 2012


	(in millions)
Net income (loss)	$	19		$	(36	)	$	148		$	549		$	(255	)	$	178
(Income) loss from discontinued operations, net of tax		—			(17	)		(7	)		(507	)		(50	)		9

Income (loss) from continuing operations		19			(53	)		141			42			(305	)		187
Income tax expense		10			—			1,121			—			—			134
Interest expense, net of capitalized interest		84			77			316			321			218			14
Depreciation, depletion and amortization		224			192			875			585			188			307
Exploration expense(a)		5			8			22			41			40			—

EBITDAX		342			224			2,475			989			141			642
Mark-to-market on financial derivatives(b)		(203	)		135			(985	)		52			62			(365	)
Cash settlements and premiums on financial derivatives(c)		214			(25	)		44			10			217			165
Non-cash portion of compensation expense(d)		5			9			9			31			35			6
Transition, restructuring and other costs(e)		8			1			(4	)		7			144			5
Fees paid to Sponsors(f)		—			6			6			26			87			—
Loss on extinguishment of debt(g)		—			—			—			9			14			—
Loss from unconsolidated affiliate(h)		—			—			—			13			1			5
Impairment and ceiling test charges		—			—			2			2			1			62

Adjusted EBITDAX		366			350			1,547			1,139			702			520
Less: Adjusted EBITDAX—divested assets(i)		—			—			—			—			5			83

Pro Forma Adjusted EBITDAX	$	366		$	350		$	1,547		$	1,139		$	697		$	437

(a): Represents exploration expense only.
(b): Represents the income statement impact of financial derivatives.
(c): Represents actual cash settlements received/(paid) related to financial derivatives, including cash premiums. No cash premiums were received for the quarter ended March 31, 2015. For the quarter ended March 31, 2014, we received less than $1 million of cash premiums. For the year ended December 31, 2014 and 2013, we received approximately $1 million and $9 million of cash premiums, respectively, and for the period from March 23 to December 31, 2012 we paid $3 million of cash premiums.
(d): Represents non-cash compensation expense under long-term incentive programs adjusted for cash payments made under long-term incentive plans. For the quarters ended March 31, 2015 and 2014, cash payments were less than $1 million. For the years ended December 31, 2014 and 2013, cash payments were approximately $13 million and $10 million, respectively.

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(e): Reflects transition and severance costs related to restructuring activities for the quarters ended March 31, 2015 and 2014. Reflects an $11 million insurance settlement and $5 million of acquisition costs in 2014 as well as transition and severance costs related to restructuring for the year ended December 31, 2014, severance costs incurred in connection with divested assets in 2013 and transaction costs paid as part of the Acquisition in 2012.
(f): Represents management and other fees paid to the Sponsors.
(g): Represents the loss on extinguishment of debt recorded related to the redetermination of the RBL Facility and a partial repayment of the term loan in 2013 and the re-pricing of the term loan in 2012.
(h): Reflects the elimination of equity income (losses) recognized from Four Star, net of amortization of our purchase cost in excess of our equity interest in the underlying net assets, as a result of the sale of Four Star in September 2013.
(i): Consists of the Adjusted EBITDAX contributions related to assets that have been divested, including our (i) Arklatex and South Louisiana Wilcox areas, (ii) CBM, South Texas and Arklatex assets and (iii) Gulf of Mexico assets.

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Summary Pro Forma Operating and Reserve Information

Proved Reserves

The following table summarizes our estimated net proved reserves and related PV-10 and standardized measure of discounted future net cash flows as of December 31, 2014. The proved reserves as of December 31, 2014 are based on our internal reserve report. The reserve data represents only estimates, which are often different from the quantities of oil and natural gas that are ultimately recovered. The risks and uncertainties associated with estimating proved oil and natural gas reserves are discussed further in "Risk Factors." Net proved reserves exclude royalties and interests owned by others and reflect contractual arrangements and royalty obligations in effect at December 31, 2014. You should refer to the information included under the headings "Risk Factors," "Management's Discussion and Analysis of Financial Condition and Results of Operations" and "Business" appearing elsewhere in this prospectus in evaluating the material presented below. The information in the following table does not give any effect to or reflect our commodity hedges.

Ryder Scott conducted an audit of the estimates of the proved reserves that we prepared as of December 31, 2014 and concluded that the overall procedures and methodologies we utilized in preparing these estimates complied with current SEC regulations and the overall proved reserves for the reviewed properties as estimated by us are, in aggregate, reasonable within the established audit tolerance guidelines of 10% as set forth in the Society of Petroleum Engineers ("SPE") auditing standards.

	As of December 31, 2014

Proved reserves:
Natural gas (MMcf)		1,243,006
Oil (MBbls)		320,813
NGLs (MBbls)		94,226
Total estimated net proved reserves (MBoe)		622,206
Proved developed producing (MBoe)		222,950
Proved developed non-producing (MBoe)		15,190
Proved undeveloped (MBoe)		384,067
Percent proved developed reserves (%)		38	%
PV-10 (in millions)(1)	$	9,376
Standardized measure (in millions)	$	6,898

(1): PV-10 is a non-GAAP measure and is derived from the standardized measure of discounted future net cash flows, which is the most directly comparable GAAP financial measure. Our PV-10 differs from our standardized measure because our standardized measure reflects discounted future income taxes related to our domestic operations. We believe that the presentation of PV-10 is relevant and useful to investors because it presents the relative monetary significance of our oil, natural gas and NGLs properties regardless of tax structure. Further, investors may utilize the measure as a basis for comparison of the relative size and value of our reserves to other companies. We use this measure when assessing the potential return on investment related to our oil, natural gas and NGLs properties. PV-10, however, is not a substitute for the standardized measure of discounted future net cash flows. Our PV-10 measure and the standardized measure of discounted future net cash flows do not purport to present the fair value of our oil (including NGLs) and natural gas reserves. The unweighted arithmetic average of the historical first-day-of-the-month prices for the prior 12 months was $94.99 per barrel of oil (WTI) and $4.34 per MMBtu of natural gas (Henry Hub) as of December 31, 2014.

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

	As of December 31, 2014

PV-10	$	9,376
Less: Income taxes, discounted at 10%		2,478

Standardized measure of discounted future net cash flows	$	6,898

Production, Revenues and Price History

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

	Quarter ended March 31, 2015		Quarter ended March 31, 2014		Year ended December 31, 2014		Year ended December 31, 2013(1)			Year ended December 31, 2012(1)

Production data:
Oil (MBbls)		5,402		4,373		19,985		13,235			8,301
Natural gas (MMcf)		16,628		17,699		69,434		83,816			124,711
NGLs (MBbls)		1,044		843		4,116		2,434			1,098

Combined production (MBoe)		9,218		8,166		35,673		29,638			30,185



Average combined daily production (MBoe/d)		102.4		90.7		97.7		81.2			82.5



Average realized prices on physical sales:
Oil (Bbl)	$	42.40	$	92.83	$	85.31	$	94.75		$	93.49
Natural gas (Mcf)	$	2.51	$	4.21	$	3.76	$	3.28		$	2.48
NGLs (Bbl)	$	12.04	$	32.29	$	26.73	$	30.58		$	40.22
Average realized prices, including financial derivative settlements(2):
Oil (Bbl)	$	78.39	$	91.20	$	88.77	$	97.56		$	98.48
Natural gas (Mcf)	$	3.69	$	3.26	$	3.34	$	2.97		$	5.20
NGLs (Bbl)	$	12.26	$	31.40	$	27.78	$	—		$	—
Average cash operating costs ($/Boe)(3):
Lease operating expenses	$	5.12	$	5.42	$	5.40	$	4.98		$	3.48
Production taxes(4)		2.13		3.72		3.39		2.84			2.05
General and administrative expenses		5.06		5.97		4.47		7.68			14.03
Taxes other than production and income taxes		0.28		0.28		0.23		(0.18	)		(0.11	)
Other expense(5)		0.20		—		0.09		—			—

Total	$	12.79	$	15.39	$	13.58	$	15.32		$	19.45



Depreciation, depletion and amortization ($/Boe)	$	24.30	$	23.47	$	24.53	$	19.74		$	12.50

(1): The years ended 2013 and 2012 do not include volumes from our approximate 49% equity interest in the volumes of Four Star Oil & Gas Company (Four Star), which we sold in September 2013. The year ended December 31, 2012 does not include volumes from our South Louisiana Wilcox and Arklatex Tight Gas areas sold in 2014, our CBM, South Texas, and the majority of our Arklatex assets, all of which were sold in 2013, and our Gulf of Mexico assets, which were sold in 2012. For periods after May 24, 2012, our South Louisiana Wilcox, CBM, South Texas and Arklatex assets are treated as

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discontinued operations and accordingly volumes related to those assets are excluded from all financial and non-financial metrics.

(2): Amounts reflect settlements on derivative instruments, including cash premiums. No cash premiums were received for the quarter ended March 31, 2015. Cash premiums received for the quarter ended March 31, 2014 were less than $1 million. For the year ended December 31, 2014 we received cash premiums of approximately $1 million, for the year ended December 31, 2013 we received cash premiums of $9 million and for the year ended December 31, 2012 we paid $3 million of cash premiums.
(3): Total adjusted cash operating costs per unit for each period were $11.41/Boe, $13.45/Boe, $13.26/Boe, $13.17/Boe and $10.26/Boe. Adjusted cash operating cost is a non-GAAP measure. See "Management's Discussion and Analysis of Financial Condition and Results of Operations—Results of Operations—Cash Operating Costs and Adjusted Cash Operating Costs" included elsewhere in this prospectus for a reconciliation of this measure to operating expenses, the most directly comparable GAAP measure.
(4): Production taxes include ad valorem and severance taxes.
(5): Recorded in conjunction with early rig termination fees.

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RISK FACTORS

Investing in the exchange notes in this exchange offer involves a high degree of risk. You should carefully consider the risk factors set forth below, as well as the other information contained in this prospectus, before participating in the exchange offer. Any of the following risks could materially and adversely affect our business, financial condition or results of operations. In any such case, you may lose all or a part of your original investment in the notes.

Risks Related to Our Business and Industry

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

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

•: the oversupply of oil, natural gas and/or NGLs;
•: adverse changes in geopolitical factors, including the ability of the Organization of Petroleum Exporting Countries (OPEC) to agree upon and maintain certain production levels, political unrest and changes in foreign governments in energy producing regions of the world and unexpected wars, terrorist activities and other acts of aggression;
•: adverse changes in global, geopolitical and economic conditions, including changes that negatively impact general demand for oil and its refined products; power generation and industrial loads for natural gas; and petrochemical, refining and heating demand for NGLs;
•: perceptions of customers on the availability and price volatility of our products, particularly customers' perceptions on the volatility of oil and natural gas prices over the longer term;
•: increased prices of oil, natural gas or NGLs that could negatively impact the demand for these products;
•: adverse changes in domestic regulations that could impact the supply or demand for oil, natural gas and NGLs, including potential restrictive regulations associated with hydraulic fracturing operations;
•: increased costs to explore for, develop and produce oil, natural gas or NGLs, including increases in oil field service costs;
•: technological advancements that may drive further increases in production from oil and natural gas shales;
•: the need of many producers to drill to maintain leasehold positions regardless of current commodity prices;
•: the relative growth of natural gas-fired power generation, including the speed and level of existing coal-fired generation that is replaced by natural gas-fired generation, which could be offset by the growth of various renewable energy sources;
•: adoption of various energy efficiency and conservation measures;
•: the impact of weather on demand for oil, natural gas and/or NGLs; and
•: competition from imported and potentially exported liquefied natural gas (LNG), Canadian supplies and alternate fuels.

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

Our success depends upon the prices we receive for our oil, natural gas and NGLs. These commodity prices historically have been highly volatile and are likely to continue to be volatile in the future, especially given current global geopolitical and economic conditions. During the second half of 2014, NYMEX-WTI oil prices fell from in excess of $100 per Bbl to below $50 per Bbl, the lowest price since 2009. There is a risk that commodity prices could remain depressed for sustained periods. Except to the extent of our risk mitigation and hedging strategies, we can be impacted by short-term changes in commodity prices. We would also be negatively impacted in the long-term by any sustained depression in prices for oil, natural gas or NGLs, including reductions in our drilling opportunities. The prices for oil, natural gas and NGLs are subject to a variety of additional factors that are outside of our control, which include, among others:

•: changes in regional, domestic and international supply of, and demand for, oil, natural gas and NGLs;
•: natural gas inventory levels in the United States;
•: political and economic conditions domestically and in other oil and natural gas producing countries, including, among others, countries in the Middle East, Africa and South America;
•: actions of OPEC and other state-controlled oil companies relating to oil price and production controls;
•: volatile trading patterns in capital and commodity-futures markets;
•: changes in the costs of exploring for, developing, producing, transporting, processing and marketing oil, natural gas and NGLs;
•: weather conditions and weather patterns;
•: technological advances affecting energy consumption and energy supply;
•: domestic governmental regulations and taxes, including administrative and/or agency actions;
•: availability, proximity and cost of commodity processing, gathering and transportation and refining capacity;
•: the price and availability of supplies of alternative energy sources;
•: the effect of LNG deliveries to or the ability to export LNG from the United States;
•: the strengthening and weakening of the U.S. dollar relative to other currencies; and
•: variations between product prices at sales points and applicable index prices.

In addition to negatively impacting our cash flows, prolonged or substantial declines in commodity prices could negatively impact our proved oil and natural gas reserves and impact the amount of oil and natural gas that we can produce economically in the future. A decrease in production could result in a shortfall in our expected cash flows and require us to reduce our capital spending or borrow funds to cover any such shortfall. Prices also affect our cash flow available for capital expenditures and our ability to access funds under our reserve-based revolving credit facility (the RBL Facility) and through the capital markets. The amount available for borrowing under the RBL Facility is subject to a borrowing base, which is determined by our lenders taking into account our proved reserves, and is subject to periodic redeterminations based on pricing models determined by the lenders at such time. Declines in oil, natural gas and NGLs prices may adversely impact the value of our proved reserves and, in turn, the bank pricing used by our lenders to determine our borrowing base. Any of these

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factors could negatively impact our liquidity, our ability to replace our production and our future rate of growth. On the other hand, increases in these commodity prices may be offset by increases in drilling costs, production taxes and lease operating costs that typically result from any increase in such commodity prices. Any of these outcomes could have a material adverse effect on our business, results of operations and financial condition.

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

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

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

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

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

•: unexpected drilling conditions;

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•: delays imposed by or resulting from compliance with regulatory and contractual requirements;
•: unexpected pressure or irregularities in geological formations;
•: equipment failures or accidents;
•: fracture stimulation accidents or failures;
•: adverse weather conditions;
•: declines in oil and natural gas prices;
•: surface access restrictions with respect to drilling or laying pipelines;
•: shortages (or increases in costs) of water used in hydraulic fracturing, especially in arid regions or regions that have been experiencing severe drought conditions;
•: shortages or delays in the availability of, increases in the cost of, or increased competition for, drilling rigs and crews, fracture stimulation crews, equipment, pipe, chemicals and supplies and transportation, gathering, processing, treating or other midstream services; and
•: limitations or reductions in the market for oil and natural gas.

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

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

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

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

The derivative contracts we enter into to mitigate commodity price risk are not designated as accounting hedges and are therefore marked to market. As a result, we still experience volatility in our revenues and net income 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

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increase above the fixed price. In addition, these hedging arrangements also expose us to the risk of financial loss in the following circumstances, among others:

•: when production is less than expected or less than we have hedged;
•: when the counterparty to the hedging instrument defaults on its contractual obligations;
•: when there is an increase in the differential between the underlying price in the hedging instrument and actual prices received; and
•: when there are issues with respect to legal enforceability of such instruments.

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

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

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

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

A rule adopted under the Dodd-Frank Act imposing position limits in respect of transactions involving certain commodities, including oil and natural gas was vacated and remanded to the CFTC for further proceedings by order of the United States District Court for the District of Columbia, U.S. District Judge Robert L. Wilkins on September 28, 2012. The CFTC appealed this decision and on November 5, 2013, filed a consensual motion to dismiss its appeal. The same day, the CFTC proposed

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a new position limits rule which would limit trading in New York Mercantile Exchange (NYMEX) contracts for Henry Hub Natural Gas, Light Sweet Crude Oil, New York Harbor Ultra-Low Sulfur No. 2 Diesel and Reformulated Blendstock for Oxygen Blending Gasoline and other futures and swap contracts that are economically equivalent to such NYMEX contracts. Comments on the proposed rule were due on March 30, 2015. We cannot predict whether or when the proposed rule will be adopted or the effect of the proposed rule on our business. The Dodd-Frank Act and the rules promulgated thereunder could significantly increase the cost of derivative contracts (including through requirements to post collateral), materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks we encounter, reduce our ability to monetize or restructure our existing derivative contracts, and increase our exposure to less creditworthy counterparties. Finally, the Dodd-Frank Act was intended, in part, to reduce the volatility of oil and natural gas prices, which some legislators attributed to speculative trading in derivatives and commodity contracts related to oil and natural gas. Our revenues could therefore be adversely affected if a consequence of the Dodd-Frank Act and regulations is to lower commodity prices. Any of these consequences could have a material and adverse effect on our business, financial condition and results of operations.

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

We require substantial capital expenditures to conduct our exploration, development and production operations, engage in acquisition activities and increase our proved reserves and production. In 2014, we spent total capital including acquisitions of $2.2 billion. We have established a capital budget for 2015 of approximately $1.2 billion to $1.25 billion and we intend to rely on cash flow from operating activities, available cash and borrowings under the RBL Facility as our primary sources of liquidity. We also may engage in non-core asset sale transactions to, among other things, fund capital expenditures when market conditions permit us to complete transactions on terms we find acceptable. There can be no assurance that such sources will be sufficient to fund our exploration, development and acquisition activities. If our revenues and cash flows decrease in the future as a result of a decline in commodity prices or a reduction in production levels, and we are unable to obtain additional equity or debt financing in the capital markets or access alternative sources of funds, we may be required to reduce the level of our capital expenditures and may lack the capital necessary to increase or even maintain our reserves and production levels.

Our future revenues, cash flows and spending levels are subject to a number of factors, including commodity prices, the level of production from existing wells and our success in developing and producing new wells. Further, our ability to access funds under the RBL Facility is based on a borrowing base, which is subject to periodic redeterminations based on our proved reserves and prices that will be determined by our lenders using the bank pricing prevailing at such time. If the prices for oil and natural gas decline, if we have a downward revision in estimates of our proved reserves, or if we sell additional oil and natural gas reserves, our borrowing base may be reduced.

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

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

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

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

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

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

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

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

The oil, natural gas and NGLs businesses are highly competitive. We compete with third parties in the search for and acquisition of leases, properties and reserves, as well as the equipment, materials

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

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

Our industry is cyclical, and historically there have been shortages of drilling rigs, equipment, supplies or qualified personnel. Declines in commodity prices can also impact the number of service providers for such drilling rigs, equipment, supplies or qualified personnel, contributing to or also resulting in the shortages. During periods of high prices, the cost of rigs, equipment, supplies and personnel can fluctuate widely and availability may be limited. These services may not be available on commercially reasonable terms or at all. We cannot predict the extent to which these conditions will exist in the future or their timing or duration. The high cost or unavailability of drilling rigs, equipment, supplies, personnel and other oil field services could significantly decrease our profit margins, cash flows and operating results and could restrict our ability to drill the wells and conduct the operations that we currently have planned and budgeted or that we may plan in the future. Any of these outcomes could have a material adverse effect on our business, results of operations and financial condition.

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

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

•: Adverse weather conditions, natural disasters, and/or other climate related matters—including extreme cold or heat, lightning and flooding, fires, earthquakes, hurricanes, tornadoes and other natural disasters. Although the potential effects of climate change on our operations (such as hurricanes, flooding, etc.) are uncertain at this time, changes in climate patterns as a result of global emissions of greenhouse gas (GHG) could also have a negative impact upon our

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operations in the future, particularly with regard to any of our facilities that are located in or near coastal regions;

•: Acts of aggression on critical energy infrastructure—including terrorist activity or "cyber security" events. We are subject to the ongoing risk that one of these incidents may occur which could significantly impact our business operations and/or financial results. Should one of these events occur in the future, it could impact our ability to operate our drilling and exploration processes, our operations could be disrupted, and/or property could be damaged resulting in substantial loss of revenues, increased costs to respond or other financial loss, damage to reputation, increased regulation and litigation and/or inaccurate information reported from our exploration and production operations to our financial applications, to our customers and to regulatory entities; and
•: Other hazards—including the collision of third-party equipment with our infrastructure; explosions, equipment malfunctions, mechanical and process safety failures, well blowouts, formations with abnormal pressures and collapses of wellbore casing or other tubulars; events causing our facilities to operate below expected levels of capacity or efficiency; uncontrollable flows of natural gas, oil, brine or well fluids, release of pollution or contaminants (including hydrocarbons) into the environment (including discharges of toxic gases or substances) and other environmental hazards.

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

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

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

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

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

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

For the year ended December 31, 2014, four purchasers accounted for approximately 80% of our oil revenues. We depend upon a limited number of significant purchasers for the sale of most of our production. The loss of any of these customers, should we be unable to replace them, could adversely affect our revenues and have a material adverse effect on our financial condition and results of operations. We cannot assure you that any of our customers will continue to do business with us or that we will continue to have access to suitably liquid markets for our future production.

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

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

•: the location of wells;
•: methods of drilling and completing wells;
•: allowable production from wells;
•: unitization or pooling of oil and gas properties;
•: spill prevention plans;
•: limitations on venting or flaring of natural gas;
•: disposal of fluids used and wastes generated in connection with operations;
•: access to, and surface use and restoration of, well properties;
•: plugging and abandoning of wells, even if we no longer own and/or operate such wells;
•: air quality and emissions, noise levels and related permits;
•: gathering, transportation and marketing of oil and natural gas (including NGLs);
•: taxation; and
•: competitive bidding rules on federal and state lands.

Generally, the regulations have become more stringent and have imposed more limitations on our operations and, as a result, have caused us to incur more costs to comply. Many required approvals are subject to considerable discretion by the regulatory agencies with respect to the timing and scope of approvals and permits issued. If permits are not issued, or if unfavorable restrictions or conditions are imposed on our drilling activities, we may not be able to conduct our operations as planned or at all. Delays in obtaining regulatory approvals or permits, the failure to obtain a drilling permit for a well, or the receipt of a permit with excessive conditions or costs could have a material negative impact on our operations and financial results. We may also incur substantial costs in order to maintain compliance with these existing laws and regulations, including costs to comply with new and more extensive

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reporting and disclosure requirements. Failure to comply with such requirements may result in the suspension or termination of operations and may subject us to criminal as well as civil and administrative penalties. We are exposed to fines and penalties to the extent that we fail to comply with the applicable laws and regulations, as well as the potential for limitations to be imposed on our operations. In addition, our costs of compliance may increase if existing laws and regulations are revised or reinterpreted, or if new laws and regulations become applicable to our operations. Such costs could have a material adverse effect on our business, financial condition and results of operations.

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

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

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

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

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

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

Investment funds affiliated with, and one or more co-investment vehicles controlled by, our Sponsors and other legacy investors collectively own a majority of our equity interests and such persons or their designees hold substantially all of the seats on the board of directors of our parent, EP Energy Corporation. As a result, the Sponsors and such other investors have control over our decisions to enter into certain corporate transactions and have the ability to prevent any transaction that typically would require the approval of stockholders, regardless of whether holders of our notes believe that any such transactions are in their own best interests. For example, the Sponsors and other legacy investors could collectively cause us to make acquisitions that increase the amount of our indebtedness or to sell

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assets, or could cause us to issue additional equity or declare dividends or other distributions to our equity holders. So long as investment funds affiliated with the Sponsors and other such investors continue to indirectly own a majority of the outstanding shares of our equity interests or otherwise control a majority of the board of directors of our parent, these investors will continue to be able to strongly influence or effectively control our decisions. The indentures governing the notes and the credit agreements governing the RBL Facility and our senior secured term loan permit us, under certain circumstances, to pay advisory and other fees, pay dividends and make other restricted payments to the Sponsors and other investors, and the Sponsors and such other investors or their respective affiliates may have an interest in our doing so.

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

We may face unanticipated water and other waste disposal costs.

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

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

•: we cannot obtain future permits from applicable regulatory agencies;
•: water of lesser quality or requiring additional treatment is produced;
•: our wells produce excess water;
•: new laws and regulations require water to be disposed in a different manner; or
•: costs to transport the produced water to the disposal wells increase.

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

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

•: we may not produce revenues, reserves, earnings or cash flow at anticipated levels or could have environmental, permitting or other problems for which contractual protections prove inadequate;
•: we may assume liabilities that were not disclosed to us and for which contractual protections prove inadequate or that exceed our estimates;
•: we may acquire properties that are subject to burdens on title that we were not aware of at the time of acquisition that interfere with our ability to hold the property for production and for which contractual protections prove inadequate;
•: we may be unable to integrate acquired businesses successfully and realize anticipated economic, operational and other benefits in a timely manner, which could result in substantial costs and delays or other operational, technical or financial problems;
•: we may encounter disruption to our ongoing business, distract management, divert resources and make it difficult to maintain our current business standards, controls, procedures and policies;
•: we may issue (or assume) additional equity or debt securities or debt instruments in connection with future acquisitions, which may affect our liquidity or financial leverage;
•: we may make mistaken assumptions about costs, including synergies related to an acquired business;
•: we may encounter difficulties in complying with regulations, such as environmental regulations, and managing risks related to an acquired business;
•: we may encounter limitations on rights to indemnity from the seller;
•: we may make mistaken assumptions about the overall costs of equity or debt used to finance any such acquisition;
•: we may encounter difficulties in entering markets in which we have no or limited direct prior experience and where competitors in such markets have stronger expertise and/or market positions;

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•: we may potentially lose key customers; and
•: we may lose key employees and/or encounter costly litigation resulting from the termination of those employees.

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

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

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

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

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

Given the decline in commodity prices, especially oil, we may incur impairment charges in the future depending on the value of our proved reserves, which are subject to change as a result of factors such as prices, costs and well performance. Currently, our reserves are based on the first day 12-month average prices of $94.99 per barrel of oil and $4.34 per MMBtu of natural gas, which are above the current strip price. Additionally, we could incur significant impairment charges of our unproved property should oil prices not justify sufficient capital allocation to the continued development of our unproved properties, among other factors. These impairment charges could have a material adverse effect on our results of operations and financial condition for the periods in which such charges are taken.

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

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

On December 15, 2009, the EPA published its findings that emissions of carbon dioxide, methane, and other GHGs present an endangerment to public health and the environment because emissions of such gases are, according to the EPA, contributing to the warming of the earth's atmosphere and other climate changes. These findings served as a statutory prerequisite for the EPA to adopt and implement regulations that would restrict emissions of GHGs under existing provisions of the Clean Air Act. The EPA has adopted two sets of related rules, one of which regulates emissions of GHGs from motor vehicles and the other of which regulates emissions of GHGs from certain large stationary sources of emissions such as power plants or industrial facilities. The EPA finalized the motor vehicle rule in April 2010 and it became effective January 2011. The EPA adopted the stationary source rule, also known as the "Tailoring Rule," in May 2010, and it also became effective January 2011, although the U.S. Supreme Court partially invalidated the rule in an opinion issued in June 2014. The Tailoring Rule remains applicable for those facilities considered major sources of six other "criteria" pollutants. Additionally, in September 2009, the EPA issued a final rule requiring the reporting of GHG emissions from specified large GHG emission sources in the U.S., including NGLs fractionators and local natural gas/distribution companies, beginning in 2011 for emissions occurring in 2010. In November 2010, the EPA expanded its existing GHG reporting rule to include onshore and offshore oil and natural gas production and onshore processing, transmission, storage and distribution facilities, which includes certain of our facilities, beginning in 2012 for emissions occurring in 2011. Amendments to the GHG

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reporting rule, revising certain calculation methods and clarifying certain terms, became final in early 2015. On December 9, 2014, the EPA proposed amendments to include reporting of emissions from completions and workovers of oil wells using hydraulic fracturing, as well as emissions from gathering and boosting systems. Public comment on this proposed amendment closed February 24, 2015, but a final amendment has not been promulgated. Additionally, the EPA announced in January 2015 that it will initiate rulemaking to encompass further segments of industry in GHG reporting, as well as explore regulatory opportunity to require use of new measurement and monitoring technology. In addition, the EPA has continued to adopt GHG regulations of the oil and gas and other industries, such as the proposed New Source Performance Standards for new coal-fired and natural gas-fired power plants published January 8, 2014. As a result of this continued regulatory focus, future GHG regulations of the oil and natural gas industry remain a possibility.

In March 2014, the White House announced a Climate Action Plan Strategy to Reduce Methane Emissions, and in support the EPA released five technical white papers focusing on emissions in the oil and gas industry. Subsequently, in January 2015 the White House announced that rulemaking will be initiated by several federal agencies to further reduce emissions of methane and VOCs in the oil and gas sector, including the EPA, the BLM, and the Pipeline and Hazardous Materials Safety Administration (PHMSA). From the EPA, such rulemaking may address green completions for hydraulically-fractured oil wells, emissions from pneumatic devices, and fugitive emissions at new or modified sources. The EPA is also expected to propose new guidelines in summer 2015 to reduce ozone precursors from oil and gas sources in nonattainment areas, in addition to already-proposed changes to the National Air Quality Ambient Standards for ozone. The BLM is expected to propose updated standards for venting and flaring in spring 2015. Similarly in 2015, the PHMSA is expected to propose natural gas pipeline safety standards that will concurrently reduce methane emissions. Finally, the White House has proposed funding for the Department of Energy (DOE) aimed at quantifying emissions from natural gas infrastructure and development of leak detection and control technology.

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

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

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

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

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

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

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

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

Despite the existence of various procedures and plans, there is a risk that we could experience well control problems in our operations. As a result, we could be exposed to regulatory fines and penalties, as well as landowner lawsuits resulting from any spills or leaks that might occur. While we maintain insurance against some of these risks in amounts that we believe are reasonable, our insurance coverages have material deductibles, self-insurance levels and limits on our maximum recovery and do not cover all risks. For example, from time to time we may not carry, or may be unable to obtain on terms that we find acceptable and/or reasonable, insurance coverage for certain exposures including, but not limited to, certain environmental exposures (including potential environmental fines and penalties), business interruption and named windstorm/hurricane exposures and, in limited

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circumstances, certain political risk exposures. The premiums and deductibles we pay for certain insurance policies are also subject to the risk of substantial increases over time that could negatively impact our financial results. In addition, we may not be able to renew existing insurance policies or procure desirable insurance on commercially reasonable terms. There is also a risk that our insurers may default on their insurance coverage obligations or that amounts for which we are insured, or that the proceeds of such insurance, will not compensate us fully for our losses. Any of these outcomes could have a material adverse effect on our business, results of operations and financial condition.

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

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

We use hydraulic fracturing extensively in our operations. The hydraulic fracturing process is typically regulated by state oil and natural gas commissions. Hydraulic fracturing involves the injection of water, sand and chemicals under pressure into formations to fracture the surrounding rock and stimulate production. The Safe Drinking Water Act (the SDWA) regulates the underground injection of substances through the Underground Injection Control (UIC) program. While hydraulic fracturing generally is exempt from regulation under the UIC program, the EPA has taken the position that hydraulic fracturing with fluids containing diesel fuel is subject to regulation under the UIC program as "Class II" UIC wells. On April 7, 2015, EPA published proposed regulations for pretreatment and discharge of wastewater from unconventional oil and gas extraction to publicly owned treatment works. Public comment is open until July 17, 2015. In addition, the BLM promulgated a final rule on March 26, 2015 that updates regulation of hydraulic fracturing activities on federal lands, including requirements for disclosure, well bore integrity, handling of flowback water, and further identification and isolation of useable water. The rule becomes effective June 24, 2015, although several states and trade organizations have filed lawsuits in federal court in Wyoming challenging and seeking to enjoin the rule.

The EPA has commenced a study of the potential environmental impacts of hydraulic fracturing activities, and a committee of the U.S. House of Representatives is also conducting an investigation of hydraulic fracturing practices. The EPA issued a Progress Report in December 2012 and a draft Assessment of Potential Impacts on June 4, 2015, in which it found no widespread, systemic impacts on drinking water resources from hydraulic fracturing activities. A Scientific Advisory Board will review the draft Assessment and will hold public hearing through October 30, 2015. This study, depending on its final result, could spur initiatives to regulate hydraulic fracturing under the SDWA or otherwise. Congress has in recent legislative sessions considered legislation to amend the SDWA, including legislation that would repeal the exemption for hydraulic fracturing from the definition of "underground injection" and require federal permitting and regulatory control of hydraulic fracturing, as well as legislative proposals to require disclosure of the chemical constituents of the fluids used in the fracturing process, were proposed in recent sessions of Congress. The U.S. Congress may consider similar SDWA legislation in the future.

On August 16, 2012, the EPA published final regulations under the Clean Air Act (CAA) that establish new air emission controls for oil and natural gas production and natural gas processing operations. Specifically, the EPA promulgated New Source Performance Standards establishing emission limits for sulfur dioxide (SO2) and volatile organic compounds (VOCs). The final rule requires a 95% reduction in VOCs emitted by mandating the use of reduced emission completions or "green completions" on all hydraulically-fractured gas wells constructed or refractured after January 1, 2015.

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Until this date, emissions from fractured and refractured gas wells were to be reduced through reduced emission completions or combustion devices. The rules also establish new requirements regarding emissions from compressors, controllers, dehydrators, storage tanks and other production equipment. In response to numerous requests for reconsideration of these rules from both industry and the environmental community and court challenges to the final rules, the EPA announced its intention to issue revised rules in 2013. The EPA published revised portions of these rules on September 23, 2013 for VOCs emissions for production oil and gas storage tanks, in part phasing in emissions controls on storage tanks past October 15, 2013. Additional revisions became effective December 31, 2014, primarily defining two stages of well completion operations. On March 23, 2015, the EPA proposed additional clarifications for low pressure wells and tanks in parallel.

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

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

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

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

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

•: the repeal of the percentage depletion allowance for oil and gas properties;
•: the elimination of current expensing of intangible drilling and development costs;
•: the elimination of the deduction for certain U.S. production activities; and
•: an extension of the amortization period for certain geological and geophysical expenditures.

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

We have certain contingent liabilities that could exceed our estimates.

We have certain contingent liabilities associated with litigation, regulatory, environmental and tax matters described in Note 7 to our consolidated financial statements and elsewhere in this prospectus. In addition, the positions taken in our federal, state, local and previously in non-U.S. tax returns require significant judgments, use of estimates and interpretation of complex tax laws. Although we believe that we have established appropriate reserves for our litigation, regulatory, environmental and tax matters, we could be required to accrue additional amounts in the future and/or incur more actual cash expenditures than accrued for and these amounts could be material.

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

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

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

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

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

We have sold various assets and either retained certain liabilities or indemnified certain purchasers against future liabilities relating to businesses and assets sold, including breaches of warranties, environmental expenditures, asset retirements and other representations that we have provided. We may also be subject to retained liabilities with respect to certain divested assets by operation of law. For example, the recent decline in commodity prices may create an environment where there is an increased risk that owners and/or operators of assets purchased from us may no longer be able to satisfy plugging or abandonment obligations that attach to such assets. In that event, due to operation of law, we may be required to assume these plugging or abandonment obligations on assets no longer owned and operated by us. Although we believe that we have established appropriate reserves for any such liabilities, we could be required to accrue additional amounts in the future and these amounts could be material.

Risks Related to Our Indebtedness and the Notes

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

We are a highly leveraged company. As of March 31, 2015, on a pro forma basis after giving effect to the Refinancing Transactions, we would have had $4,767 million face value of outstanding indebtedness (in addition to approximately $1.7 billion of undrawn commitments under the RBL Facility (after giving effect to issued and undrawn letters of credit)), and for the quarter ended March 31, 2015, we would have had total pro forma debt service payment obligations of approximately $79.1 million (including approximately $66.6 million of debt service obligations relating to fixed rate obligations).

Our substantial indebtedness could have important consequences for you as a holder of the notes. For example, it could:

•: limit our ability to borrow money for our working capital, capital expenditures, debt service requirements, strategic initiatives or other purposes;
•: make us more vulnerable to downturns in our business or the economy;
•: make it more difficult for us to satisfy our obligations with respect to our indebtedness, including the notes, and any failure to comply with the obligations of any of our debt instruments, including restrictive covenants and borrowing conditions, could result in an event of default under the indenture governing the notes and the agreements governing other indebtedness;

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•: require us to dedicate a substantial portion of our cash flow from operations to the repayment of our indebtedness, thereby reducing funds available to us for other purposes;
•: limit our flexibility in planning for, or reacting to, changes in our operations or business;
•: make us more highly leveraged than some of our competitors, which may place us at a competitive disadvantage;
•: restrict us from making strategic acquisitions, engaging in development activities, introducing new technologies or exploiting business opportunities;
•: cause us to make non-strategic divestitures;
•: limit, along with the financial and other restrictive covenants in our indebtedness, among other things, our ability to borrow additional funds or dispose of assets;
•: prevent us from raising the funds necessary to repurchase all notes tendered to us upon the occurrence of certain changes of control, which failure to repurchase would constitute a default under the indenture governing the notes; or
•: expose us to the risk of increased interest rates, as certain of our borrowings, including borrowings under the RBL Facility and our senior secured term loans, are at variable rates of interest.

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

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

We and our subsidiaries may be able to incur substantial indebtedness in the future. Although the terms of the indentures governing the existing senior notes and the notes and the credit agreements governing the RBL Facility and the senior secured term loans contain restrictions on our ability to incur additional indebtedness, including secured indebtedness that will be effectively senior to the notes, these restrictions are subject to a number of important qualifications and exceptions, and the indebtedness incurred in compliance with these restrictions could be substantial. These restrictions also will not prevent us from incurring obligations that do not constitute indebtedness. As of March 31, 2015, on a pro forma basis after giving effect to the Refinancing Transactions, we would have had approximately $1.7 billion available for additional borrowing under the RBL Facility (after giving effect to the issued and undrawn letters of credit), all of which would be secured. In addition to the notes, the existing senior notes and our borrowings under the RBL Facility and the senior secured term loans, the covenants under any other existing or future debt instruments could allow us to incur a significant amount of additional indebtedness. The more leveraged we become, the more we, and in turn our security holders, will be exposed to certain risks described above under "—Our substantial indebtedness could adversely affect our ability to raise additional capital to fund our operations, limit our ability to react to changes in the economy or our industry and prevent us from making debt service payments on the notes."

The notes are unsecured, and will be effectively subordinated to any existing and future secured debt.

The notes are unsecured and will rank equal in right of payment with our existing and future unsecured and unsubordinated senior debt, including the existing senior notes. The notes will not be secured by any of our or the guarantors' assets. The notes will be effectively subordinated to the RBL

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Facility, the senior secured term loans and any future secured debt to the extent the value of the assets that secure the indebtedness. The effect of this subordination is that upon a default in payment on, or the acceleration of, any of our secured indebtedness, or in the event of bankruptcy, insolvency, liquidation, dissolution or reorganization of us or the guarantors of the RBL Facility, the senior secured term loans or of other secured debt, the proceeds from the sale of assets securing our secured indebtedness will be available to pay obligations on the notes only after all indebtedness under the RBL Facility, the senior secured term loans and the other secured debt has been paid in full. As a result, the holders of the notes may receive less, ratably, than the holders of secured debt in the event of our or the guarantors' bankruptcy, insolvency, liquidation, dissolution or reorganization. As of March 31, 2015, on a pro forma basis after giving effect to the Refinancing Transactions, there would have been secured debt consisting of $971 million under the RBL Facility excluding issued and undrawn letters of credit (as well as approximately $1.7 billion of undrawn commitments (after giving effect to issued and undrawn letters of credit)) and $646 million under our senior secured term loans.

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

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

•: our future financial and operating performance, which will be affected by prevailing economic, industry and competitive conditions and financial, business, legislative, regulatory and other factors, many of which are beyond our control; and
•: our future ability to borrow under the RBL Facility, which depends on, among other things, our compliance with the covenants in the credit agreement governing such facility and our borrowing base determinations.

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

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

If we cannot make scheduled payments on our indebtedness, we will be in default and holders of the notes could declare all outstanding principal and interest to be due and payable, the lenders under the RBL Facility could terminate their commitments to loan money, our secured lenders (including the

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lenders under the RBL Facility and the senior secured term loans) could foreclose against the assets securing their loans and we could be forced into bankruptcy or liquidation. All of these events could cause you to lose all or part of your investment in the notes.

Repayment of our debt, including the notes, is dependent on cash flow generated by our subsidiaries.

We are a holding company and have no direct operations other than holding the equity interests in our subsidiaries and activities directly related thereto. Accordingly, repayment of our indebtedness, including the notes, is dependent on the generation of cash flow by our subsidiaries and (if they are not guarantors of the notes) their ability to make such cash available to us, by dividend, debt repayment or otherwise. Unless they are guarantors of the notes, our subsidiaries do not have any obligation to pay amounts due on the notes or to make funds available for that purpose. Our subsidiaries may not be able to, or may not be permitted to, make distributions to enable us to make payments in respect of our indebtedness, including the notes. Each of our subsidiaries is a distinct legal entity, and under certain circumstances legal and contractual restrictions may limit our ability to obtain cash from them and we may be limited in our ability to cause any future joint ventures to distribute their earnings to us. While the indentures governing the existing senior notes and the notes and the credit agreements governing the RBL Facility and the senior secured term loans limit the ability of our subsidiaries to incur consensual restrictions on their ability to pay dividends or make other intercompany payments to us, these limitations are subject to certain qualifications and exceptions. In the event that we do not receive distributions from our non-guarantor subsidiaries, we may be unable to make required principal and interest payments on our indebtedness, including the notes.

If we default on our obligations to pay our other indebtedness, we may not be able to make payments on the notes.

Any default under the agreements governing our indebtedness, including defaults under the RBL Facility and the senior secured term loans that are not waived by the required lenders, and the remedies sought by the holders of such indebtedness could leave us unable to pay principal, premium, if any, or interest on the notes and could substantially decrease the market value of the notes. If we are unable to generate sufficient cash flow and are otherwise unable to obtain funds necessary to meet required payments of principal, premium, if any, or interest on our indebtedness, or if we otherwise fail to comply with the various covenants, including financial and operating covenants, in the instruments governing our indebtedness (including the RBL Facility and the senior secured term loans), we could be in default under the terms of the agreements governing such indebtedness. In the event of such default, the holders of such indebtedness could elect to (i) declare all the funds borrowed thereunder to be due and payable, together with accrued and unpaid interest, (ii) terminate their commitments and cease making further loans and (iii) institute foreclosure proceedings against our assets, and we could be forced into bankruptcy or liquidation.

If our operating performance declines, we may in the future need to seek waivers from the required lenders or holders under the RBL Facility, the senior secured term loans and the existing senior notes to avoid being in default. If we breach our covenants under the RBL Facility, the senior secured term loans or the existing senior notes and seek a waiver, we may not be able to obtain a waiver from the required lenders or holders, as applicable. If this occurs, we would be in default under these facilities, the lenders or holders could exercise their rights as described above, and we could be forced into bankruptcy or liquidation. See "Description of Notes."

Upon any such bankruptcy filing, we would be stayed from making any ongoing payments on the notes, and the holders of the notes would not be entitled to receive post-petition interest or applicable fees, costs or charges, or any "adequate protection" under Title 11 of the United States Code, as amended (the "Bankruptcy Code").

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The notes will be structurally subordinated to all liabilities of our non-guarantor subsidiaries.

The notes will be structurally subordinated to indebtedness and other liabilities of our subsidiaries that are not guaranteeing the notes, and the claims of creditors of these subsidiaries, including trade creditors, will have priority as to the assets of these subsidiaries. In the event of a bankruptcy, liquidation or reorganization of any of our non-guarantor subsidiaries, these non-guarantor subsidiaries will pay the holders of their debts, holders of preferred equity interests and their trade creditors before they will be able to distribute any of their assets to us.

In addition, the indenture governing the notes permits these subsidiaries to incur additional indebtedness, subject to some limitations, and does not contain any limitation on the amount of other liabilities, such as trade payables, that may be incurred by these subsidiaries.

The notes will not be guaranteed by any of our non-U.S. subsidiaries or any other subsidiaries that are not material or wholly owned. These non-guarantor subsidiaries are separate and distinct legal entities and have no obligation, contingent or otherwise, to pay any amounts due pursuant to the notes, or to make any funds available therefore, whether by dividends, loans, distributions or other payments. Any right that we or the subsidiary guarantors have to receive any assets of any of the non-guarantor subsidiaries upon the liquidation or reorganization of those subsidiaries, and the consequent rights of holders of notes to realize proceeds from the sale of any of those subsidiaries' assets, will be structurally subordinated to the claims of those subsidiaries' creditors, including trade creditors and holders of preferred equity interests of those subsidiaries. As of March 31, 2015, on a pro forma basis after giving effect to the Refinancing Transactions, non-wholly owned subsidiaries, foreign subsidiaries and other subsidiaries of the Issuer that will not guarantee the notes held approximately 0% of our consolidated assets and had no outstanding indebtedness, excluding intercompany obligations.

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

The RBL Facility and the senior secured term loans and the indentures governing the existing senior notes and the notes contain, and any other existing or future indebtedness of ours would likely contain, a number of covenants that impose significant operating and financial restrictions on us, including restrictions on our and our subsidiaries ability to, among other things:

•: incur additional debt, guarantee indebtedness or issue certain preferred shares;
•: restricted payments;
•: prepay, redeem or repurchase certain debt;
•: make loans or certain investments;
•: sell certain assets;
•: create liens on certain assets;
•: consolidate, merge, sell or otherwise dispose of all or substantially all of our assets;
•: enter into certain transactions with our affiliates;
•: alter the businesses we conduct;
•: enter into agreements restricting our subsidiaries' ability to pay dividends; and
•: designate our subsidiaries as unrestricted subsidiaries.

In addition, the RBL Facility requires us to comply with certain financial covenants.

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

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

•: will not be required to lend any additional amounts to us;
•: could elect to declare all borrowings outstanding, together with accrued and unpaid interest and fees, to be due and payable and terminate all commitments to extend further credit;
•: could require us to apply all of our available cash to repay these borrowings; or
•: could effectively prevent us from making debt service payments on the notes (due to a cash sweep feature);

any of which could result in an event of default under the notes.

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

If any of our outstanding indebtedness under the RBL Facility and the senior secured term loans or our other indebtedness, including the notes and the existing senior notes, were to be accelerated, there can be no assurance that our assets would be sufficient to repay such indebtedness in full. See "Description of Exchange Notes."

Because each subsidiary guarantor's liability under its guarantee may be reduced to zero, avoided or released under certain circumstances, you may not receive any payments from some or all of the subsidiary guarantors.

You have the benefit of the guarantees of the guarantors. However, the guarantees by the subsidiary guarantors are limited to the maximum amount that such guarantors are permitted to guarantee under applicable law. As a result, any such guarantor's liability under its guarantee could be reduced to zero, depending on the amount of other obligations of such guarantor. Further, under the circumstances discussed more fully below, a court under federal or state fraudulent conveyance and transfer statutes could void the obligations under a guarantee or further subordinate it to all other obligations of the guarantor.

In addition, the subsidiary guarantors will be automatically released from their guarantees upon the occurrence of certain events, including the following:

•: the designation of a subsidiary guarantor as an unrestricted subsidiary;
•: the release or discharge of any guarantee or indebtedness that resulted in the creation of the guarantee of the notes by a subsidiary guarantor; or
•: the sale or other disposition, including the sale of substantially all the assets, of a subsidiary guarantor.

If the guarantee of any subsidiary guarantor is released, no holder of the notes will have a claim as a creditor against that subsidiary, and the indebtedness and other liabilities, including trade payables

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and preferred stock, if any, whether secured or unsecured, of that subsidiary will be structurally senior to the claim of any holders of the notes. See "Description of Exchange Notes—Subsidiary Guarantees."

We may not be able to repurchase the notes upon a change of control.

Upon the occurrence of certain specific kinds of change of control events, we will be required to offer to repurchase all outstanding notes and our existing senior notes and senior secured term loans at 101% of the principal amount thereof plus, without duplication, accrued and unpaid interest and additional interest, if any, to the date of repurchase. Additionally, under the RBL Facility, a change of control constitutes an event of default that permits the lenders to accelerate the maturity of borrowings and terminate their commitments to lend. The source of funds for any repurchase of the notes, the existing senior notes and repayment of borrowings under the RBL Facility and the senior secured term loans would be our available cash or cash generated from our subsidiaries' operations or other sources, including borrowings, sales of assets or sales of equity. It is possible that we will not have sufficient funds at the time of a change of control to make the required repurchases or that restrictions in the RBL Facility will not allow such repurchases. We may require additional financing from third parties to fund any such repurchases, and we may be unable to obtain financing on satisfactory terms or at all. Further, our ability to repurchase the notes may be limited by law. In addition, certain important corporate events, such as leveraged recapitalizations that would increase the level of our indebtedness, would not constitute a change of control under the indenture governing the notes. See "Description of Notes—Change of Control."

Courts interpreting change of control provisions under New York law (which is the governing law of the indenture governing the notes) have not provided clear and consistent meanings of such change of control provisions which leads to subjective judicial interpretation. In addition, a court case in Delaware has questioned whether a change of control provision contained in an indenture could be unenforceable on public policy grounds.

We may enter into transactions that would not constitute a change of control that could affect our ability to satisfy our obligations under the notes.

Legal uncertainty regarding what constitutes a change of control and the provisions of the indenture governing the notes may allow us to enter into transactions, such as acquisitions, refinancing or recapitalizations, that would not constitute a change of control but may increase our outstanding indebtedness or otherwise affect our ability to satisfy our obligations under the notes. The definition of change of control for purposes of the notes includes a phrase relating to the transfer of "all or substantially all" of our assets taken as a whole. Although there is a limited body of case law interpreting the phrase "substantially all," there is no precise established definition of the phrase under applicable law. Accordingly, your ability to require us to repurchase notes as a result of a transfer of less than all of our assets to another person may be uncertain.

Federal and state statutes allow courts, under specific circumstances, to void notes and guarantees and require noteholders to return payments received.

If we or any guarantor becomes a debtor in a case under the Bankruptcy Code or encounters other financial difficulty, under federal or state fraudulent transfer law a court may void or otherwise decline to enforce the notes or the guarantees. A court might do so if it found that when we issued the notes or the subsidiary guarantor entered into its guarantee, or in some states when payments became due under the notes or the guarantees, we or the subsidiary guarantor received less than reasonably equivalent value or fair consideration and:

•: was insolvent or rendered insolvent by reason of such incurrence;
•: was left with inadequate capital to conduct its business;

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•: believed or reasonably should have believed that it would incur debts beyond its ability to pay; or
•: was a defendant in an action for money damages or had a judgment for money damages docketed against us or the subsidiary guarantor if, in either case, the judgment is unsatisfied after final judgment.

The court might also void an issuance of notes or a guarantee, without regard to the above factors, if the court found that we issued the notes or the applicable guarantor entered into its guarantee with actual intent to hinder, delay or defraud its creditors.

A court would likely find that we or a guarantor did not receive reasonably equivalent value or fair consideration for the notes or its guarantee if we or a guarantor did not substantially benefit directly or indirectly from the issuance of the notes. If a court were to void the issuance of the notes or any guarantee you would no longer have any claim against the issuer or the applicable guarantor. Sufficient funds to repay the notes may not be available from other sources, including the remaining obligors, if any. In addition, the court might direct you to repay any amounts that you already received from us or a guarantor. In the event of a finding that a fraudulent transfer or conveyance occurred, you may not receive any repayment on the notes. Further, the avoidance of the notes could result in an event of default with respect to our and our subsidiaries' other debt, which could result in acceleration of that debt.

The measures of insolvency for purposes of these fraudulent transfer laws will vary depending upon the law applied in any proceeding to determine whether a fraudulent transfer has occurred. Generally, however, a guarantor would be considered insolvent if:

•: the sum of its debts, including contingent liabilities, was greater than the fair saleable value of all of its assets;
•: if the present fair saleable value of its assets was less than the amount that would be required to pay its probable liability on its existing debts, including contingent liabilities, as they become absolute and mature; or
•: it could not pay its debts as they become due.

On the basis of historical financial information, recent operating history and other factors, we believe that the subsidiary guarantors on a consolidated basis, after giving effect to their guarantee of these notes, will not be insolvent, will not have unreasonably small capital for the business in which they are engaged and will not have incurred debts beyond their ability to pay such debts as they mature. In addition, no subsidiary guarantor was a defendant in an action for money damages, or had a judgment for money damages docketed against it, for which the judgment was unsatisfied after final judgment. We cannot assure you, however, as to what standard a court would apply in making these determinations or that a court would agree with our conclusions in this regard.

Although each guarantee entered into by a guarantor will contain a provision intended to limit that guarantor's liability to the maximum amount that it could incur without causing the incurrence of obligations under its guarantee to be a fraudulent transfer, this provision may not be effective to protect those guarantees from being voided under fraudulent transfer law, or may reduce that guarantor's obligation to an amount that effectively makes its guarantee worthless. In a Florida bankruptcy case (which was subsequently reinstated by the applicable court of appeals on other grounds), this kind of provision was found to be ineffective to protect the guarantees.

Finally, as a court of equity, the bankruptcy court may subordinate the claims in respect of the notes to other claims against us under the principle of equitable subordination if the court determines that (a) the holder of notes engaged in some type of inequitable conduct, (b) the inequitable conduct

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resulted in injury to our other creditors or conferred an unfair advantage upon the holders of notes and (c) equitable subordination is not inconsistent with the provisions of the Bankruptcy Code.

Our variable rate indebtedness subjects us to interest rate risk, which could cause our debt service obligations to increase significantly.

Borrowings under the RBL Facility and the senior secured term loans are at variable rates of interest and expose us to interest rate risk. Assuming the RBL Facility is fully drawn, and the applicable LIBOR rate exceeds the term loan LIBOR floor, each 0.125% change in assumed blended interest rates would result in a $3.5 million change in annual interest expense on indebtedness under the RBL Facility and the senior secured term loans. We have entered into interest rate swaps that involve the exchange of floating for fixed rate interest payments in order to reduce interest rate volatility. However, we may not maintain interest rate swaps with respect to all of our variable rate indebtedness, and such swaps, along with any swaps we enter into in the future, may not fully mitigate our interest rate risk, may prove disadvantageous or may create additional risks.

Many of the restrictive covenants contained in the indenture governing the notes will not apply during any period in which the notes are rated investment grade by both Moody's and S&P.

Many of the covenants contained in the indenture governing the notes will not apply to us during any period in which the notes are rated investment grade by both Moody's Investors Service, Inc. and Standard & Poor's Ratings Group, provided that at such time no default or event of default has occurred and is continuing. Such covenants include restrictions on, among other things, our ability to make certain distributions, incur indebtedness and enter into certain other transactions. There can be no assurance that the notes will ever be rated investment grade or that if the notes ever are rated investment grade they will maintain these ratings. However, suspension of these covenants would allow us to engage in certain transactions that would not be permitted while these covenants were in force. To the extent the covenants are subsequently reinstated, any such actions taken while the covenants were suspended would not result in an event of default under the indenture governing the notes. See "Description of Exchange Notes—Certain Covenants."

Risks Related to the Exchange Offer

If you do not properly tender your initial notes, you will continue to hold unregistered initial notes and be subject to the same limitations on your ability to transfer initial notes.

We will only issue exchange notes in exchange for initial notes that are timely received by the exchange agent together with all required documents, including a properly completed and signed letter of transmittal. Therefore, you should allow sufficient time to ensure timely delivery of the initial notes and you should carefully follow the instructions on how to tender your initial notes. Neither we nor the exchange agent are required to tell you of any defects or irregularities with respect to your tender of the initial notes. If you are eligible to participate in the exchange offer and do not tender your initial notes or if we do not accept your initial notes because you did not tender your initial notes properly, then, after we consummate the exchange offer, you will continue to hold initial notes that are subject to the existing transfer restrictions and will no longer have any registration rights or be entitled to any additional interest with respect to the initial notes. In general, you may only offer or sell the initial notes if they are registered under the Securities Act and applicable state securities laws, or offered and sold under an exemption from these requirements. Except as required by the registration rights

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agreement, we do not currently anticipate that we will register under the Securities Act, any initial notes that remain outstanding after the Exchange Offer. In addition:

•: if you tender your initial notes for the purpose of participating in a distribution of the exchange notes, you will be required to comply with the registration and prospectus delivery requirements of the Securities Act in connection with any resale of the exchange notes; and
•: if you are a broker-dealer that receives exchange notes for your own account in exchange for initial notes that you acquired as a result of market-making activities or any other trading activities, you will be required to acknowledge that you will deliver a prospectus in connection with any resale, offer to resell or other transfer of those exchange notes.

We have agreed that, for a period of 180 days after the exchange offer is consummated, we will make additional copies of this prospectus and any amendment or supplement to this prospectus available to any broker-dealer for use in connection with any resales of the exchange notes. After the exchange offer is consummated, if you continue to hold any initial notes, you may have difficulty selling them because there will be fewer initial notes outstanding.

There is no active trading market for the exchange notes.

The exchange notes are a new issue of securities for which there is no existing trading market. Accordingly, we cannot assure you that a liquid market for the exchange notes will develop or, if developed, that it will continue or that you will be able to sell your exchange notes at a particular time or at favorable prices. We have not applied, and do not intend to apply for listing or quotation of the notes on any securities exchange or automated quotation system.

The liquidity of any market for the exchange notes is subject to a number of factors, including:

•: the number of holders of exchange notes;
•: our operating performance and financial condition;
•: our ability to complete the exchange offer;
•: the market for similar securities;
•: the interest of securities dealers in making a market in the exchange notes; and
•: prevailing interest rates.

We understand that one or more of the initial purchasers with respect to the initial notes presently intend to make a market in the exchange notes. However, they are not obligated to do so, and any market-making activity with respect to the exchange notes may be discontinued at any time without notice. In addition, any market-making activity will be subject to the limits imposed by the Securities Act and the Exchange Act and may be limited during the exchange offer or the pendency of an applicable shelf registration statement.

The issuance of the exchange notes may adversely affect the market for the initial notes.

To the extent the initial notes are tendered and accepted in the exchange offer, the trading market for the untendered and tendered but unaccepted initial notes could be adversely affected. Because we anticipate that most holders of the initial notes will elect to exchange their initial notes for exchange notes due to the absence of restrictions on the resale of exchange notes under the Securities Act, we anticipate that the liquidity of the market for any initial notes remaining after the completion of this exchange offer may be substantially limited. Please refer to the section in this prospectus entitled "The Exchange Offer—Your Failure to Participate in the Exchange Offer Will Have Adverse Consequences."

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Some persons who participate in the exchange offer must deliver a prospectus in connection with resales of the exchange notes.

Based on interpretations of the staff of the Commission contained in Exxon Capital Holdings Corp., SEC no-action letter (April 13, 1988), Morgan Stanley & Co. Inc., SEC no-action letter (June 5, 1991) and Shearman & Sterling, SEC no-action letter (July 2, 1983), we believe that you may offer for resale, resell or otherwise transfer the exchange notes without compliance with the registration and prospectus delivery requirements of the Securities Act. However, in some instances described in this prospectus under "Plan of Distribution," you will remain obligated to comply with the registration and prospectus delivery requirements of the Securities Act to transfer your exchange notes. In these cases, if you transfer any exchange note without delivering a prospectus meeting the requirements of the Securities Act or without an exemption from registration of your exchange notes under the Securities Act, you may incur liability under the Securities Act. We do not and will not assume, or indemnify you against, this liability.

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MARKET AND INDUSTRY DATA

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

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CAUTIONARY STATEMENT CONCERNING FORWARD-LOOKING STATEMENTS

This prospectus and certain oral statements made from time to time by us and our representatives contain "forward-looking statements" within the meaning of the Private Securities Litigation Reform Act of 1995. Forward-looking statements involve risks and uncertainties, many of which are beyond our control. These forward-looking statements are based on assumptions or beliefs that we believe to be reasonable; however, assumed facts almost always vary from the actual results and such variances can be material. Where we express an expectation or belief as to future results, that expectation or belief is expressed in good faith and is believed to have a reasonable basis. We cannot assure you, however, that the stated expectation or belief will occur. The words "believe," "expect," "estimate," "anticipate," "intend" and "should" and similar expressions will generally identify forward-looking statements. All of our forward-looking statements are expressly qualified by these and the other cautionary statements in this prospectus, including those set forth in "Risk Factors." Important factors that could cause our actual results to differ materially from the expectations reflected in our forward-looking statements include, among others:

•: the supply and demand for oil, natural gas and NGLs;
•: changes in commodity prices and basis differentials for oil and natural gas;
•: our ability to meet production volume targets;
•: the uncertainty of estimating proved reserves and unproved resources;
•: the future level of service and capital costs;
•: the availability and cost of financing to fund future exploration and production operations;
•: the success of drilling programs with regard to proved undeveloped reserves and unproved resources;
•: our ability to comply with the covenants in various financing documents;
•: our ability to obtain necessary governmental approvals for proposed exploration and production projects and to successfully construct and operate such projects;
•: actions by credit rating agencies;
•: credit and performance risk of our lenders, trading counterparties, customers, vendors and suppliers;
•: general economic and weather conditions in geographic regions or markets we serve, or where our operations are located, including the risk of a global recession and negative impact on demand for oil and/or natural gas;
•: the uncertainties associated with governmental regulation, including any potential changes in federal and state tax laws and regulations;
•: competition; and
•: the other factors described under "Risk Factors."

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

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USE OF PROCEEDS

We will not receive any cash proceeds from the issuance of the exchange notes in exchange for the outstanding initial notes. We are making this exchange solely to satisfy our obligations under the registration rights agreement entered into in connection with the offering of the initial notes. In consideration for issuing the exchange notes, we will receive initial notes in like aggregate principal amount.

The net proceeds of the offering of the initial notes were $800 million before the initial purchasers' discount and estimated fees and expenses. We used the net proceeds from the offering (i) to purchase approximately $481.2 million aggregate principal amount of our 2019 Notes in the Tender Offer, (ii) to redeem approximately $268.7 million aggregate principal amount of our 2019 Notes that remained outstanding upon completion of the Tender Offer, (iii) to repay indebtedness under the RBL Facility, (iv) to pay related fees and expenses and (v) for other general corporate purposes.

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CAPITALIZATION

The following table sets forth our cash and cash equivalents and capitalization as of March 31, 2015:

(1): on a historical basis, and
(2): on an adjusted basis to give effect to the Refinancing Transactions.

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

	As of March 31, 2015

	Historical		As Adjusted
	(in millions)
Cash and cash equivalents	$	7	$	7



Long-term debt:
RBL Facility(1)	$	980	$	971
Senior secured term loans due 2018 and 2019		646		646
6.875% senior secured notes due 2019		750		—
9.375% senior notes due 2020		2,000		2,000
7.750% senior notes due 2022		350		350
The Notes		—		800

Total long-term debt		4,726		4,767
Member's equity		3,826		3,826

Total capitalization	$	8,552	$	8,593

(1): As of March 31, 2015, after giving effect to the Refinancing Transactions, approximately $971 million would have been drawn and outstanding under the RBL Facility, and approximately $1.7 billion would have been available and undrawn under the RBL Facility (after giving effect to issued and undrawn letters of credit).

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SELECTED HISTORICAL CONSOLIDATED FINANCIAL DATA

Set forth below is the selected historical consolidated financial data for the periods and as of the dates indicated. We have derived the selected historical consolidated balance sheet data as of December 31, 2014 and December 31, 2013 and the statements of income data and statements of cash flow data for the years ended December 31, 2014 and December 31, 2013 and for the period from March 23 to December 31, 2012 and the period from January 1, 2012 through May 24, 2012, from the audited consolidated financial statements of EP Energy LLC, which are included elsewhere in this prospectus. We have derived the selected historical consolidated balance sheet data as of December 31, 2011 and 2010, and the statements of income data and statements of cash flow data for the years ended December 31, 2011 and 2010 from the consolidated historical predecessor financial statements of EP Energy LLC, which are not included in this prospectus. The selected unaudited historical consolidated financial data as of and for the quarters ended March 31, 2015 and March 31, 2014, have been derived from the unaudited consolidated financial statements of EP Energy LLC appearing elsewhere in this prospectus, which have been prepared on a basis consistent with the audited consolidated financial statements of EP Energy LLC. In the opinion of management, such unaudited financial data reflects all adjustments, consisting only of normal and recurring adjustments, necessary for a fair presentation of the results for such period. The results of operations for the interim periods are not necessarily indicative of the results to be expected for the full year or any future period.

All financial statement periods present our Brazil operations as discontinued operations. Financial statement periods after May 24, 2012 (successor periods) also present certain domestic natural gas assets sold as discontinued operations.

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

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	Successor															Predecessor

													March 23 (inception) to December 31, 2012			January 1 to May 24, 2012
	Quarter ended March 31, 2015			Quarter ended March 31, 2014			Year ended December 31, 2014			Year ended December 31, 2013									Year ended December 31, 2011			Year ended December 31, 2010


							(in millions)
Statement of income data
Operating revenues:
Oil	$	229		$	406		$	1,705		$	1,254		$	499		$	310		$	513		$	316
Natural gas		48			78			284			300			216			228			901			919
NGLs		13			27			110			74			28			29			58			60

Physical sales		290			511			2,099			1,628			743			567			1,472			1,295
Financial derivatives(1)		203			(135	)		985			(52	)		(62	)		365			284			390
Other		—			—			—			—			—			—			—			19

Total operating revenues		493			376			3,084			1,576			681			932			1,756			1,704

Operating expenses:
Natural gas purchases		7			3			23			25			19			—			—			—
Transportation costs		27			23			100			85			48			45			85			88
Lease operating expenses		47			44			193			147			63			80			177			157
General and administrative		47			49			160			228			358			69			185			175
Depreciation, depletion and amortization		224			192			875			585			188			307			579			449
Impairment/ceiling test charges		—			—			2			2			1			62			6			25
Exploration and other expense		6			8			25			41			40			—			—			—
Taxes, other than income taxes		22			33			129			79			36			31			76			72

Total operating expenses		380			352			1,507			1,192			753			594			1,108			966

Operating income (loss)		113			24			1,577			384			(72	)		338			648			738
Other income (expense)		—			—			1			(12	)		(1	)		(3	)		(6	)		(6	)
Loss on extinguishment of debt		—			—			—			(9	)		(14	)		—			—			—
Interest expense, net of capitalized interest		(84	)		(77	)		(316	)		(321	)		(218	)		(14	)		(14	)		(23	)

Income (loss) from continuing operations before income taxes		29			(53	)		1,262			42			(305	)		321			628			709
Income tax expense		10			—			1,121			—			—			134			243			258

Income (loss) from continuing operations	$	19		$	(53	)	$	141		$	42		$	(305	)	$	187		$	385		$	451

(1): Includes $5 million for the period from January 1 to May 24, 2012, and $11 million for each of the years ended December 31, 2011 and 2010, respectively, reclassified from accumulated other comprehensive income associated with accounting hedges.

	Successor															Predecessor

													March 23 to December 31, 2012			January 1 to May 24, 2012
	Quarter ended March 31, 2015			Quarter ended March 31, 2014			Year ended December 31, 2014			Year ended December 31, 2013									Year ended December 31, 2011			Year ended December 31, 2010


							(in millions)
Statement of cash flows data
Net cash provided by (used in):
Operating activities	$	270		$	307		$	1,295		$	975		$	449		$	580		$	1,426		$	1,067
Investing activities		(432	)		(442	)		(2,064	)		(475	)		(7,893	)		(628	)		(1,237	)		(1,130	)
Financing activities		148			166			742			(515	)		7,507			110			(238	)		(46	)
Other financial data
Ratio of earnings to fixed charges(1)		1.28x			—			4.66x			1.17x			—			19.33x			27.84x			26.30x

(1): Earnings for the quarter ended March 31, 2014 and the period from March 23 to December 31, 2012 were inadequate to cover fixed charges by $58 million and $301 million, respectively. For purposes of computing these ratios, earnings means income (loss) from continuing operations before income taxes before income or loss from equity investees, adjusted to reflect actual distributions from equity investments and fixed charges less capitalized interest. Fixed charges means the sum of interest costs (not including interest on tax liabilities which is included in income tax expense on our income statement), amortization of debt costs and that portion of rental expense we believe reflects a reasonable approximation of the interest component of rent expense.

	Successor								Predecessor

			As of December 31,						As of December 31,
	As of March 31, 2015		As of December 31,						As of December 31,
	As of March 31, 2015		2014		2013		2012		2011		2010
			(in millions)




Balance sheet data
Cash and cash equivalents	$	7	$	21	$	48	$	63	$	25	$	74
Total assets		10,309		10,194		8,326		8,293		5,103		4,942
Total long-term debt		4,726		4,598		4,039		4,346		851		301
Member's/Stockholders' equity		3,826		3,782		3,455		3,085		3,100		3,067

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

Our Management's Discussion and Analysis of Financial Condition and Results of Operations ("MD&A") should be read in conjunction with the financial statements and the accompanying notes included elsewhere in this prospectus. This discussion contains forward-looking statements and involves numerous risks and uncertainties, including, but not limited to, those described in "Risk Factors." Actual results may differ materially from those contained in any forward-looking statements. See "Cautionary Statements Concerning Forward-Looking Statements." Additionally, the financial results for the successor period subsequent to the Acquisition includes the application of the acquisition method of accounting and the application of the successful efforts method of accounting for oil and natural gas properties. All periods included in these financial statements prior to 2015 present our Brazil operations (sold in 2014) as discontinued operations. The successor periods prior to 2015 present certain domestic natural gas assets sold prior to 2015, including the South Louisiana Wilcox, CBM, South Texas and Arklatex assets, as discontinued operations. Predecessor periods do not present these domestic sales as discontinued operations due to the application of the full cost method of accounting prior to the Acquisition. As a result of these differences in presentation, year-over-year results may not be comparable. Unless otherwise indicated or the context otherwise requires, references in this MD&A section to "we," "our," "us" and the "Company" refer to EP Energy LLC (the "Successor") and EP Energy Global LLC (the "Predecessor" for accounting purposes), and each of their consolidated subsidiaries.

Our Business

Overview

•: Eagle Ford Shale. The Eagle Ford Shale in South Texas continues to provide the highest economic returns in our portfolio.
•: Wolfcamp Shale. In our Wolfcamp Shale program, located in the Permian Basin in West Texas, we are focused on optimizing our drilling, completion and artificial lift systems.
•: Altamont. In the Altamont Field in the Uinta Basin in Northeastern Utah, we are gaining operational efficiencies as we develop this oil field. Our acreage in this area is largely held-by-production.
•: Haynesville Shale. The Haynesville Shale in North Louisiana generates positive cash flow, and our acreage in the Haynesville Shale is held-by-production.

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

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Factors Influencing Our Profitability

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

•: growing our proved reserve base and production volumes through the successful execution of our drilling programs or through acquisitions;
•: finding and producing oil and natural gas at reasonable costs;
•: managing cash costs; and
•: managing commodity price risks on our oil and natural gas production.

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

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

Derivative Instruments

Our realized prices from the sale of our oil and natural gas are affected by (i) commodity price movements, including locational or basis price differences that exist between the commodity index price (e.g., WTI) and the actual price at which we sell our oil and natural gas, and (ii) other contractual pricing adjustments contained in the underlying sales contract. In order to stabilize cash flows and protect the economic assumptions associated with our capital investment programs, we enter into financial derivative contracts to reduce the financial impact of unfavorable commodity price movements and locational price differences. Certain derivative contracts, usually short term in nature (less than one year), involve the receipt or payment of premiums. No cash premiums were received or paid for the quarter ended March 31, 2015. Cash premiums received for the quarter ended March 31, 2014, were less than $1 million.

During the quarter ended March 31, 2015, we (i) settled commodity index hedges on approximately 91% of our oil production, 78% of our total liquids production and 92% of our natural gas production at average floor prices of $91.28 per barrel of oil and $4.26 per MMBtu, respectively and (ii) hedged basis risk on approximately 50% of our year-to-date Eagle Ford oil production. To the extent our oil and natural gas production is unhedged, either from a commodity index price or locational price perspective, our financial results will be impacted from period to period as further

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described inOperating Revenues. The following table reflects the contracted volumes and the prices we will receive under derivative contracts we held as of March 31, 2015.

	2015					2016					2017

	Volumes(1)		Average Price(1)			Volumes(1)		Average Price(1)			Volumes(1)		Average Price(1)
Oil
Fixed Price Swaps
WTI		13,361	$	89.34			8,510	$	80.03			4,015	$	66.11
Brent		1,925	$	100.01			—	$	—			—	$	—
LLS		—	$	—			5,124	$	91.88			—	$	—
Ceilings		825	$	100.00			—	$	—			—	$	—
Three Way Collars
Ceiling—Brent		825	$	110.02			—	$	—			—	$	—
Floors—Brent(2)		825	$	100.00			—	$	—			—	$	—
Ceiling—LLS		—	$	—			1,464	$	99.29			—	$	—
Floors—LLS(3)		—	$	—			1,464	$	94.00			—	$	—
Basis Swaps
LLS vs. WTI(4)		5,163	$	4.11			2,013	$	3.91			—	$	—
LLS vs. Brent(5)		2,750	$	(3.77	)		2,196	$	(4.99	)		—	$	—
Midland vs. Cushing(6)		825	$	(0.65	)		—	$	—			—	$	—
WTI—CM vs. TM(7)		2,750	$	1.28			—	$	—			—	$	—
NYMEX Roll(8)		7,400	$	(0.96	)		7,316	$	(0.92	)		—	$	—
Natural Gas
Fixed Price Swaps		47	$	4.26			7	$	4.20			—	$	—
Basis Swaps(9)
CIG		3	$	(0.25	)		—	$	—			—	$	—
Waha		3	$	(0.07	)		—	$	—			—	$	—
Propane
Fixed Price Swaps		35	$	0.60			—	$	—			—	$	—

(1): Volumes presented are MBbls for oil, TBtu for natural gas and MMGal for propane. Prices presented are per Bbl of oil, MMBtu of natural gas and Gal for propane.
(2): If market prices settle at or below $85.00 in 2015, we will receive a "locked-in" cash settlement of the market price plus $15.00 per Bbl.
(3): If market prices settle at or below $80.00 in 2016, we will receive a "locked-in" cash settlement of the market price plus $14.00 per Bbl.
(4): EP Energy receives WTI plus basis spread listed and pays LLS.
(5): EP Energy receives Brent plus basis spread listed and pays LLS.
(6): EP Energy receives Cushing plus basis spread listed and pays Midland.
(7): EP Energy receives the WTI trade month (TM) plus the spread listed and pays WTI calendar month (CM).
(8): Hedges the timing risk associated with our physical sales. We generally sell oil for the delivery month at a sales price based on the average NYMEX WTI price during that month, plus an adjustment calculated as a spread between the weighted average prices of the delivery month, the next month and the following month during the period when the delivery month is prompt (the "trade month roll").
(9): EP Energy receives the basis spread listed and pays CIG and Waha basis.

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The following table reflects the volumes and prices associated with derivative contracts entered into between April 1, 2015 and April 24, 2015, which are not reflected in the table above.

	2015					2016

	Volumes(1)		Average Price(1)			Volumes(1)		Average Price(1)
Oil
Fixed Price Swaps
LLS(2)		—	$	—			4,392	$	67.25
Basis Swaps
WTI—CM vs. TM		—	$	—			3,660	$	0.20
NYMEX Roll		490	$	(1.00	)		182	$	(1.00	)

(1): Volumes presented are MBbls. Prices presented are per Bbl.
(2): In April 2015, we unwound 1,464 MBbls of 2016 LLS three way collars in exchange for 4,392 MBbls of 2016 LLS fixed price swaps. No cash or other consideration was included as part of this exchange.

Summary of Liquidity and Capital Resources

As of March 31, 2015, we had available liquidity, including existing cash, of approximately $1.7 billion. We believe we have sufficient liquidity for 2015 from our cash flows from operations (including our hedging program, which provides significant price protection to our near-term revenues and cash flows), combined with the availability under our $2.75 billion RBL Facility and available cash, to fund our current obligations, projected working capital requirements and our capital spending plan. Additionally, with the extension of our $2.75 billion RBL Facility maturity date to 2019, the earliest maturity date of our remaining term debt obligations is in 2018. See "—Liquidity and Capital Resources" for more information.

Outlook for 2015. For the full year 2015, we expect the following:

•: Capital expenditures of approximately $1.2 billion to $1.25 billion, allocated primarily to our oil programs: $825 million to Eagle Ford, $190 million to Wolfcamp, $140 million to Altamont and $100 million to Haynesville.
•: Well completions between 160 and 190.
•: Average daily production volumes for the year of approximately 97.0 MBoe/d to 107.0 MBoe/d, including average daily oil production volumes of approximately 57 MBbls/d to 63 MBbls/d.
•: Per unit adjusted cash operating costs for the year of approximately $10.50 to $12.00 per Boe, and transportation costs of $2.95 to $3.15 per Boe.
•: Per unit depreciation, depletion and amortization rate for the year of approximately $25.00 to $27.00 per Boe.

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Production Volumes and Drilling Summary

Production Volumes

Below is an analysis of our production volumes for the following periods:

	Quarter ended March 31,				Year ended December 31,

	2015		2014		2014		2013		2012
United States (MBoe/d)
Eagle Ford Shale		54.7		46.5		50.9		36.6		20.1
Wolfcamp Shale		17.9		11.9		15.3		5.5		2.0
Altamont		17.1		13.4		15.5		11.9		10.6
Haynesville Shale		12.6		18.7		15.9		27.1		48.4
Other		0.1		0.2		0.1		0.1		1.3
Divested assets(1)		—		—		—		6.0		31.4

Total Combined		102.4		90.7		97.7		87.2		113.8



Oil (MBbls/d)
Consolidated volumes		60.0		48.6		54.8		36.2		22.7
Divested assets(1)		—		—		—		0.6		2.0

Total Combined		60.0		48.6		54.8		36.8		24.7

					��

Natural Gas (MMcf/d)
Consolidated volumes		185		197		190		230		341
Divested assets(1)		—		—		—		28		161

Total Combined		185		197		190		258		502



NGLs (MBbls/d)
Consolidated volumes		11.6		9.3		11.3		6.7		3.0
Divested assets(1)		—		—		—		0.9		2.4

Total Combined		11.6		9.3		11.3		7.6		5.4

(1): 2013 volumes include 6.0 MBoe/d, 0.5 MBbls/d of oil, 165 MMcf/d of natural gas and 0.9 MBbls/d of NGLs from Four Star Oil & Gas Company (Four Star), our equity investment sold in September 2013. 2012 volumes include 9.1 MBoe/d, 0.8 MBbls/d of oil, 42 MMcf/d of natural gas and 1.3 MBbls/d of NGLs from Four Star. Remaining volumes are from our Arklatex and South Louisiana Wilcox areas sold in 2014, CBM and South Texas assets sold in 2013, and our Gulf of Mexico assets, which were sold in 2012. For periods after May 24, 2012, Arklatex, South Louisiana Wilcox, CBM and South Texas assets are treated as discontinued operations and accordingly volumes relating to those assets are excluded from all financial and non-financial metrics. In addition, our Brazilian operations are treated as discontinued operations in all periods and, accordingly, volumes are excluded from all financial and non-financial metrics for both predecessor and successor periods.

•: Eagle Ford Shale—Our Eagle Ford Shale equivalent volumes and oil production increased 8.2 MBoe/d (18%) and 6.4 MBbls/d (20%), respectively, for the quarter ended March 31, 2015 compared to the same period in 2014 due to the success of our drilling program in the area. During the quarter ended March 31, 2015, we completed 38 additional operated wells in the Eagle Ford, and we had a total of 439 net operated wells as of March 31, 2015. With a majority of our acreage located in the core of the oil window, primarily in LaSalle county, we continue to grow our oil and NGLs production in the area

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•: Wolfcamp Shale—Our Wolfcamp Shale equivalent volumes increased 6.0 MBoe/d (50%) for the quarter ended March 31, 2015 compared to the same period in 2014 as we continue to progress the development of the program. During the quarter ended March 31, 2015, we completed 10 additional operated wells, for a total of 214 net operated wells as of March 31, 2015.
•: Altamont—Our Altamont equivalent volumes increased 3.7 MBoe/d (28%) for the quarter ended March 31, 2015 compared to the same period in 2014. Altamont produced an average of 12.5 MBbls/d of oil during the quarter ended March 31, 2015, and we completed 9 additional operated oil wells for a total of 368 net operated wells at March 31, 2015.
•: Haynesville Shale—Our Haynesville Shale equivalent volumes decreased 36 MMcf/d (32%) for the quarter ended March 31, 2015 compared to the same period in 2014, due to natural production declines. We have allocated a portion of our capital budget in 2015 to our Haynesville drilling program based on its returns in the forecasted commodity price environment. As of March 31, 2015, we had 99 net operated wells in the Haynesville Shale, and our total natural gas production for the first quarter of 2015 was approximately 76 MMcf/d.

Reserve Replacement Ratio/Reserve Replacement Costs

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


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

(1): Reserve additions include proved reserves and reflect reserve revisions for prices and performance, extensions, discoveries and other additions and acquisitions and do not include unproved reserve quantities. We present these metrics separately, both including and excluding the impact of price revisions on reserves, to demonstrate the effectiveness of our drilling program exclusive of economic factors (such as price) outside of our control. All amounts are derived directly from the table presented in "Audited Consolidated Financial Statements—Supplemental Oil and Natural Gas Operations (Unaudited)."
(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 costs. Amounts are derived directly from the table presented in "Audited Consolidated Financial Statements—Supplemental Oil and Natural Gas Operations (Unaudited)" which includes both successor and predecessor capital costs. For 2012, capital costs utilized in this ratio reflect the combined predecessor and successor periods as further described in Results of Operations below. We do not include estimated future capital costs for the development of proved undeveloped reserves in our calculation of reserve replacement

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costs. See "Business—Oil and Natural Gas Properties—Oil, Natural Gas and NGLs Reserves and Production—Proved Undeveloped Reserves (PUDs)" for the estimated amounts in our December 31, 2014 internal reserve report to be spent in 2015, 2016 and 2017 to develop our proved undeveloped reserves.

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

The exploration for and the acquisition and development of oil and natural gas reserves is inherently uncertain as further discussed in "Risk Factors—Risks Related to Our Business and Industry." One of these risks and uncertainties is our ability to spend sufficient capital to increase our reserves. While we currently expect to spend such amounts in the future, there are no assurances as to the timing and magnitude of these expenditures or the classification of the proved reserves as developed or undeveloped. At December 31, 2014, proved developed reserves represented approximately 38% of our total proved reserves. Proved developed reserves will generally begin producing within the year they are added, whereas proved undeveloped reserves generally require additional future expenditures.

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

	Including Price Revisions									Excluding Price Revisions(1)

	2014			2013			2012			2014			2013			2012
Reserve Replacement Ratios(2)		343	%		476	%		47	%		254	%		464	%		298	%
Proved Developed Reserves(3)		38	%		33	%		46	%		38	%		33	%		46	%
Proved Undeveloped Reserves(3)		62	%		67	%		54	%		62	%		67	%		54	%
Reserve Replacement Costs(2)(4)($/Boe)	$	16.93		$	12.62		$	67.56		$	22.85		$	12.95		$	10.74

(1): Final reported proved undeveloped reserves generated positive undiscounted cash flow in each respective report year.
(2): For the year ended December 31, 2014, reserve replacement ratio and reserve replacement costs including acquisitions and price revisions were 363% and $16.90 per Boe, and excluding price revisions were 274% and $22.37 per Boe. No acquisitions are included in our reserve replacement ratio or reserve replacement costs for the years ended December 31, 2013 and 2012, as any such amounts are immaterial to the amounts presented.
(3): Represents our net proved reserve percentage by classification based on our internal reserve reports.
(4): Proved and unproved leasehold costs are included in all calculations.

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We typically cite reserve replacement costs in the context of a multi-year trend, in recognition of its limitation as a single year measure, and also to demonstrate consistency and stability, which are essential to our business model. The table below shows our reserve replacement costs for our domestic operations for the three years ended December 31, 2014.

	Including Price Revisions		Excluding Price Revisions

	Three years ended December 31, 2014
	($/Boe)
Reserve Replacement Costs
Excluding acquisitions	$	18.64	$	14.47
Including acquisitions	$	18.59	$	14.51

Results of Operations

The information below reflects financial results for EP Energy LLC for the quarters ended March 31, 2015 and 2014, and the years ended December 31, 2014 and 2013, for the period from March 23 (inception) to December 31, 2012, and for the period from January 1 to May 24, 2012. Our financial results, beginning with the Acquisition on May 24, 2012, reflect the application of the acquisition method of accounting, the application of the successful efforts method of accounting for oil and natural gas properties, and the presentation of certain domestic natural gas assets divested in 2014 and 2013 and the sale of our Brazilian operations as discontinued operations. For periods prior to the Acquisition or the predecessor periods, we have not reflected these divested domestic natural gas assets as discontinued operations since they did not qualify as such for accounting purposes under the full cost accounting method applied by the predecessor during those periods. We have reflected our Brazilian operations as discontinued operations in all periods. As a result, trends and results in periods after the Acquisition and future periods may be different than those prior to the Acquisition.

Prior to the Acquisition, we had no independent oil and gas operations, and accordingly there were no operational exploration and production activities that changed as a result of the Acquisition. Consequently, in certain period-to-period explanations that follow we have provided supplemental information that compares (i) results for the year ended December 31, 2014 with results for the year ended December 31, 2013 and (ii) results for the year ended December 31, 2013 with results for the successor period from March 23 (inception) to December 31, 2012 and for the predecessor period from January 1 to May 24, 2012 on a combined basis and excluding divested assets (such combined period is referred to as the "combined year ended December 31, 2012"). We have provided this additional analysis for comparability of results and to aid in the analysis and understanding of our operating performance period over period. Any non-GAAP analysis is provided as supplemental financial information to our GAAP results and is not intended to be a substitute for our reported successor and predecessor period GAAP results.

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Year-to-Date Period Ended March 31, 2015 to Year-To-Date Period Ended March 31, 2014

The information in the table below provides a summary of our generally accepted accounting principles (GAAP) financial results.

	Quarters ended March 31,

	2015			2014
	(in millions)
Operating revenues
Oil	$	229		$	406
Natural gas		48			78
NGLs		13			27

Total physical sales		290			511
Financial derivatives		203			(135	)

Total operating revenues		493			376



Operating expenses
Natural gas purchases		7			3
Transportation costs		27			23
Lease operating expense		47			44
General and administrative		47			49
Depreciation, depletion and amortization		224			192
Exploration and other expense		6			8
Taxes, other than income taxes		22			33

Total operating expenses		380			352

Operating income		113			24
Interest expense		(84	)		(77	)

Income (loss) from continuing operations, before income taxes		29			(53	)
Income tax expense		10			—

Income (loss) from continuing operations		19			(53	)
Income from discontinued operations, net of tax		—			17

Net income (loss)	$	19		$	(36	)

Operating Revenues

The table below provides our operating revenues, volumes and prices per unit for the quarters ended March 31, 2015 and 2014. We present (i) average realized prices based on physical sales of oil,

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natural gas and NGLs as well as (ii) average realized prices inclusive of the impacts of financial derivative settlements and premiums which reflect cash received or paid during the respective period.

	Quarters ended March 31,

	2015		2014
	(in millions)
Operating revenues:
Oil	$	229	$	406
Natural gas		48		78
NGLs		13		27

Total physical sales		290		511
Financial derivatives		203		(135	)

Total operating revenues	$	493	$	376



Volumes:
Oil (MBbls)		5,402		4,373
Natural gas (MMcf)		16,628		17,699
NGLs (MBbls)		1,044		843

Equivalent volumes (MBoe)		9,218		8,166



Total MBoe/d		102.4		90.7



Consolidated prices per unit(1):
Oil
Average realized price on physical sales ($/Bbl)(2)	$	42.40	$	92.83
Average realized price, including financial derivatives ($/Bbl)(2)(3)	$	78.39	$	91.20
Natural gas
Average realized price on physical sales ($/Mcf)(2)	$	2.51	$	4.21
Average realized price, including financial derivatives ($/Mcf)(3)	$	3.69	$	3.26
NGLs
Average realized price on physical sales ($/Bbl)	$	12.04	$	32.29
Average realized price, including financial derivatives ($/Bbl)(3)	$	12.26	$	31.40

(1): Natural gas prices for the quarters ended March 31, 2015 and 2014 are calculated including a reduction of $7 million and $3 million, respectively, for natural gas purchases associated with managing our physical sales.
(2): Changes in realized oil and natural gas prices reflect the effects of unfavorable unhedged locational or basis differentials, unhedged volumes and contractual deductions between the commodity price index and the actual price at which we sold our oil and natural gas.
(3): The quarters ended March 31, 2015 and 2014, include approximately $194 million of cash received and $7 million of cash paid, respectively, for the settlement of crude oil derivative contracts and approximately $20 million of cash received and $17 million of cash paid, respectively, for the settlement of natural gas financial derivatives. The quarters ended March 31, 2015 and 2014, include less than $1 million and approximately $1 million, respectively, of cash paid for the settlement of NGLs derivative contracts. No cash premiums were received for the quarter ended March 31, 2015. Cash premiums received for the quarter ended March 31, 2014 were less than $1 million.

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Physical sales. Physical sales represent accrual-based commodity sales transactions with customers. For the quarter ended March 31, 2015, physical sales decreased by $221 million (43%) compared to the same period in 2014. Physical sales have decreased due to lower commodity prices partially offset by oil volume growth from our Eagle Ford, Wolfcamp and Altamont drilling programs. The table below displays the price and volume variances on our physical sales when comparing the quarters ended March 31, 2015 and 2014.

	Oil			Natural gas			NGLs			Total

	(in millions)
March 31, 2014 sales	$	406		$	78		$	27		$	511
Change due to prices		(272	)		(25	)		(21	)		(318	)
Change due to volumes		95			(5	)		7			97

March 31, 2015 sales	$	229		$	48		$	13		$	290

Oil sales for the quarter ended March 31, 2015 compared to the same period in 2014 decreased by $177 million (44%) due primarily to lower oil prices partially offset by oil volume growth from our Eagle Ford, Wolfcamp and Altamont drilling programs. For the quarter ended March 31, 2015 compared to the same period in 2014, Eagle Ford oil production increased by 20% (6.4 MBbls/d), Wolfcamp oil production increased by 32% (2.3 MBbls/d), and Altamont oil production increased by 28% (2.7 MBbls/d).

Natural gas sales decreased for the quarter ended March 31, 2015 compared to the same period in 2014 primarily due to lower natural gas prices and a decrease in volumes due to natural production declines in the Haynesville Shale, despite natural gas volume growth in Eagle Ford, Wolfcamp and Altamont.

Our oil and natural gas is typically sold at index prices (WTI, LLS and Henry Hub) or posted prices at various delivery points across our producing basins. Realized prices received (not considering the effects of hedges) are generally less than the stated index price as a result of contractual deducts, differentials from the index to the delivery point and/or discounts for quality or grade. Generally as the index price of our commodities increase, deducts and differentials widen and can further widen for temporary or permanent changes in supply or demand, capacity constraints or the build out of infrastructure in developing areas.

In the Eagle Ford, our oil is sold at prices tied to benchmark LLS crude oil. In Wolfcamp, physical barrels are generally sold at the WTI Midland Index, which trades at a spread to WTI Cushing. In Altamont, market pricing of our oil is based upon both Salt Lake City refinery postings and rail economics, which reflect transportation and handling costs associated with moving wax crude by truck and/or rail to end users. Across all regions, natural gas realized pricing is influenced by factors such as excess royalties paid on flared gas and the percentage of proceeds retained under processing contracts, in addition to the normal seasonal supply and demand influences and those factors discussed above. The table below displays the weighted average differentials and deducts on our oil and natural gas sales on an average NYMEX price.

	Quarters ended March 31,

	2015						2014
	Oil (Bbl)			Natural gas (MMBtu)			Oil (Bbl)			Natural gas (MMBtu)
Differentials and deducts	$	(6.49	)	$	(0.50	)	$	(5.70	)	$	(0.58	)
NYMEX	$	48.63		$	2.98		$	98.69		$	4.94

The larger oil differentials and deducts in the quarter ended March 31, 2015 were generally a result of a decrease in LLS pricing relative to NYMEX in Eagle Ford, a widening Midland Cushing

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discount and new contract deductions in Wolfcamp, and higher deducts in Altamont due to increased rail transport instead of deliveries by truck to refineries as a result of refinery maintenance in the first quarter of 2015. The smaller gas differentials and deducts in the quarter ended March 31, 2015 were generally a result of lower excess royalties paid on flared gas.

NGLs sales decreased for the quarter ended March 31, 2015 compared to the same period in 2014. Average realized prices declined in 2015 compared to the same period in 2014, due in part to lower pricing on all liquids components. NGLs volume increased as a result of our Eagle Ford and Wolfcamp drilling programs. For the quarter ended March 31, 2015 compared to the same period in 2014, Eagle Ford NGLs volumes increased by 13% (0.9 MBbls/d) and Wolfcamp NGLs volumes increased by 63% (1.5 MBbls/d).

As of March 31, 2015, the NYMEX spot price of a barrel of oil was $47.60 versus the NYMEX spot price of a MMBtu of natural gas of $2.64, or a ratio of 18 to 1. Despite further recent declines in oil prices, the value difference between these commodities is such that we will continue to target increases in our oil volumes in our capital budget. Growth in our overall oil sales (including the impact of financial derivatives) will largely be impacted by our ability to grow these volumes and will also be impacted by commodity pricing to the extent we are unhedged and by the location of our production and the nature of our sales contracts. Based on our hedges in place as of March 31, 2015, we are approximately 96% hedged (based on the midpoint of our 2015 production guidance) at a weighted average price of $91.16 per barrel for the remainder of 2015. These hedge positions consist of 95% fixed price swaps and three way collars (locking in $15.00 per barrel in excess of market prices should Brent settle below $85.00) comprising the remaining positions.

Gains or losses on financial derivatives. We record 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. We realize such gains or losses when we settle the derivative position. During the quarter ended March 31, 2015, we recorded $203 million of derivative gains compared to derivative losses of $135 million during the quarter ended March 31, 2014.

Operating Expenses

Transportation costs. Transportation costs for the quarters ended March 31, 2015 and 2014 were $27 million and $23 million, respectively. Total transportation costs have increased for the quarter ended March 31, 2015 primarily due to oil transportation costs associated with Eagle Ford and Wolfcamp as a result of our production growth and new contracts in these areas.

Lease operating expense. Lease operating expense for the quarters ended March 31, 2015 and 2014 were $47 million and $44 million, respectively. Total lease operating expense increased in the first quarter of 2015 compared to the same period in 2014 due to higher disposal, maintenance and compression costs in Wolfcamp by approximately $7 million associated with growing production volumes in this area, offset by a decrease in lease operating expense of approximately $4 million in Eagle Ford mainly due to lower chemical and power costs.

General and administrative expenses. General and administrative expenses for the quarters ended March 31, 2015 and 2014 were $47 million and $49 million, respectively. The overall decrease of $2 million for the quarter ended March 31, 2015, reflects lower payroll, benefits and administrative costs of $5 million compared to the same period in 2014 from lower headcount. Additionally, in 2014 we paid advisory fees of $6.25 million to our Sponsors. Partially offsetting these items were transition and restructuring costs of $8 million recorded during the first quarter of 2015.

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Depreciation, depletion and amortization expense. Depreciation, depletion and amortization expense for the quarters ended March 31, 2015 and 2014 were $224 million and $192 million, respectively. Our depreciation, depletion and amortization costs increased in the first quarter of 2015 compared to the same period in 2014 due to an increase in production volumes from the ongoing development of higher cost oil programs (e.g., Eagle Ford and Wolfcamp) and slightly higher depletion rates. We expect our depletion rate will continue to increase compared to our current levels as a result of this ongoing development of our higher cost oil programs. Our average depreciation, depletion and amortization costs per unit for the quarters ended March 31 were:

	Quarters ended March 31,

	2015		2014
Depreciation, depletion and amortization ($/Boe)(1)	$	24.30	$	23.47

(1): Includes $0.07 per Boe for both of the quarters ended March 31, 2015 and 2014 related to accretion expense on asset retirement obligations.

Exploration and other expense. For the quarter ended March 31, 2015, we recorded $6 million of exploration expense compared to $8 million for the same period in 2014. Included in exploration expense for the quarters ended March 31, 2015 and 2014 is $4 million and $7 million, respectively, of amortization of unproved leasehold costs. In addition, in the first quarter of 2015, we recorded approximately $2 million as other expense in conjunction with the early termination of a contract for drilling rigs.

Taxes, other than income taxes. Taxes, other than income taxes for the quarters ended March 31, 2015 and 2014 were $22 million and $33 million, respectively. Production taxes decreased in the first quarter of 2015 compared to the same period in 2014 due to lower commodity prices which have a significant impact on severance taxes.

Cash Operating Costs and Adjusted Cash Operating Costs. We monitor cash operating costs required to produce our oil and natural gas. Cash operating costs is a non-GAAP measure calculated on a per Boe basis and includes total operating expenses less depreciation, depletion and amortization expense, transportation costs, exploration expense, natural gas purchases and other expenses. Adjusted cash operating costs is a non-GAAP measure and is defined as cash operating costs less transition, restructuring and other non-recurring costs, management and other fees paid to the Sponsors (which terminated on January 23, 2014), and the non-cash portion of compensation expense (which represents compensation expense under long-term incentive programs adjusted for cash payments made under long-term incentive plans). We believe cash operating costs and adjusted cash operating costs per unit are valuable measures of operating performance and efficiency; however, these measures may not be comparable to similarly titled measures used by other companies. The table below represents a

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reconciliation of our cash operating costs and adjusted cash operating costs to operating expenses for the quarters ended March 31:

	Quarters ended March 31,

	2015						2014
	Total			Per Unit(1)			Total			Per Unit(1)
	(in millions, except per unit costs)
Total continuing operating expenses	$	380		$	41.24		$	352		$	43.13
Depreciation, depletion and amortization		(224	)		(24.30	)		(192	)		(23.47	)
Transportation costs		(27	)		(2.90	)		(23	)		(2.85	)
Exploration expense(2)		(5	)		(0.51	)		(8	)		(0.99	)
Natural gas purchases		(7	)		(0.74	)		(3	)		(0.43	)

Total continuing cash operating costs		117			12.79			126			15.39
Transition/restructuring costs, non-cash portion of compensation expense and other(3)		(12	)		(1.38	)		(16	)		(1.94	)

Total adjusted cash operating costs and adjusted per-unit cash operating costs	$	105		$	11.41		$	110		$	13.45



Total equivalent volumes (MBoe)		9,218						8,166

(1): Per unit costs are based on actual total amounts rather than the rounded totals presented.
(2): Represents exploration expense only.
(3): For the quarter ended March 31, 2015, amount includes approximately $8 million of transition and severance costs related to restructuring and $5 million of non-cash compensation expense. For the quarter ended March 31, 2014, amount includes $6 million of management and other fees paid to our Sponsors, $9 million of non-cash compensation expense and $1 million of transition and severance costs related to restructuring. The non-cash portion of compensation expense represents non-cash compensation expense under long-term incentive programs adjusted for cash payments made under long-term incentive plans.

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

	Quarters ended March 31,

	2015			2014
Average cash operating costs ($/Boe)
Lease operating expenses	$	5.12		$	5.42
Production taxes(1)		2.13			3.72
General and administrative expenses(2)		5.06			5.97
Taxes, other than production and income taxes		0.28			0.28
Other expenses(3)		0.20			—

Total cash operating costs		12.79			15.39
Transition/restructuring costs, non-cash portion of compensation expense and other(2)		(1.38	)		(1.94	)

Total adjusted cash operating costs	$	11.41		$	13.45

(1): Production taxes include ad valorem and severance taxes which decreased during the quarter ended March 31, 2015 due to lower commodity prices.
(2): For additional detail of items included in general and administrative expenses, refer to the reconciliation of cash operating costs and adjusted cash operating costs above.
(3): Includes early rig termination fees of $2 million.

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Other Income Statement Items.

Interest expense. Interest expense for the quarter ended March 31, 2015 increased by $7 million compared to the same period in 2014 due to higher interest expense related to our RBL Facility and the additional losses in 2015 compared to 2014 due to changes in fair market value of our interest rate derivative instruments.

Income taxes. On December 31, 2014, we simplified our structure and became a division of a corporation subject to federal and state income taxes. Our effective tax rate for the quarter ended March 31, 2015 includes the effects of state income taxes and non-deductible compensation expense. For the quarter ended March 31, 2014, we were a partnership not subject to federal and state income taxes.

Income from discontinued operations. Our income from discontinued operations for the quarter ended March 31, 2014 includes the financial results of assets classified as discontinued operations and any gain (loss) recorded on the sale of these non-core domestic natural gas and other assets in 2014.

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Year Ended December 31, 2014 to Year Ended December 31, 2013, and Year Ended December 31, 2013 to Year Ended December 31, 2012

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

	Year-to-Date Periods

	2014			2013			2012
	Successor									Predecessor
	Year ended December 31,			Year ended December 31,			March 23 (inception) to December 31			January 1 to May 24
				(in millions)
Operating revenues:
Oil	$	1,705		$	1,254		$	499		$	310
Natural gas		284			300			216			228
NGLs		110			74			28			29

Total physical sales		2,099			1,628			743			567
Financial derivatives		985			(52	)		(62	)		365

Total operating revenues		3,084			1,576			681			932

Operating expenses:
Natural gas purchases		23			25			19			—
Transportation costs		100			85			48			45
Lease operating expenses		193			147			63			80
General and administrative		160			228			358			69
Depreciation, depletion and amortization		875			585			188			307
Impairment and ceiling test charges		2			2			1			62
Exploration and other expense		25			41			40			—
Taxes, other than income taxes		129			79			36			31

Total operating expenses		1,507			1,192			753			594

Operating income (loss)		1,577			384			(72	)		338
Other income (expense)		1			(12	)		(1	)		(3	)
Loss on extinguishment of debt		—			(9	)		(14	)		—
Interest expense		(316	)		(321	)		(218	)		(14	)

Income (loss) from continuing operations before income taxes		1,262			42			(305	)		321
Income tax expense		1,121			—			—			134

Income (loss) from continuing operations		141			42			(305	)		187
Income (loss) from discontinued operations, net of tax		7			507			50			(9	)

Net income (loss)	$	148		$	549		$	(255	)	$	178

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Operating Revenues

The table below provides our operating revenues, volumes and prices per unit for the years ended December 31, 2014 and 2013, and for each of the successor and predecessor periods in 2012. We present (i) average realized prices based on physical sales of oil, natural gas and NGLs as well as (ii) average realized prices inclusive of the impacts of financial derivative settlements and premiums which reflect cash received or paid during the respective period.

	Year-to-Date Periods

	2014		2013			2012
	Successor								Predecessor
	Year ended December 31,		Year ended December 31,			March 23 (inception) to December 31			January 1 to May 24
						(in millions)
Operating revenues(1):
Oil	$	1,705	$	1,254		$	499		$	310
Natural gas		284		300			216			228
NGLs		110		74			28			29

Total physical sales		2,099		1,628			743			567
Financial derivatives		985		(52	)		(62	)		365

Total operating revenues	$	3,084	$	1,576		$	681		$	932



Volumes(2):
Oil (MBbls)(2)		19,985		13,432			5,824			3,220
Natural gas (MMcf)(2)		69,434		93,866			82,743			101,157
NGLs (MBbls)(2)		4,116		2,761			1,122			863

Equivalent volumes (MBoe)(2)		35,673		31,837			20,736			20,943



Total MBoe/d(2)		97.7		87.2			93.8			144.4



Consolidated prices per unit(3):
Oil
Average realized price on physical sales ($/Bbl)(4)	$	85.31	$	94.75		$	88.17		$	99.76
Average realized price, including financial derivatives ($/Bbl)(4)(5)	$	88.77	$	97.56		$	95.59		$	99.61
Natural gas
Average realized price on physical sales ($/Mcf)(4)	$	3.76	$	3.28		$	2.68		$	2.40
Average realized price, including financial derivatives ($/Mcf)(4)(5)	$	3.34	$	2.97		$	5.05		$	4.15
NGLs
Average realized price on physical sales ($/Bbl)	$	26.73	$	30.58		$	33.47		$	42.94
Average realized price, including financial derivatives ($/Bbl)(5)	$	27.78	$	—		$	—		$	—

(1): Operating revenues and volumes in the successor periods do not include amounts associated with domestic natural gas assets sold. All periods presented do not include Brazilian operations sold in 2014.
(2): In September 2013, we sold our equity investment in Four Star. For the year ended December 31, 2013, the period from March 23 to December 31, 2012 and the predecessor period from January 1 to May 24, 2012, Four Star's production volumes were 197 MBbls, 167 MBbls and 115 MBbls of oil; 10,050 MMcf, 9,242 MMcf and 6,310 MMcf of natural gas; 327 MBbls, 288 MBbls and 190 MBbls of NGLs; and 2,199 MBoe (6.0 MBoe/d), 1,995 MBoe (9.0 MBoe/d) and 1,357 MBoe (9.4 MBoe/d) of equivalent volumes, respectively.

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(3): Natural gas prices for the years ended December 31, 2014 and 2013 and from March 23 to December 31, 2012 are calculated including a reduction of $23 million, $25 million and $19 million, respectively, for natural gas purchases associated with managing our physical sales. Prices per unit are based on consolidated volumes and do not include volumes associated with Four Star which was sold in September 2013.
(4): Changes in realized oil and natural gas prices reflect the effects of unfavorable unhedged locational or basis differentials and contractual deductions between the commodity price index and the actual price at which we sold our oil and natural gas.
(5): The years ended December 31, 2014 and 2013 and from March 23 to December 31, 2012 include approximately $30 million of cash paid, $28 million of cash paid and approximately $175 million of cash received for the settlement of natural gas financial derivatives. The predecessor period from January 1 to May 24, 2012 includes approximately $165 million of cash received for the settlement of natural gas financial derivatives. The years ended December 31, 2014 and 2013 and the period from March 23 to December 31, 2012 include approximately $69 million, $29 million and $45 million, respectively, of cash receipts 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, 2014, physical sales increased by $471 million (29%), compared to the year ended December 31, 2013. For the year ended December 31, 2013, physical sales increased by $318 million (24%) compared to the combined year ended December 31, 2012. Physical sales have increased primarily due to oil volume growth from our Eagle Ford and Wolfcamp drilling programs, partially offset by decreases in natural gas sales in Haynesville. The table below displays the price and volume variances on our physical sales when comparing the years ended December 31, 2014 and 2013.

	Oil			Natural gas			NGLs			Total

	(in millions)
December 31, 2013 sales	$	1,254		$	300		$	74		$	1,628
Change due to prices		(188	)		35			(16	)		(169	)
Change due to volumes		639			(51	)		52			640

December 31, 2014 sales	$	1,705		$	284		$	110		$	2,099

Oil sales for the year ended December 31, 2014, compared to the year ended December 31, 2013, increased by $451 million (36%), mainly from growth in our Eagle Ford drilling program. In 2014, Eagle Ford oil production volumes increased by 45% (10.8 MBbls/d) compared with the year ended December 31, 2013. In addition, Wolfcamp oil production volumes increased by 143% (5.0 MBbls/d). For the year ended December 31, 2013, oil sales increased by $445 million compared to the combined year ended December 31, 2012 attributable to a 60% increase (13.6 MBbls/d) in consolidated oil volumes in our Eagle Ford, Wolfcamp and Altamont operating areas.

Natural gas sales decreased for the year ended December 31, 2014 compared with the year ended December 31, 2013, due to the decrease in volumes in Haynesville as a result of suspending the drilling program in 2012, partially offset by higher natural gas prices. Natural gas sales decreased for the year ended December 31, 2013 compared with the combined year December 31, 2012 (excluding amounts related to divested assets) primarily due to lower natural gas prices and the decrease in volumes in Haynesville.

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temporary or permanent changes in supply or demand, capacity constraints or the build out of infrastructure in developing areas.

	Years ended December 31,

	2014						2013
	Oil (Bbl)			Natural gas (MMBtu)			Oil (Bbl)			Natural gas (MMBtu)
Differentials and deducts	$	(7.69	)	$	(0.60	)	$	(3.35	)	$	(0.32	)
NYMEX	$	92.99		$	4.41		$	97.97		$	3.65

The larger differentials and deducts in the year ended December 31, 2014 were generally a result of wider basis differentials in areas currently facing oversupply due to a combination of temporary refinery outages and insufficient takeaway capacity along with slightly higher market prices of natural gas.

NGLs sales increased for the year ended December 31, 2014 compared with the year ended December 31, 2013 and for the year ended December 31, 2013 compared to the combined year ended December 31, 2012. Although average realized prices decreased in 2014 and 2013 compared to the previous years, NGLs volume increases have more than offset the price decline primarily as a result of our Eagle Ford drilling program. Eagle Ford NGLs volumes increased by 34% (2.0 MBbls/d) over the year ended December 31, 2013.

As of December 31, 2014, the NYMEX spot price of a barrel of oil was $53.27 versus the NYMEX spot price of natural gas of $2.89, or a ratio of 18 to 1. Despite further declines in oil prices, the value difference between these commodities is such that we will continue to target increases in our oil volumes in our capital budget. Growth in our overall oil sales (including the impact of financial derivatives) will largely be impacted by our ability to grow these volumes, and will also be impacted by commodity pricing to the extent we are unhedged and by the nature of our hedge contracts. Based on our hedges in place as of December 31, 2014, we are approximately 96% hedged (based on the midpoint of our 2015 production guidance) at $91.19 per barrel for 2015. These hedge positions consist of 95% fixed price swaps and three way collars (locking in $15 per barrel in excess of market prices should NYMEX settle below $85.00) comprising the remaining hedge positions. For additional details on our 2015 production guidance and hedge program, refer to "Our Business" below.

Gains or losses on financial derivatives. We record 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. We realize such gains or losses when we settle the derivative position. During the year ended December 31, 2014, we recorded $985 million of derivative gains compared to a derivative loss of $52 million during the year ended December 31, 2013. Realized and unrealized gains for the combined year ended December 31, 2012 were $303 million of derivative gains.

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Operating Expenses

Transportation costs. Transportation costs for the years ended December 31, 2014 and 2013, and for the period from March 23 to December 31, 2012 were $100 million, $85 million and $48 million, respectively, and for the predecessor period from January 1 to May 24, 2012 were $45 million (including $20 million of transportation costs related to divested assets). Total transportation costs (excluding amounts related to the divested assets) have increased over the three year period beginning in 2012 due to oil transportation costs associated with Eagle Ford and Wolfcamp as a result of our production growth and new contracts in these areas.

Lease operating expense. Lease operating expense for the years ended December 31, 2014 and 2013, and for the period from March 23 to December 31, 2012 were $193 million, $147 million and $63 million, respectively, and for the predecessor period from January 1 to May 24, 2012 were $80 million (including $36 million of lease operating expense related to divested assets). Total lease operating expense has increased in 2014 due to higher chemical, maintenance, disposal, repair and power costs in Eagle Ford, higher chemical, disposal and compression costs in Wolfcamp and higher chemical, disposal and power costs in Altamont associated with growing production volumes in these areas. Lease operating expense for the year ended December 31, 2013 increased compared to the combined year ended December 31, 2012 (excluding amounts related to divested assets) due to increased equipment and chemical costs in our Eagle Ford play and higher maintenance, repair and power costs.

General and administrative expenses. General and administrative expense for the years ended December 31, 2014 and 2013, and for the period from March 23 to December 31, 2012 were $160 million, $228 million and $358 million, respectively, and for the predecessor period from January 1 to May 24, 2012 were $69 million. General and administrative expenses for the year ended December 31, 2014 decreased $68 million compared to the year ended December 31, 2013. While the year ended December 31, 2014, reflects lower payroll, benefits and administrative costs of $39 million compared to the year ended December 31, 2013 and an $11 million reduction in general and administrative expenses associated with an insurance settlement, also affecting 2014 were advisory fees paid in January to our Sponsors of $6.25 million compared to $26 million paid in 2013.

General and administrative expenses for the year ended December 31, 2013 decreased $199 million compared to the combined year 2012 primarily due to the transition and restructuring costs of $221 million ($173 million of acquisition related costs and $48 million of transition and severance costs) recorded in 2012 as a result of the Acquisition, partly offset by an increase of $11 million in management consulting and advisory service charges reflected for the year ended December 31, 2013. Prior to the Acquisition, El Paso allocated general and administrative costs to us based on the estimated level of resources devoted to our operations and the relative size of our earnings before interest and taxes, gross property and payroll.

Depreciation, depletion and amortization expense. Depreciation, depletion and amortization expense for the years ended December 31, 2014 and 2013, and for the period from March 23 to December 31, 2012 were $875 million, $585 million and $188 million, respectively, and for the predecessor period from January 1 to May 24, 2012 were $307 million. Our depreciation, depletion and amortization costs have increased over the three year period beginning in 2012 due to increases in production volumes and the ongoing development of higher cost oil programs (e.g. Eagle Ford and Wolfcamp). Depreciation, depletion and amortization for the year ended December 31, 2013 also reflects the step up in 2012 in the book basis of our oil and natural gas assets as a result of the Acquisition. We expect our depletion rate will continue to increase as compared to our current levels as

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a result of this ongoing development of our higher cost liquids programs. Our average depreciation, depletion and amortization costs per unit for the year-to-date periods were:

	Year-to-Date Periods

	2014		2013		2012
	Successor						Predecessor
	Year ended December 31,		Year ended December 31,		March 23 (inception) to December 31		January 1 to May 24

Depreciation, depletion and amortization ($/Boe)(1)	$	24.53	$	19.74	$	10.07	$	15.66

(1): Includes $0.07 per Boe for each of the years ended December 31, 2014 and 2013, $0.09 per Boe for the period from March 23 to December 31, 2012 and $0.23 per Boe for the predecessor period from January 1 to May 24, 2012 related to accretion expense on asset retirement obligations.

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

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

Exploration and other expense. Exploration and other expense for the year ended December 31, 2014 and 2013, and for the period from March 23 to December 31, 2012 were $25 million, $41 million and $40 million, respectively. Exploration expense is the result of applying the successful efforts method of accounting following the Acquisition. Prior to the Acquisition, exploration costs were capitalized under full cost accounting. Included in exploration expense for the year ended December 31, 2014 is $18 million of amortization of unproved leasehold costs. In addition, in 2014, we recorded approximately $3 million as other expense in conjunction with the early termination of a contract for drilling rig commitments.

Taxes, other than income taxes. Taxes, other than income taxes for the years ended December 31, 2014 and 2013, and for the period from March 23 to December 31, 2012, were $129 million, $79 million and $36 million, respectively, and for the predecessor period from January 1 to May 24, 2012 were $31 million (including approximately $14 million of taxes, other than income taxes related to divested assets). Production taxes have increased (excluding amounts related to divested assets) over the three year period beginning in 2012 due to higher severance taxes associated with growing production volumes in our oil producing areas. Additionally, year-to-date production taxes in 2013 reflect a reduction in sales and use tax of $13 million recorded in the second quarter of 2013 associated with settling a Texas sales and use tax audit.

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Cash Operating Costs and Adjusted Cash Operating Costs. We monitor cash operating costs required to produce our oil and natural gas. Cash operating costs is a non-GAAP measure calculated on a per Boe basis and includes total operating expenses less depreciation, depletion and amortization expense, transportation costs, exploration expense, natural gas purchases, impairments and ceiling test charges and other expenses. Adjusted cash operating costs is a non-GAAP measure and is defined as cash operating costs less transition, restructuring and other non-recurring costs, management and other fees paid to the Sponsors (which terminated on January 23, 2014), and the non-cash portion of compensation expense (which represents compensation expense under long-term incentive programs adjusted for cash payments made under long-term incentive plans). We believe cash operating costs and adjusted cash operating costs per unit are valuable measures of operating performance and efficiency; however, these measures may not be comparable to similarly titled measures used by other companies. The table below represents a reconciliation of our cash operating costs and adjusted cash operating costs to operating expenses for the year-to-date periods below:



	Year-to-Date Periods
	2014						2013						2012
	Successor																		Predecessor
	Year ended December 31,						Year ended December 31,						March 23 (inception) to December 31
																			January 1 to May 24
																			January 1 to May 24
	Total			Per Unit(1)			Total			Per Unit(1)			Total			Per Unit(1)			Total			Per Unit(1)
	Total			Per Unit(1)			Total			Per Unit(1)			Total			Per Unit(1)			Total			Per Unit(1)
							(in millions, except per unit costs)
Total continuing operating expenses	$	1,507		$	42.23		$	1,192		$	40.21		$	753		$	40.19		$	594		$	30.32
Depreciation, depletion and amortization		(875	)		(24.53	)		(585	)		(19.74	)		(188	)		(10.07	)		(307	)		(15.66	)
Transportation costs		(100	)		(2.81	)		(85	)		(2.85	)		(48	)		(2.54	)		(45	)		(2.32	)
Exploration expense(2)		(22	)		(0.62	)		(41	)		(1.39	)		(40	)		(2.13	)		—			—
Natural gas purchases		(23	)		(0.64	)		(25	)		(0.85	)		(19	)		(1.04	)		—			—
Impairment and ceiling test charges		(2	)		(0.05	)		(2	)		(0.06	)		(1	)		(0.06	)		(62	)		(3.15	)

Total continuing cash operating costs		485			13.58			454			15.32			457			24.35			180			9.19
Transition/restructuring costs, non-cash portion of compensation expense and other(3)		(11	)		(0.32	)		(64	)		(2.15	)		(266	)		(14.19	)		(11	)		(0.58	)

Total adjusted cash operating costs and adjusted per-unit cash costs(3)	$	474		$	13.26		$	390		$	13.17		$	191		$	10.16		$	169		$	8.61



Total equivalent volumes (MBoe)(4)		35,673						29,638						18,741						19,586

(1): Per unit costs are based on actual total amounts rather than the rounded totals presented.
(2): For the year ended December 31, 2014, amount does not include approximately $3 million recorded in conjunction with early rig termination fees included in exploration and other expense on our consolidated income statement.
(3): For the year ended December 31, 2014 amount includes $7 million of management and other fees paid to our Sponsors, $11 million of cash received from an insurance settlement, $5 million of acquisition costs, $9 million of non-cash compensation expense and $2 million of transition and severance costs related to restructuring. For the year ended December 31, 2013, includes $7 million of transition and severance costs associated with asset divestitures, management and other fees paid to our Sponsors of $26 million and $31 million of non-cash compensation expense. The period from March 23 (inception) to December 31, 2012 includes transition and severance costs of $215 million, management fees paid to our Sponsors of $16 million and $35 million of non-cash compensation expense. The predecessor period from January 1 to May 24, 2012 includes severance costs of $5 million and $6 million of non-cash compensation expense. The non-cash portion of compensation expense represents non-cash compensation expense under long-term incentive programs adjusted for cash payments made under long-term incentive plans.
(4): Excludes volumes associated with our equity investment in Four Star sold in September 2013.

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

	Year-to-Date Periods

	2014			2013			2012
	Successor									Predecessor
	Year ended December 31,			Year ended December 31,			March 23 (inception) to December 31			January 1 to May 24
Average cash operating costs ($/Boe)
Lease operating expenses	$	5.40		$	4.98		$	3.34		$	4.07
Production taxes(1)		3.39			2.84			1.88			1.79
General and administrative expenses(2)		4.47			7.68			19.07			3.53
Taxes, other than production and income taxes(3)		0.23			(0.18	)		0.06			(0.20	)
Other expense(4)		0.09			—			—			—

Total cash operating costs		13.58			15.32			24.35			9.19
Transition/restructuring costs, non-cash portion of compensation expense and other(2)		(0.32	)		(2.15	)		(14.19	)		(0.58	)

Total adjusted cash operating costs	$	13.26		$	13.17		$	10.16		$	8.61

(1): Production taxes include ad valorem and severance taxes which increased in 2014 primarily due to higher severance taxes associated with our higher oil production.
(2): For additional detail of items included in general and administrative expenses, refer to the reconciliation of cash operating costs and adjusted cash operating costs above.
(3): The year ended December 31, 2013 includes a reduction in sales and use taxes of $13 million associated with settling a sales and use tax matter.
(4): Recorded in conjunction with early rig termination fees.

Other Income Statement Items.

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

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

Interest expense. Interest expense for the year ended December 31, 2014 compared to 2013 decreased due to the repayment of approximately $500 million under our term loans in August 2013. Interest expense for the year ended December 31, 2013 compared to 2012 increased due to the issuance of approximately $4.25 billion of debt in conjunction with the Acquisition in May 2012. Prior to the Acquisition and related financing transactions, interest expense primarily related to borrowings under the predecessor's $1 billion credit facility in place at that time.

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Income taxes. On December 31, 2014, we simplified our structure and became a division of a corporation subject to federal and state income taxes. Upon the change in tax status, we recorded deferred income tax expense of $1,121 million as a result of recording net deferred tax liabilities for initial temporary differences at that time. No current tax liability or expense was incurred as of the date of the change in status. From May 25, 2012 until December 31, 2014, we were a limited liability company treated as a partnership for federal and state income tax purposes.

Income (loss) from discontinued operations. Our income (loss) from discontinued operations for the year ended December 31, 2014 includes the financial results of assets classified as discontinued operations and any gain (loss) recorded on the sale of these non-core domestic natural gas and other assets. Our income (loss) from discontinued operations for 2013 includes a $468 million gain on the sale of assets during 2013.

Supplemental Non-GAAP Measures

We use the non-GAAP measures "EBITDAX", "Adjusted EBITDAX" and "Pro Forma Adjusted EBITDAX" as supplemental measures. We believe these supplemental measures provide meaningful information to our investors. We define EBITDAX as income (loss) from continuing operations plus interest and debt expense, income taxes, depreciation, depletion and amortization and exploration expense. Adjusted EBITDAX is defined as EBITDAX, adjusted as applicable in the relevant period for the net change in the fair value of derivatives (mark-to-market effects of financial derivatives, net of cash settlements and premiums related to these derivatives), the non-cash portion of compensation expense (which represents non-cash compensation expense under long-term incentive programs adjusted for cash payments made under long-term incentive plans), transition, restructuring and other non-recurring costs, management and other fees paid to our Sponsors (which ended in 2014), losses on extinguishment of debt, equity earnings from Four Star prior to its sale in 2013, and impairment and ceiling test charges. Pro Forma Adjusted EBITDAX is defined as total Adjusted EBITDAX less Adjusted EBITDAX related to divested assets.

We believe that the presentation of EBITDAX, Adjusted EBITDAX and Pro Forma Adjusted EBITDAX is important to provide management and investors with additional information (i) to evaluate our ability to service debt adjusting for items required or permitted in calculating covenant compliance under our debt agreements, (ii) to provide an important supplemental indicator of the operational performance of our business, (iii) for evaluating our performance relative to our peers, (iv) to measure our liquidity (before cash capital requirements and working capital needs) and (v) to provide supplemental information about certain material non-cash and/or other items that may not continue at the same level in the future. EBITDAX, Adjusted EBITDAX and Pro Forma Adjusted EBITDAX have limitations as analytical tools and should not be considered in isolation or as a substitute for analysis of our results as reported under GAAP or as an alternative to net income (loss), income (loss) from continuing operations, operating income (loss), operating cash flows or other measures of financial performance or liquidity presented in accordance with GAAP.

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

	Successor															Predecessor

	Quarter ended March 31, 2015			Quarter ended March 31, 2014			Year ended December 31, 2014			Year ended December 31, 2013			March 23 (inception) to December 31, 2012			January 1 to May 24, 2012
	(in millions)
Net income (loss)	$	19		$	(36	)	$	148		$	549		$	(255	)	$	178
(Income) loss from discontinued operations, net of tax		—			(17	)		(7	)		(507	)		(50	)		9

Income (loss) from continuing operations		19			(53	)		141			42			(305	)		187
Income tax expense		10			—			1,121			—			—			134
Interest expense, net of capitalized interest		84			77			316			321			218			14
Depreciation, depletion and amortization		224			192			875			585			188			307
Exploration expense(1)		5			8			22			41			40			—

EBITDAX		342			224			2,475			989			141			642
Mark-to-market on financial derivatives(2)		(203	)		135			(985	)		52			62			(365	)
Cash settlements and premiums on financial derivatives(3)		214			(25	)		44			10			217			165
Non-cash portion of compensation expense(4)		5			9			9			31			35			6
Transition, restructuring and other costs(5)		8			1			(4	)		7			144			5
Fees paid to Sponsors(6)		—			6			6			26			87			—
Loss on extinguishment of debt(7)		—			—			—			9			14			—
Loss from unconsolidated affiliate(8)		—			—			—			13			1			5
Impairment and ceiling test charges		—			—			2			2			1			62

Adjusted EBITDAX		366			350			1,547			1,139			702			520
Less: Adjusted EBITDAX—divested assets(9)		—			—			—			—			5			83

Pro Forma Adjusted EBITDAX	$	366		$	350		$	1,547		$	1,139		$	697		$	437

(1): Represents exploration expense only.
(2): Represents the income statement impact of financial derivatives.
(3): Represents actual cash settlements received/(paid) related to financial derivatives, including cash premiums. No cash premiums were received for the quarter ended March 31, 2015. For the quarter ended March 31, 2014, we received less than $1 million of cash premiums. For the years ended December 31, 2014 and 2013, we received approximately $1 million and $9 million of cash premiums, respectively, and for the period from March 23 to December 31, 2012 we paid $3 million of cash premiums.
(4): Represents non-cash compensation expense under long-term incentive programs adjusted for cash payments under long-term incentive plans. For the quarters ended March 31, 2015 and 2014, cash payments were less than $1 million. For the years ended December 31, 2014 and 2013, cash payments were approximately $13 million and $10 million, respectively.
(5): Reflects transition and severance costs related to restructuring activities for the quarters ended March 31, 2015 and 2014. Reflects an $11 million insurance settlement and $5 million of acquisition costs as well as transition and severance costs related to restructuring for the year ended December 31, 2014, severance costs incurred in connection with divested assets in 2013 and transaction costs paid as part of the Acquisition in 2012.
(6): Represents management and other fees paid to the Sponsors.
(7): Represents the loss on extinguishment of debt recorded related to the redetermination of the RBL Facility and a partial repayment of the term loan in 2013 and the re-pricing of the term loan in 2012.
(8): Reflects the elimination of equity income (losses) recognized from Four Star, net of amortization of our purchase cost in excess of our equity interest in the underlying net assets, as a result of the sale of Four Star in September 2013.
(9): Consists of Adjusted EBITDAX related to assets that have been divested, including our (i) Arklatex and South Louisiana Wilcox areas, (ii) CBM, South Texas and Arklatex assets and (iii) Gulf of Mexico assets.

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Liquidity and Capital Resources

Overview. Our primary sources of liquidity are cash generated by our operations and borrowings under our RBL Facility. Our primary uses of cash are capital expenditures, debt service requirements including interest, and working capital requirements. As of March 31, 2015, our available liquidity was approximately $1.7 billion. In April 2015, we completed our semi-annual redetermination of our RBL Facility, reaffirming the borrowing base at $2.75 billion and extending the maturity date from May 2017 to May 2019, provided that our 2018 and 2019 secured term loans and senior secured notes are retired or refinanced six months prior to maturity.

We believe we have sufficient liquidity from (i) our cash flows from operations (including our significant multi-year hedge program), (ii) availability under the RBL Facility and (iii) available cash, to fund our capital program, current obligations and projected working capital requirements in 2015 and the foreseeable future. Additionally, with the extension of our $2.75 billion RBL Facility maturity date to 2019, the earliest maturity date of our remaining term debt obligations is in 2018. Furthermore, despite the recent declines in oil prices, we believe our oil and natural gas derivative contracts provide significant commodity price protection on a substantial portion of our anticipated production for 2015 and 2016. These derivative contracts have been effective in minimizing the impact of price declines to our near-term revenues and also provide greater cash flow certainty. Based on our hedges in place as of March 31, 2015, we are approximately 96% hedged (based on the midpoint of our 2015 production guidance) at a weighted average price of $91.16 per barrel for the remainder of 2015. These hedge positions consist of 95% fixed price swaps and three way collars (locking in $15.00 per barrel in excess of market prices should NYMEX settle below $85.00) comprising the remaining hedge positions.

Our ability to (i) generate sufficient cash flows from operations or obtain future borrowings under the RBL Facility, (ii) repay or refinance any of our indebtedness on commercially reasonable terms or at all on the occurrence of certain events, such as a change of control, or (iii) obtain additional capital if required on acceptable terms or at all for any potential future acquisitions, joint ventures or other similar transactions, will depend on prevailing economic conditions many of which are beyond our control. We could be required to take additional future actions if necessary to address further changes in the financial or commodity markets.

Capital Expenditures. For the full year 2015, we expect our capital budget will be approximately $1.2 billion to $1.25 billion. We expect to spend a significant portion of our 2015 capital budget in our oil programs. However, we have also allocated a portion of our capital to our Haynesville Shale natural gas assets based on the expected returns in this program. Our capital expenditures and average drilling rigs by area for the quarter ended March 31, 2015 were:

	Capital Expenditures (in millions)

Eagle Ford Shale	$	288	5.0
Wolfcamp Shale		74	2.0
Altamont		48	2.0
Haynesville Shale		5	0.1

Total capital expenditures	$	415	9.1

Long-Term Debt. As of March 31, 2015, on a pro forma basis after giving effect to the Refinancing Transactions, our long-term debt would have been approximately $4.8 billion, comprised of $3.15 billion in senior notes due in 2020, 2022 and 2023, $646 million in senior secured term loans with maturity dates in 2018 and 2019, and $971 million outstanding under the RBL Facility expiring in 2019.

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The RBL Facility

In connection with the Acquisition, we entered into a $2,000 million RBL Facility. The RBL Facility provides for revolving loans, swing line loans and letters of credit and is available to fund working capital and for general corporate purposes. After completing a borrowing base redetermination in March 2013, the aggregate amount of the RBL Facility was increased to $2,500 million. In October 2014, we completed our borrowing base redetermination, increasing the borrowing base to $2,750 million. In April 2015, we entered into an amendment to the RBL Facility whereby the lenders agreed to extend the maturity date (including the revolving commitment period) of the facility for all lenders by two years from May 24, 2017 to May 24, 2019, subject to an earlier maturity date in the event that, (i) more than $25.0 million of the Issuer's senior secured term loans are outstanding on the date that is 180 days prior to the maturity date of such senior secured term loans or (ii) more than $25.0 million of the Issuer's 2019 Senior Secured Notes are outstanding on the date that is 180 days prior to the maturity date of such notes. In addition, the Issuer completed its semi-annual redetermination, reaffirming the borrowing base at $2,750 million.

The RBL Facility contains customary representations and warranties and customary affirmative and negative covenants, including, among other things, restrictions on indebtedness, investments, asset sales, mergers and consolidations, prepayments of subordinated indebtedness, liens, transactions with affiliates, and dividends and other distributions. The RBL Facility also includes customary events of defaults including a change of control.

As of March 31, 2015, on a pro forma basis after giving effect to the Refinancing Transactions, we had approximately $1.7 billion available for borrowing under the RBL Facility (after giving effect to issued and undrawn letters of credit). For additional information on the RBL Facility, see "Description of Other Indebtedness—The RBL Facility."

Senior Secured Term Loan

We have a $750 million senior secured term loan facility that contains customary representations and warranties and customary affirmative and negative covenants, including, among other things, restrictions on indebtedness, investments, asset sales, mergers and consolidations, prepayments of subordinated indebtedness, liens, transactions with affiliates, and dividends and other distributions. In August 2012 and May 2013, we completed repricing amendments of the term loan facility that reduced the LIBOR floor and applicable margin applicable to the original term loans. In October 2012, we obtained $400 million aggregate principal amount of incremental term loans (the "incremental term loans") under the term loan facility pursuant an incremental facility amendment, which will mature on April 30, 2019. We refer to the original term loans and the incremental term loans as our "senior secured term loans."

On August 16, 2013, we repaid $250 million aggregate principal amount of the original term loans and $250 million aggregate principal amount of the incremental term loans. As of March 31, 2015, on a pro forma basis after giving effect to the Refinancing Transactions, we had $646 million outstanding aggregate principal amount of senior secured term loans. For additional information on senior secured term loans, see "Description of Other Indebtedness—Senior Secured Term Loans."

The Senior Notes

The indentures governing the existing senior notes and the notes contain covenants that, among other things, limit our ability, and the ability of our restricted subsidiaries, to:

•: incur additional indebtedness and guarantee indebtedness, pay dividends or make other distributions in respect of, or repurchase or redeem, capital stock;
•: prepay, redeem or repurchase certain debt;

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•: make loans and investments;
•: sell or otherwise dispose of assets;
•: incur liens;
•: enter into transactions with affiliates;
•: enter into agreements restricting our subsidiaries' ability to pay dividends; and
•: consolidate, merge or sell all or substantially all of our assets.

These limitations are subject to a number of qualifications and exceptions that set forth in the indentures.

As of March 31, 2015, on a pro forma basis after giving effect to the Refinancing Transactions, we had $2,000 million outstanding aggregate principal amount of 9.375% Senior Notes due 2020, $350 million outstanding aggregate principal amount of 7.750% Senior Notes due 2022 and $800 million outstanding aggregate principal amount of the notes. For additional information on the existing senior notes, see "Description of Other Indebtedness—Existing Senior Notes." For additional information on the notes, see "Description of Exchange Notes."

We continually monitor the debt capital markets and our capital structure and will make changes to our capital structure from time to time, with the goal of maintaining flexibility and cost efficiency. For additional details on our long-term debt, see Note 6 to our historical consolidated financial statements and related notes included elsewhere in this prospectus.

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

	Successor															Predecessor

	Quarter ended March 31, 2015			Quarter ended March 31, 2014			Year ended December 31, 2014			Year ended December 31, 2013			March 23 (inception) to December 31, 2012			January 1 to May 24, 2012
	(in millions)
Cash Flow from Operations
Operating activities										��
Net income (loss)	$	19		$	(36	)	$	148		$	549		$	(255	)	$	178
Impairment and ceiling test charges		—			3			20			46			1			62
Gain on sale of assets		—			(13	)		(2	)		(468	)		—			—
Other income adjustments		243			214			2,058			796			351			537
Change in other assets and liabilities		8			139			(929	)		52			352			(197	)

Total cash flow from operations	$	270		$	307		$	1,295		$	975		$	449		$	580



Other Cash Inflows
Investing activities
Proceeds from the sale of assets and investments, net of cash transferred	$	—		$	17		$	154		$	1,451		$	110		$	9

Financing activities
Proceeds from issuance of long-term debt		364			550			2,455			1,880			5,477			215
Contributions		20			186			186			—			3,323			960

		384			736			2,641			1,880			8,800			1,175

Total cash inflows	$	384		$	753		$	2,795		$	3,331		$	8,910		$	1,184



Cash Outflows
Investing activities
Capital expenditures	$	432		$	459		$	2,033		$	1,924		$	877		$	636
Cash paid for acquisitions, net of cash acquired		—			—			165			2			7,126			1
Increase in note receivable with parent		—			—			20			—			—			—

	$	432		$	459		$	2,218		$	1,926		$	8,003		$	637



Financing activities
Repayments of long-term debt		236			570			1,898			2,190			1,139			1,065
Distributions to members		—			—			—			200			—			—
Debt issuance costs		—			—			1			5			154			—

		236			570			1,899			2,395			1,293			1,065

Total cash outflows	$	668		$	1,029		$	4,117		$	4,321		$	9,296		$	1,702



Net change in cash and cash equivalents	$	(14	)	$	31		$	(27	)	$	(15	)	$	63		$	62

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Contractual Obligations

We are party to various contractual obligations. Some of these obligations are reflected in our financial statements, such as liabilities from commodity-based derivative contracts, while other obligations, such as operating leases and capital commitments, are not reflected on our balance sheet. The following table and discussion summarizes our contractual cash obligations as of March 31, 2015, for each of the periods presented:

	2015			2016 - 2017		2018 - 2019		Thereafter		Total

	(in millions)
Long-term financing obligations:
Principal	$	—		$	—	$	2,380	$	2,350	$	4,730
Interest		239			638		554		135		1,566
Liabilities from derivatives		(1	)		—		—		—		(1	)
Operating leases		9			24		10		—		43
Other contractual commitments and purchase obligations:
Volume and transportation commitments		54			161		164		179		558
Other obligations		71			99		—		—		170

Total contractual obligations	$	372		$	922	$	3,108	$	2,664	$	7,066

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. In April 2015, we completed our semi-annual redetermination, reaffirming the borrowing base at $2.75 billion and extending the maturity date to May 2019 which is reflected in the table above.

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.
•: Other Obligations. Included in these amounts are commitments for drilling, completions and seismic activities for our operations and various other maintenance, engineering, procurement and construction contracts. Our future commitments under these contracts may change reflecting changes in commodity prices (e.g. the significant decline in oil prices in the second half of 2014) and any related effect on the supply/demand for these services. 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.

Commitments and Contingencies

For a further discussion of our commitments and contingencies, see Note 7 to our historical consolidated financial statements and related notes included elsewhere in this prospectus.

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Off-Balance Sheet Arrangements

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

Critical Accounting Estimates

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

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

Under the successful efforts method of accounting for oil and natural gas properties, we evaluate capitalized costs related to proved properties at least annually or upon a triggering event (such as the recent commodity price declines) to determine if impairment of such properties has occurred. Our evaluation of whether costs are recoverable is made based on common geological structure or stratigraphic conditions and considers estimated future cash flows for all proved developed (producing and non-producing), proved undeveloped reserves and risk-weighted non-proved reserves in comparison to the carrying amount of the proved properties. If the carrying amount of a property exceeds the estimated undiscounted future cash flows of its reserves, the carrying amount is reduced to estimated fair value through a charge to income. Fair value is calculated by discounting the future cash flows based on estimates of future oil and gas production, forward commodity prices based on estimated commodity price curves as of the date of the estimate, adjusted for geographical location, contractual and quality differentials, estimates of future operating and development costs, and a risk-adjusted discount rate. The discount rate is based on rates utilized by market participants that are commensurate with the risks inherent in the development and production of the underlying crude oil and natural gas. Each of these estimates involves judgment. As of March 31 2015, our capitalized costs related to proved properties were approximately $5 billion for Eagle Ford, $2 billion for Wolfcamp and $1 billion for Altamont.

Leasehold acquisition costs associated with non-producing areas are assessed for impairment based on estimated drilling plans and capital expenditures relative to potential lease expirations. Our unproved property costs were approximately $0.5 billion at March 31, 2015, of which approximately

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$0.4 billion was associated with Wolfcamp and $0.1 billion with Altamont. Generally, economic recovery of unproved reserves in non-producing areas are not yet supported by actual production or conclusive formation tests, but may be confirmed by our continuing exploration and development of the program. Our allocation of capital to the development of unproved properties may be influenced by changes in commodity prices (e.g. the rapid decline in oil prices in the fourth quarter of 2014), the availability of drilling rigs and associated costs, and/or the relative returns of our unproved property development in comparison to the use of capital for other strategic objectives. Due to the significant decline in oil prices, we reduced our expected capital expenditures in certain of our operating areas for 2015; however, we did not record an impairment of our unproved oil and gas properties in 2014 based on our current intent and ability to fulfill our drilling commitments prior to the expiration of associated leases. Among other factors, should oil prices not justify sufficient capital allocation to the continued development of these unproved properties, we could incur significant impairment charges of our unproved property in the future. In 2013 and from the Acquisition (May 25, 2012) to December 31, 2012, we did not record any impairments of our oil and gas properties included in continuing operations.

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

As of December 31, 2014, 62% of our total proved reserves were undeveloped and 2% 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.

Prior to the Acquisition on May 24, 2012, our predecessor accounted for oil and natural gas producing activities in accordance with the full cost method. Under the full cost accounting method, substantially all of the costs incurred in connection with the acquisition, exploration and development of oil and natural gas reserves were capitalized in full cost pools by country. These capitalized amounts included the costs of unproven properties. Under the full cost method our most critical accounting assessment was a quarterly ceiling test performed on capitalized costs for each full cost pool since many

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of the variables (reserves, costs and future capital) involved significant estimation. Cost pools were also evaluated periodically based on estimates of future plans and activities. Prior to the Acquisition, our predecessor recorded non-cash charges of $62 million for the period from January 1, 2012 through May 24, 2012, as a result of the decision to end exploration activities in Egypt.

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 estimated 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 and estimates of pricing which can impact the timing of the asset retirement obligation. As of March 31, 2015, our asset retirement liability was approximately $43 million.

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

The table below presents the hypothetical sensitivity of our commodity-based derivatives to changes in fair values arising from immediate selected potential changes in oil and natural gas prices at March 31, 2015:

			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)	$	1,034	$	830	$	(204	)	$	1,237	$	203

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

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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.

Deferred Taxes and Uncertain Income Tax Positions. As a result of our change in tax status in 2014, we began recording deferred income tax assets and liabilities reflecting the tax consequences of differences between the financial statement carrying value of assets and liabilities and the tax basis of those assets and liabilities. Our deferred tax assets and liabilities reflect our conclusions about which positions are more likely than not to be sustained if they are audited by taxing authorities. Our most significant judgments on tax related matters include, but are not limited to, the realization of deferred tax assets and uncertain tax positions which involve the exercise of significant judgment which could change and impact our financial condition or results of operations.

Qualitative and Quantitative Disclosures About Market Risk

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

Commodity Price Risk

•: changes in oil, natural gas and NGLs prices impact the amounts at which we sell our production and affect the fair value of our oil and natural gas derivative contracts held; and
•: changes in locational price differences also affect amounts at which we sell our oil, natural gas and NGLs production, and the fair values of any related derivative products.

Interest Rate Risk

•: changes in interest rates affect the interest expense we incur on our variable-rate debt and the fair value of fixed-rate debt;
•: changes in interest rates result in increases or decreases in the unrealized value of our derivative positions; and
•: changes in interest rates used to discount liabilities result in higher or lower accretion expense over time.

Risk Management Activities

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

•: forward contracts, which commit us to purchase or sell energy commodities in the future;
•: option contracts, which convey the right to buy or sell a commodity, financial instrument or index at a predetermined price;
•: swap contracts, which require payments to or from counterparties based upon the differential between two prices or rates for a predetermined contractual (notional) quantity; and
•: structured contracts, which may involve a variety of the above characteristics.

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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 Notes 1 and 4 to our annual consolidated financial statements included elsewhere in this prospectus.

Commodity Price Risk

Oil, Natural Gas and NGL 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 change in fair value of our commodity-based derivatives due to hypothetical changes in oil and natural gas prices, discount rates and credit rates at March 31, 2015:

			Oil, Natural Gas and NGL Derivatives

			10 Percent Increase					10 Percent Decrease
	Fair Value		Fair Value		Change			Fair Value		Change
	(in millions)
Price impact(1)	$	1,034	$	830	$	(204	)	$	1,237	$	203

			Oil, Natural Gas and NGL Derivatives

			1 Percent Increase					1 Percent Decrease
	Fair Value		Fair Value		Change			Fair Value		Change
	(in millions)
Discount Rate(2)	$	1,034	$	1,026	$	(8	)	$	1,042	$	8
Credit rate(3)	$	1,034	$	1,024	$	(10	)	$	1,039	$	5

(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 of our counterparties.

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. In April 2015, we completed our semi-annual redetermination, reaffirming

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the borrowing base at $2.75 billion and extending the maturity date to May 2019 which is reflected in the table below.

	March 31, 2015																						December 31, 2014

	Expected Fiscal Year of Maturity of Carrying Amounts
	Expected Fiscal Year of Maturity of Carrying Amounts																				Fair Value		Carrying Amounts		Fair Value
	2015			2016			2017			2018			2019			Thereafter			Total		Fair Value		Carrying Amounts		Fair Value
													(in millions)
Fixed rate long-term debt	$	—		$	—		$	—		$	—		$	750		$	2,350		$	3,100	$	3,195	$	3,100	$	3,111
Average interest rate		8.6	%		8.6	%		8.6	%		8.6	%		8.9	%		8.1	%
Variable rate long-term debt	$	—		$	—		$	—		$	496		$	1,130		$	—		$	1,626	$	1,614	$	1,498	$	1,471
Average interest rate		3.3	%		3.3	%		3.3	%		3.2	%		3.1	%		—	%

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BUSINESS

Overview

We are an independent exploration and production company engaged in the acquisition and development of unconventional onshore oil and natural gas properties in the United States. We are focused on creating value through the development of our low risk drilling inventory located predominantly in four operating areas: the Eagle Ford Shale (South Texas), the Wolfcamp Shale (Permian Basin in West Texas), the Altamont Field in the Uinta Basin (Northeastern Utah) and the Haynesville Shale (North Louisiana). In our operating areas, we have identified 5,673 drilling locations (including 979 drilling locations to which we have attributed proved undeveloped reserves as of December 31, 2014, of which approximately 92% are oil wells). At 2014 activity levels, this represents approximately 21 years of drilling inventory (more than 30 years of drilling inventory at 2015 drilling levels). As of December 31, 2014, we had proved reserves of 622.2 MMBoe (52% oil and 67% liquids) and for the quarter ended March 31, 2015, we had average net daily production of 102,421 Boe/d (59% oil and 70% liquids).

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

Each of our operating areas is characterized by a favorable operating environment, a long lived reserve base and high drilling success rates. We have established significant contiguous leasehold positions in each area, representing approximately 477,000 net (647,000 gross) acres in total. Beginning in 2012, our capital programs have focused predominantly on the Eagle Ford Shale, the Wolfcamp Shale and Altamont, three of the premier unconventional oil plays in the United States, resulting in oil reserve and production growth of 10% and 51%, respectively, from December 31, 2013 to December 31, 2014.

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

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	Estimated Proved Reserves(1)

	Estimated Proved Reserves(1)														Average Net Daily Production (MBoe/d)
	Oil (MMBbls)		NGLs (MMBbls)		Natural Gas (Bcf)		Total (MMBoe)		Liquids (%)			Proved Developed (%)			Average Net Daily Production (MBoe/d)
Operating Areas
Eagle Ford Shale		183.1		65.5		398.0		314.9		79	%		32	%		54.7
Wolfcamp Shale		53.9		28.7		158.2		109.0		76	%		47	%		17.9
Altamont		83.8		—		180.4		113.9		74	%		49	%		17.1
Haynesville Shale		—		—		506.1		84.3		—	%		36	%		12.6

Total Areas		320.8		94.2		1,242.7		622.1		67	%		38	%		102.3
Other(2)		—		—		0.3		0.1		—	%		100	%		0.1

Total		320.8		94.2		1,243.0		622.2		67	%		38	%		102.4

(1): Proved reserves were evaluated using first day 12-month prices of $94.99 per barrel of oil (WTI) and $4.34 per MMBtu of natural gas (Henry Hub).
(2): Comprised of outside operated overriding interests in the Gulf of Mexico and Rockies.

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

We operate 85% of our producing wells and have operational control over approximately 97% of our operating drilling inventory as of December 31, 2014. This control provides us with flexibility around the amount and timing of capital spending and has allowed us to continually improve our capital and operating efficiencies. We also employ a centralized drilling and completion structure to accelerate our internal knowledge transfer around the execution of our drilling and completion programs. In 2014, we drilled 273 wells with a success rate of 100%, adding approximately 101 MMBoe of proved reserves (77% of which were liquids), excluding divested assets. Our reserve replacement cost as of December 31, 2014 was $16.93 per Boe. Please see "Management's Discussion and Analysis of Financial Condition and Results of Operations—Reserve Replacement Ratio/Reserve Replacement Costs."

Our Properties and Operating Areas

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productivity when fractured. As of December 31, 2014, we had 81,753 net (88,890 gross) acres in the Eagle Ford, and we have identified 872 drilling locations.

Our large, contiguous acreage positions are characterized by stacked pay zones, including the Wolfcamp A, B, and C, which combine for over 750 feet of net (approximately 1,000 feet of gross) thickness. The Wolfcamp has high organic content and is composed of interbedded shale, silt, and fine-grained carbonate that respond favorably to fracture stimulation. As of December 31, 2014, we have 179,780 net (181,487 gross) acres in the Wolfcamp, in which we have identified approximately 3,300 drilling locations in the Wolfcamp A, B, and C. In the second half of 2014, we initiated drilling in the Wolfcamp A.

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The following table provides a summary of acreage and inventory data as of December 31, 2014:

	Acres

	Acres				Drilling Locations(1) (#)			Inventory (Years)(3)		Working Interest (%)
	Gross		Net		Drilling Locations(1) (#)			Inventory (Years)(3)		Working Interest (%)
Operating Areas
Eagle Ford Shale		88,890		81,753		872	136		6.4		89	%	67	%
Wolfcamp Shale		181,487		179,780		3,300	90		36.7		97	%	73	%
Wolfcamp A						1,165					97	%	73	%
Wolfcamp B						1,019					97	%	73	%
Wolfcamp C						1,116					97	%	73	%
Altamont		319,600		177,119		1,304	47		27.7		75	%	62	%
Vertical						1,295					75	%	62	%
Horizontal						9					62	%	48	%
Haynesville Shale		57,502		38,224		197	—		—		81	%	65	%
Holly						116					77	%	62	%
Non-Holly						81					88	%	69	%

Total Operating Areas		647,479		476,876		5,673	273		20.8		90	%	69	%

(1)

Our inventory as of December 31, 2014 does not include the following potential additional locations:

•: In the Wolfcamp Shale area, (i) horizontal drilling locations in the Cline Shale and (ii) vertical drilling locations in the Spraberry and other stacked formations; and
•: In Altamont, (i) additional vertical infill locations and (ii) horizontal drilling locations in the Wasatch and Green River formations.

(2)

Represents gross operated wells completed in 2014.

(3)

Calculated as Drilling Locations divided by 2014 Drilling Locations. At 2015 activity levels, inventory is approximately 30 years.

We have used the data from our development programs to identify and prioritize our inventory. These drilling locations are only included in our inventory after they have been evaluated technically.

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Business Strategy

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

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

Maintain an Extensive Low-Risk Drilling Inventory

Enhance Returns by Continuously Improving Capital and Operating Efficiencies

Identify and Develop Additional Drilling Opportunities in our Portfolio

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Maintain Liquidity and Financial Flexibility

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Competitive Strengths

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

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

Multi-Year Inventory of Low-Risk Drilling Opportunities

High-Quality Proved Reserve Base with Substantial Current Production

Our leasehold position and inventory of low-risk drilling locations is complemented by a substantial proved reserve base. As of December 31, 2014, we had proved reserves of 622.2 MMBoe (52% oil and 67% liquids). For the quarter ended March 31, 2015, our average production was 102,421 Boe/d, which was 59% oil and 70% liquids. Our current production provides a stable source of cash flow to fund the development of our operating areas. This significantly reduces our reliance on outside sources of capital. In addition, our extensive inventory improves our ability to replace and grow proved reserves.

Significant Operational Control with Low Cost Operations

Capital Allocation Flexibility and Scale across Multiple Basins

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Furthermore, because of our centralized operational structure, we are able to quickly transfer operational efficiencies from one project to the next. From this deep operational knowledge base and sizeable, concentrated positions in multiple basins, we have the flexibility to allocate significant amounts of capital across our properties in an efficient and value-maximizing manner.

Ability to Direct Capital to the Prolific Haynesville Shale

Significant Liquidity and Financial Flexibility

As of March 31, 2015, after giving effect to the Refinancing Transactions, we had approximately $1.7 billion available to borrow under the RBL facility (after giving effect to issued and undrawn letters of credit). We maintain a robust hedging program in order to protect our cash flows through commodity cycles. Based on our hedges in place as of March 31, 2015, we were approximately 96% hedged (based on the midpoint of our 2015 production guidance) at a weighted average price of $91.16 per barrel for the remainder of 2015. We have (i) fixed price swaps on approximately 96% of and 82% of our oil production, at weighted average floor prices of $91.16 and $80.29 in 2015 and 2016, respectively (based on the midpoint of 2015 production guidance) and (ii) hedged basis risk on approximately 50% of our year-to-date Eagle Ford oil production. After giving effect to the Refinancing Transactions, we expect that liquidity provided by operating cash flow, availability under the RBL Facility and available cash will give us the financial flexibility to pursue our planned capital expenditures in 2015 and for the foreseeable future.

2015 Capital Budget

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Oil and Natural Gas Properties

Oil, Natural Gas and NGLs Reserves and Production

Proved Reserves

The table below presents information about our estimated proved reserves as of December 31, 2014, based on our internal reserve report. The reserve data represents only estimates which are often different from the quantities of oil and natural gas that are ultimately recovered. The risks and uncertainties associated with estimating proved oil and natural gas reserves are discussed further in "Risk Factors." Net proved reserves exclude royalties and interests owned by others and reflect contractual arrangements and royalty obligations in effect at December 31, 2014.

	Net Proved Reserves(1)

	Oil (MMBbls)		NGLs (MMBbls)		Natural Gas (Bcf)		Total (MMBoe)		Percent (%)
*Reserves by Classification*
Proved Developed
Operating Areas
Eagle Ford Shale		64.1		18.2		111.6		100.9		16	%
Wolfcamp Shale		23.8		14.2		78.5		51.1		8	%
Altamont		40.5		—		90.9		55.7		9	%
Haynesville Shale		—		—		182.3		30.3		5	%

Total Operating Areas		128.4		32.4		463.3		238.0		38	%
Other(2)		—		—		0.3		0.1		—	%

Total Proved Developed(3)		128.4		32.4		463.6		238.1		38	%

Proved Undeveloped
Operating Areas
Eagle Ford Shale		119.0		47.3		286.4		214.0		34	%
Wolfcamp Shale		30.1		14.5		79.7		57.9		9	%
Altamont		43.3		—		89.5		58.2		10	%
Haynesville Shale		—		—		323.8		54.0		9	%

Total Operating Areas		192.4		61.8		779.4		384.1		62	%
Other(2)		—		—		—		—		—	%

Total Proved Undeveloped		192.4		61.8		779.4		384.1		62	%

Total Proved Reserves		320.8		94.2		1,243.0		622.2		100	%

(1): Proved reserves were evaluated using the first day 12-month average prices of $94.99 per barrel of oil (WTI) and $4.34 per MMBtu of natural gas (Henry Hub).
(2): Comprised of outside operated overriding interests in the Gulf of Mexico and Rockies.
(3): Includes 223 MMBoe of proved developed producing reserves representing 36% of total net proved reserves and 15 MMBoe of proved developed non-producing reserves representing 2% of total net proved reserves at December 31, 2014.

Our reserves in the table above are consistent with estimates of reserves filed with other federal agencies except for differences of less than 5% resulting from actual production, acquisitions, property sales, necessary reserve revisions and additions to reflect actual experience. Our estimated proved reserves were prepared by our internal reserve engineers and audited by Ryder Scott Company, L.P., our independent petroleum engineering consultants since 2004.

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The table below presents net proved reserves as reported and sensitivities related to our estimated proved reserves based on differing price scenarios as of December 31, 2014.

		Net Proved Reserves (MMBoe)

As Reported			622.2
10 percent increase in commodity prices(1)			624.7
10 percent decrease in commodity prices(1)			618.8

(1): Based on the first day 12-month average prices of $94.99 per barrel of oil (WTI) and $4.34 per MMBtu of natural gas (Henry Hub) used to determine net proved reserves at December 31, 2014.

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 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 our Marketing and Commercial groups. He also oversees the reserve reporting and technical/business excellence groups. He has more than 25 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 "Management's Discussion and Analysis of Financial Condition and Results of Operations—Critical Accounting Estimates."

Ryder Scott conducted an audit of the estimates of net proved reserves that we prepared as of December 31, 2014. In connection with its audit, Ryder Scott reviewed 94% (by volume) of our total net proved reserves on a barrel of oil equivalent basis, representing 98% of the total discounted future net cash flows of these net proved reserves. For the audited properties, 91% of our total net PUD reserves were evaluated. Ryder Scott concluded the overall procedures and methodologies that we utilized in preparing our estimates of net proved reserves as of December 31, 2014 complied with current SEC regulations and the overall net proved reserves for the reviewed properties as estimated by us are, in aggregate, reasonable within the established audit tolerance guidelines of 10% as set forth in the Society of Petroleum Engineers auditing standards.

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 11 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.

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Proved Undeveloped Reserves (PUDs)

As of December 31, 2014, we have 384 MMBoe of PUD reserves and 979 PUD locations within our operating areas, all of which are scheduled to be developed or drilled within five years of their initial recording. All PUD locations are surrounded by producing properties, and a majority of our PUDs directly offset a producing property. Where we have recorded PUDs beyond one location away from a producing property, reasonable certainty of economic producibility has been established by reliable technology in our operating areas, including field tests that demonstrate consistent and repeatable results within the formation being evaluated.

We assess our PUD reserves on a quarterly basis. During 2014, we increased our PUD reserves by a net 19 MMBoe compared to December 31, 2013, including the addition of 75 MMBoe of PUD reserves primarily from our drilling activities in the Eagle Ford Shale and Altamont; positive revisions of 26 MMBoe primarily due to the recovery of certain natural gas PUD reserves; acquisition of 3 MMBoe of PUD reserves in our Wolfcamp Shale; 75 MMBoe of PUD reserves transferred to proved developed reserves; 8 MMBoe related to our divestitures; and 2 MMBoe of PUD reserves transferred to probable reserves due to long range plan capital reductions resulting from changes in economic outlook.

We spent approximately $1,192 million, $679 million and $587 million during 2014, 2013 and 2012, respectively, to convert approximately 20% or 75 MMBoe, 12% or 39 MMBoe and 10% or 32 MMboe, respectively, of our prior year-end PUD reserves to proved developed reserves. In our December 31, 2014 internal reserve report, the amounts estimated to be spent in 2015, 2016 and 2017 to develop our PUD reserves are $1,157 million, $1,378 million and $1,390 million, respectively. The upward trend in the amounts estimated to be spent to develop our PUD reserves is a result of our focus on developing our oil programs. The amount and timing of these expenditures will depend on a number of factors, including actual drilling results, service costs and commodity prices.

The following table summarizes our changes in PUDs for the years ended December 31, 2013 and December 31, 2014, respectively (in MMBoe):


Balance, December 31, 2012	315
Extensions and discoveries	109
Revisions of previous estimates(1)	6
Transfers to proved developed	(39	)
Divestitures	(26	)

Balance, December 31, 2013	365

Purchase of minerals in place	3
Extensions and discoveries(2)	75
Revisions of previous estimates(3)	26
Transfers to proved developed	(75	)
Divestitures	(8	)
Other(4)	(2	)

Balance, December 31, 2014	384

(1): Revisions to previous estimates during 2013 are primarily due to improved performance and ownership positions.
(2): Includes 2 MMBoe related to South Louisiana Wilcox assets sold in 2014.
(3): Revisions to previous estimates during 2014 are primarily due to increased natural gas prices.
(4): Represents PUDs reclassified as probable reserves due to long-range plan capital reductions resulting from changes in economic outlook.

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Acreage and Wells

The following tables detail (i) our interest in developed and undeveloped acreage at December 31, 2014, (ii) our interest in oil and natural gas wells at December 31, 2014 and (iii) our exploratory and development wells drilled during the years 2012 through 2014. 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
Operating Areas
Eagle Ford Shale		28,325		26,043		60,565		55,710		88,890		81,753
Wolfcamp Shale		14,129		14,021		167,358		165,759		181,487		179,780
Altamont		95,410		75,613		224,190		101,506		319,600		177,119
Haynesville Shale		14,948		10,597		42,554		27,627		57,502		38,224

Total Operating Areas		152,812		126,274		494,667		350,602		647,479		476,876
Other		107,304		10,424		281,839		170,216		389,143		180,640

Total Acreage		260,116		136,698		776,506		520,818		1,036,622		657,516

(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.

Our net developed acreage is concentrated primarily in Utah (55%), Texas (33%) and Louisiana (8%). Our net undeveloped acreage is concentrated primarily in Texas (44%), Utah (20%), Michigan (10%), West Virginia (8%), Louisiana (6%) and Colorado (3%). Approximately 5%, 9% and 19% of our net undeveloped acreage is held under leases that have minimum remaining primary terms expiring in 2015, 2016 and 2017, respectively. 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.

	Oil				Natural Gas				Total				Wells Being Drilled at December 31, 2014(1)

	Gross(2)		Net(3)		Gross(2)		Net(3)		Gross(2)		Net(3)(4)		Gross(2)		Net(3)
Productive Wells
Eagle Ford Shale		434		399		3		3		437		402		38		37
Wolfcamp Shale		207		204		—		—		207		204		26		26
Altamont		479		364		3		1		482		365		5		1
Haynesville Shale		—		—		203		106		203		106		—		—

Total Productive Wells		1,120		967		209		110		1,329		1,077		69		64

(1): Comprised of wells that were spud as of December 31, 2014 and have not been completed.
(2): Gross interest reflects the total wells we participated in, regardless of our ownership interest.
(3): Net interest is the aggregate of the fractional working interests that we have in the gross wells or gross wells drilled.
(4): At December 31, 2014, we operated 1,055 of the 1,077 net productive wells.

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	Net Exploratory(1)						Net Development(1)

	2014		2013		2012		2014		2013		2012
Wells Drilled
Operating Areas
Productive		5		8		13		257		216		116
Dry		—		—		1		—		2		2

Total Operating Areas		5		8		14		257		218		118
Divested Assets(2)
Productive		—		—		7		—		—		16
Dry		—		—		—		—		—		1

Total Divested Assets		—		—		7		—		—		17
Total
Productive		5		8		20		257		216		132
Dry		—		—		1		—		2		3

Total Wells Drilled		5		8		21		257		218		135

(1): Net interest is the aggregate of the fractional working interests that we have in the gross wells or gross wells drilled.
(2): Wells of divested assets in 2012 include those for our South Louisiana Wilcox and Arklatex Tight Gas areas sold in 2014, our CBM, South Texas and Arklatex assets, each sold in 2013 and of our Gulf of Mexico assets sold in 2012.

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.

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Net Production, Sales Prices, Transportation and Production Costs

The following table details our net production volumes, net production volume by operating area, average sales prices received, average transportation costs, average lease operating expense and average production taxes associated with the sale of oil, natural gas and NGLs for each of the periods indicated:

	Quarters ended March 31,				Years ended December 31,

	2015		2014		2014		2013		2012
*Volumes:*
Net Production Volumes
Operating Areas
Oil (MBbls)		5,401		4,373		19,979		13,230		8,277
Natural Gas (MMcf)		16,572		17,592		69,177		83,606		122,254
NGLs (MBbls)		1,044		840		4,109		2,424		1,056

Total Operating Areas (MBoe)		9,207		8,146		35,617		29,588		29,709
Other
Oil (MBbls)		1		—		6		5		24
Natural Gas (MMcf)		56		107		257		210		2,457
NGLs (MBbls)		—		3		7		10		42

Total Other (MBoe)		11		20		56		50		476
Total Operating and Other Areas
Oil (MBbls)		5,402		4,373		19,985		13,235		8,301
Natural Gas (MMcf)		16,628		17,699		69,434		83,816		124,711
NGLs (MBbls)		1,044		843		4,116		2,434		1,098

Total Operating and Other Areas (MBoe)		9,218		8,166		35,673		29,638		30,185
Divested Assets(1)
Oil (MBbls)		—		—		—		197		743
Natural Gas (MMcf)		—		—		—		10,050		59,189
NGLs (MBbls)		—		—		—		327		887

Total (MBoe)		—		—		—		2,199		11,494
Total Net Production Volumes
Oil (MBbls)		5,402		4,373		19,985		13,432		9,044
Natural Gas (MMcf)		16,628		17,699		69,434		93,866		183,900
NGLs (MBbls)		1,044		843		4,116		2,761		1,985

Total Equivalent Volumes (MBoe)		9,218		8,166		35,673		31,837		41,679
MBoe/d(2)		102.4		90.7		97.7		87.2		113.9

(1): Volumes in 2013 represent volumes from our approximate 49% equity interest in the volumes of Four Star Oil & Gas Company (Four Star), which we sold in September 2013. Volumes in 2012 include 282 MBbls of oil, 15,552 MMcf of natural gas, 478 MBbls of NGLs and 3,352 MBoe related to Four Star. Remaining volumes include volumes from our South Louisiana Wilcox and Arklatex Tight Gas areas sold in 2014, our CBM, South Texas, and the majority of our Arklatex assets, all of which were in sold in 2013, and our Gulf of Mexico assets, which were sold in 2012. For periods after May 24, 2012, our South Louisiana Wilcox, CBM, South Texas, and Arklatex assets are treated as discontinued operations and accordingly volumes relating to those assets are excluded from all financial and non-financial metrics. In addition, our Brazilian operations are treated as discontinued operations in all periods, and accordingly volumes are excluded from all financial and non-financial metrics for both predecessor and successor periods.
(2): The years ended December 31, 2013 and 2012 include 6.0 Mboe/d and 9.2 Mboe/d, respectively, from Four Star.

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	Quarters ended March 31,				Years ended December 31,

	2015		2014		2014		2013		2012
Operating Area Net Production Volumes
Eagle Ford Shale
Oil (MBbls)		3,422		2,848		12,698		8,763		5,023
Natural Gas (MMcf)		4,860		4,320		18,215		14,857		8,425
NGLs (MBbls)		692		613		2,851		2,133		936

Total Eagle Ford Shale (MBoe)		4,924		4,181		18,585		13,372		7,364
Wolfcamp Shale
Oil (MBbls)		858		646		3,073		1,306		489
Natural Gas (MMcf)		2,433		1,271		7,551		2,483		763
NGLs (MBbls)		349		218		1,237		280		116

Total Wolfcamp Shale (MBoe)		1,613		1,076		5,568		2,000		734
Altamont
Oil (MBbls)		1,121		879		4,208		3,161		2,765
Natural Gas (MMcf)		2,479		1,927		8,504		6,931		6,632
NGLs (MBbls)		3		9		21		11		4

Total Altamont (MBoe)		1,537		1,210		5,646		4,327		3,876
Haynesville Shale
Oil (MBbls)		—		—		—		—		—
Natural Gas (MMcf)		6,800		10,074		34,907		59,335		106,434
NGLs (MBbls)		—		—		—		—		—

Total Haynesville Shale (MBoe)		1,133		1,679		5,818		9,889		17,736

	Quarters ended March 31,				Years ended December 31,

	2015		2014		2014		2013		2012
Prices and Costs per Unit:(1)
Oil Average Realized Sales Price ($/Bbl)
Physical Sales	$	42.40	$	92.83	$	85.31	$	94.75	$	92.28
Including Financial Derivatives(2)	$	78.39	$	91.20	$	88.77	$	97.56	$	97.01
Natural Gas Average Realized Sales Price ($/Mcf)
Physical Sales	$	2.51	$	4.21	$	3.76	$	3.28	$	2.64
Including Financial Derivatives(2)	$	3.69	$	3.26	$	3.34	$	2.97	$	4.66
NGLs Average Realized Sales Price ($/Bbl)
Physical Sales	$	12.04	$	32.29	$	26.73	$	30.58	$	37.70
Including Financial Derivatives(2)	$	12.26	$	31.40	$	27.78	$	—	$	—

(1): Prices and costs per unit are calculated excluding volumes related to Four Star.
(2): Amounts reflect settlements on financial derivatives, including cash premiums. No cash premiums were received for the quarter ended March 31, 2015. Cash premiums received for the quarter ended March 31, 2014 were less than $1 million. For the years ended December 31, 2014, 2013 and 2012, we received $1 million, $9 million and paid $3 million of cash premiums, respectively.

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	Years ended December 31,

	2014		2013		2012
Average Transportation Costs
Operating Areas
Oil ($/Bbl)	$	1.65	$	2.01	$	2.09
Natural Gas ($/Mcf)	$	0.65	$	0.52	$	0.40
NGLs ($/Bbl)	$	5.42	$	6.08	$	2.93
Other
Oil ($/Bbl)	$	0.85	$	0.83	$	0.28
Natural Gas ($/Mcf)	$	1.31	$	0.01	$	0.51
NGLs ($/Bbl)	$	5.37	$	3.88	$	9.48
Divested Assets(1)
Oil ($/Bbl)	$	—	$	—	$	0.04
Natural Gas ($/Mcf)	$	—	$	—	$	0.42
NGLs ($/Bbl)	$	—	$	—	$	7.30
Consolidated
Oil ($/Bbl)	$	1.65	$	2.01	$	1.91
Natural Gas ($/Mcf)	$	0.65	$	0.52	$	0.41
NGLs ($/Bbl)	$	5.42	$	6.07	$	4.29
Average Lease Operating Expenses ($/Boe)
Operating Areas	$	5.41	$	5.04	$	3.26
Divested Assets(1)	$	—	$	—	$	4.58
Total Consolidated	$	5.40	$	4.98	$	3.56
Average Production Taxes ($/Boe)
Operating Areas	$	3.40	$	2.84	$	1.93
Divested Assets(1)	$	—	$	—	$	1.57
Total Consolidated	$	3.39	$	2.84	$	1.84

(1): Divested assets in 2012 represent activity prior to May 24, 2012 and include our South Louisiana Wilcox and Arklatex Tight Gas assets sold in 2014, our CBM, South Texas and Arklatex assets sold in 2013 and our Gulf of Mexico assets sold in 2012.

Acquisition, Development and Exploration Expenditures

See our audited consolidated financial statements included elsewhere in this prospectus under "Supplemental Oil and Natural Gas Operations—Total Cost-Incurred" for details on our acquisition, development and exploration expenditures.

Operations

As of December 31, 2014, we operated approximately 85% of our producing wells. As operator, we design and manage the development of a well and supervise operation and maintenance activities on a day-to-day basis. We employ petroleum engineers, geologists and land professionals who work to improve production rates, increase reserves and lower the cost of operating our oil and natural gas properties.

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Transportation, Markets and Customers

Our marketing strategy seeks to ensure both maximum deliverability of our physical production and maximum realized prices. We leverage our knowledge of markets and transportation infrastructure to enter into favorable downstream processing, treating and marketing contracts. We primarily sell our domestic oil and gas production to third parties at spot market prices, while we sell our NGLs at market prices under monthly or long-term contracts. We typically sell our oil production to a relatively small number of credit-worthy counterparties, as is customary in the industry. For the year ended December 31, 2014, four purchasers accounted for approximately 80% of our oil revenues: Plains Marketing LP, Chevron Corporation, Flint Hills Resources, LP, an affiliate of Koch Industries, and Shell Trading U.S. Co., an affiliate of Shell Oil Company. As oil volumes grow, we anticipate further diversification of our revenue exposure to a wider range of buyers under a mix of short-term and long-term sales agreements. Across all of our operating areas, we maintain adequate gathering, treating, processing and transportation capacity, as well as downstream sales arrangements, to accommodate our growing production volumes.

In our Eagle Ford Shale operating area, we are connected to the Camino Real Gathering System and to the Frio LaSalle Pipeline system. The vast majority of our oil production flows on the Camino Real oil gathering system, a 68-mile long pipeline with over 110,000 Bbls/d of capacity and a gravity bank that allows for oil blending to maintain attractive API levels. We have 80,000 Bbls/d of firm capacity on this oil system, of which we utilized an average of 58% during December 2014. The system delivers oil to the Storey Oil Terminal on Highway 97 east of Cotulla, Texas, six miles southeast of Gardendale. From the Storey Terminal, oil can be pumped into Harvest's Arrowhead #1 and/or #2 pipelines, as well as the recently-added Plains All American Pipeline connection to the Gardendale Hub. Oil can also be loaded into trucks out of the Storey Terminal or out of the numerous central tank batteries throughout our field, providing additional deliverability, reliability and flexibility. We expect our utilization rate on the Camino Real oil gathering system to increase as new wells are connected. We currently market our oil either at the Storey Terminal or at our central tank batteries under a combination of short and long term contracts, ranging from monthly deals to a seven-year term sale. We currently receive a price premium for our Eagle Ford Shale oil relative to NYMEX WTI, due primarily to exposure to waterborne crude markets on the Gulf Coast that price off the Louisiana Light Sweet crude index. With adequate takeaway capacity in the region and close proximity to the Gulf Coast refining complex, we do not anticipate any issues with marketing or delivering additional crude volumes from the Eagle Ford Shale.

Our Eagle Ford natural gas production flows on either the Camino Real gas gathering system or the Frio LaSalle Pipeline system. The majority of our produced gas flows on the Camino Real gas gathering system, which receives high-pressure, unprocessed wellhead gas into an 83-mile pipeline with capacity of 150-170 MMcf/d. The gas is then redelivered into interconnects with Energy Transfer, Enterprise, Regency and Eagle Ford Gathering. We currently have 125 MMcf/d of firm transportation capacity on Camino Real, of which we used an average of 57% during December 2014, and we have additional capacity available as needed. Our capacity utilization will increase as additional wells are connected to the system. We have firm gas gathering, processing and transportation agreements on three of the interconnected gas pipelines downstream of the Camino Real system, with a minimum capacity of approximately 80 MMBtu/d and rights to increase firm capacity as necessary. In addition, gas produced from our northwest acreage position within the Eagle Ford operating area is connected to the Frio LaSalle Pipeline system, which provides access to firm H2S treating and processing. Frio LaSalle can either return gas to the Camino Real system or, after processing, deliver to various Texas intrastate pipelines and a mix of interstates, such as Texas Eastern Transmission, Tennessee Gas Pipeline, and Transco. We market our physical gas to various purchasers at spot market prices.

In our Wolfcamp Shale operating area, we continue to leverage significant legacy gathering, processing and transportation infrastructure. For natural gas, we are connected to the West Texas Gas

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(WTG), DCP and Lucid Energy Group gathering systems, and we process a majority of our gas at the WTG Benedum & Sonora gas plants. We receive Waha pricing for our natural gas and Mont Belvieu pricing for our NGLs. "Waha pricing" refers to the published index price for spot and monthly physical natural gas purchases and sales made into interstate and intrastate pipelines at the outlet of the Waha header system and in the Waha vicinity in the Permian Basin in West Texas. "Mont Belvieu pricing" refers to the spot market price for NGLs delivered into the Mont Belvieu NGL processing and storage hub in Mont Belvieu, Texas. Our crude oil production facilities are connected to a third party oil gathering system that delivers to a Plains pipeline at Owens Station in Reagan County, Texas and to the Centurion Cline Shale Pipeline at Barnhart in Irion County, Texas. We sell our pipeline delivered crude to multiple purchasers under both short and long-term contracts at WTI-based pricing. We also maintain the capability to truck crude oil to those same purchasers under similarly-priced contracts to provide additional flow assurance. During the fourth quarter of 2014, we entered into a new two-year oil sale agreement on a portion of our Wolfcamp volumes with pricing of WTI less a fixed amount, reducing our risk in the fluctuations in the Midland-Cushing differential. With new Permian Basin takeaway pipelines coming online in 2015, we anticipate no limitations moving physical crude oil to market and expect regional pricing to remain correlated with NYMEX/WTI.

In our Altamont operating area, the wax crude we produce is sold at the wellhead to multiple purchasers who transport the oil via truck to downstream refineries or to rail loading facilities. We sell most of the oil we produce in the basin to Salt Lake City refineries under long-term sales agreements that accommodate our production forecasts. In addition, we have entered into a variety of crude-by-rail solutions to expand the market for Altamont wax crude beyond Salt Lake City. We anticipate that planned expansions of Salt Lake City refineries and expanded rail capacity will keep pace with basin-wide production growth, and we continue to develop new market solutions. Our produced natural gas is gathered and processed at the Altamont plant, a third-party-owned processing facility, under a long-term sales agreement that provides for residue gas return for operational use.

In our Haynesville Shale operating area, our gathering facilities are connected to multiple gas takeaway pipeline systems, including Tennessee Gas Pipeline, Enterprise Acadian Gas Pipeline and Enterprise Stateline Gathering. We currently control approximately 245 MMcf/d of firm capacity on these pipelines, of which we used an average of 46% during December 2014. Capacity obligations will drop substantially in early 2015 to approximately half of our year-end 2014 capacity levels. Currently, our Haynesville Shale gas is produced at close to pipeline specifications and requires only CO2 removal before delivery into takeaway pipelines. We sell our physical gas production to a wide variety of purchasers at spot market prices under short-term sales agreements. Given the abundance of pipeline infrastructure in the region and the growing demand for natural gas in the Southeast, we do not anticipate any issues with production deliverability.

While most of our physical production is priced off spot market indices, we actively manage the volatility of spot market pricing through a dynamic and active risk management program. We enter into an array of financial derivatives contracts on our oil and natural gas production to stabilize our cash flows, reduce the risk of downward commodity price movements and protect the economic assumptions associated with our capital investment program. We employ a sophisticated, disciplined risk management program that utilizes rigorous risk control processes and leverages the extensive commodity trading expertise of our staff. For a further discussion of these risk management activities and derivative contracts, see "Management's Discussion and Analysis of Financial Condition and Results of Operations."

Competitors

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 NGLs. Our competitors include major and intermediate sized oil and natural gas companies, independent oil and natural gas

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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.

Use of 3-D Seismic Data

We have an inventory of approximately 2,200 square miles of 3-D seismic data. We have 1,092 square miles of 3-D seismic data in our four operating areas which provides approximately 39% coverage over our leased acreage in those areas. We use the data to identify and optimize drilling locations and completion operations, field development plans and new resource targets. In the Wolfcamp and Altamont plays in particular, we utilize 3-D seismic technologies to help identify areas with natural fractures and use this information to help with the placement of future drill well locations that could result in higher productivity wells.

Regulatory Environment

Our oil and natural gas exploration and production activities are regulated at the federal, state and local levels in the United States. 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 operations under federal oil and natural gas leases are regulated by the statutes and regulations of the Department of Interior (DOI) 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 DOI, which has promulgated valuation guidelines for the payment of royalties by producers. These 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 a process of pumping fluid and proppant (usually sand) under high pressure into deep underground geologic formations that contain recoverable hydrocarbons. These hydrocarbon formations are typically thousands of feet below the surface. The hydraulic fracturing process creates small fractures in the hydrocarbon formation. These fractures allow natural gas and oil to move more freely through the formation to the well and finally to the surface production facilities. We use hydraulic fracturing to maximize productivity of our oil and natural gas wells in our operating areas and our proved undeveloped oil and natural gas reserves will be developed using hydraulic fracturing. For the year ended December 31, 2014, we incurred costs of approximately $556 million associated with hydraulic fracturing.

Hydraulic fracturing fluid is typically composed of over 99% water and proppant, which is usually sand. The other 1% 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

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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 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 and is cemented in place. Surface casing is set on all wells. The purpose of the surface casing is to isolate 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 USDWs.
•: 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 cementing above any hydrocarbon bearing zone and performing casing pressure 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 pumping cement above the confining structure of the target zone and 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 pressure testing of casing and surface equipment and continuous monitoring of surface pressure, pumping rates, volumes of fluids and chemical concentrations 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 and completions operations, we manage waste water to minimize environmental risks and costs. Flowback water returned to the surface is typically contained in steel tanks or pits. Water that is not treated for reuse is typically piped or trucked to waste disposal injection wells, many of which we own and operate. These wells are permitted through Underground Injection Control

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("UIC") program of the Safe Drinking Water Act. We also use commercial UIC permitted water injection facilities for flowback and produced water disposal.

We have not received regulatory citations or notice of suits related to our hydraulic fracturing operations for environmental concerns. We have not experienced a surface release of fluids associated with hydraulic fracturing that resulted in material financial exposure or significant environmental impact. Consistent with local, state and federal requirements, releases are reported to appropriate regulatory agencies and site restoration completed. No remediation reserve has been identified or anticipated as a result of hydraulic fracturing releases experienced to date.

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 significant hydraulic fracturing well control issue.

Environmental

We are subject to existing federal, state and local laws and regulations governing environmental quality, pollution control and greenhouse gas (GHG) emissions. Numerous governmental agencies, such as the EPA, issue regulations which often require difficult and costly compliance measures that carry substantial administrative, civil and criminal penalties and may result in injunctive obligations for non-compliance. These laws and regulations may require the acquisition of a permit before drilling commences, restrict the types, quantities and concentrations of various substances that can be released into the environment in connection with drilling and production activities, limit or prohibit construction or drilling activities on certain lands lying within wilderness, wetlands, ecologically sensitive and other protected areas, require action to prevent or remediate pollution from current or former operations, such as plugging abandoned wells or closing pits, result in the suspension or revocation of necessary permits, licenses and authorizations, require that additional pollution controls be installed and impose substantial liabilities for pollution resulting from our operations or relate to our owned or operated facilities. The strict and joint and several liability nature of such laws and regulations could impose liability upon us regardless of fault. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances, hydrocarbons or other waste products into the environment. Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent and costly pollution control or waste handling, storage, transport, disposal or cleanup requirements could materially adversely affect our operations and financial position, as well as the oil and natural gas industry in general. Our management believes that we are in substantial compliance with applicable environmental laws and regulations and we have not experienced any material adverse effect from compliance with these environmental requirements. This trend, however, may not continue in the future.

The environmental laws and regulations to which we are subject also require us to remove or remedy the effect on the environment of the disposal or release of specified substances at current and former operating sites. As of March 31, 2015, we had accrued and had exposure of approximately $1 million for related environmental remediation costs associated with onsite, offsite and groundwater technical studies and for related environmental legal costs. Our accrual represents a combination of two estimation methodologies. First, where the most likely outcome can be reasonably estimated, that cost has been accrued. Second, where the most likely outcome cannot be estimated, a range of costs is established and if no one amount in that range is more likely than any other, the lower end of the expected range has been accrued. Our environmental remediation projects are in various stages of

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completion. The liabilities we have recorded reflect our current estimates of amounts that we will expend to remediate these sites. However, depending on the stage of completion or assessment, the ultimate extent of contamination or remediation required may not be known. As additional assessments occur or remediation efforts continue, we may incur additional liabilities.

Climate Change and Other Emissions. The EPA and several state environmental agencies have adopted regulations to regulate GHG emissions. Although the EPA has adopted a "tailoring" rule to regulate GHG emissions, the U.S. Supreme Court partially invalidated it in an opinion decided June 2014. The tailoring rule remains applicable for those facilities considered major sources of six other "criteria" pollutants and at this time we do not expect a material impact to our existing operations from the rule. 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, which will generally favor the use of natural gas over other fossil fuels such as coal. It remains uncertain what regulations will ultimately be adopted and when they will be adopted. As part of the White House's Climate Action Plan Strategy to Reduce Methane Emissions, the EPA has announced it will propose additional regulations in 2015 for the oil and gas industry addressing methane and other emissions. Further, the Bureau of Land Management is expected to propose additional regulations for public lands in 2015, and the Pipeline and Hazardous Materials Safety Administration is expected to propose new standards in 2015 for natural gas pipelines. Any regulations regarding GHG emissions would likely increase our costs of compliance by potentially delaying the receipt of permits and other regulatory approvals; requiring us to monitor emissions, install additional equipment or modify facilities to reduce GHG and other emissions; purchase emission credits; and utilize electric-driven compression at facilities to obtain regulatory permits and approvals in a timely manner.

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

In August 2012, the EPA promulgated additional standards to reduce various air pollutants associated with hydraulic fracturing of natural gas wells and equipment including compressors, storage vessels, and pneumatic valves. Parts of the new standard were amended August 2013. We do not anticipate material capital expenditures to meet these requirements. Effective December 31, 2014, additional amendments to the new standard were finalized, for which we do not anticipate material capital expenditure.

The EPA has promulgated regulations to require pre-construction permits for minor sources of air emissions in tribal lands as of September 2, 2014. On May 22, 2014, the EPA extended this deadline to March 2, 2016, during which time the EPA anticipates separate rulemaking to create general permits for true minor sources in the oil and gas production industry. Until such regulations are adopted, it is uncertain what impact they might have on our operations in tribal lands.

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 and Department of Energy are reviewing changes in their regulations to address the environmental impacts of hydraulic fracturing operations. Recently, on March 26, 2015, the Bureau of Land Management (BLM) published final rules for hydraulic fracturing on federal and certain tribal lands, including use of tanks for recovered water, updated cementing and testing requirements, and disclosure of chemicals used in hydraulic fracturing. Although we are reviewing these amendments, there is no expected material cost associated with the Company's 2015 program.

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Comprehensive Environmental Response, Compensation and Liability Act ("CERCLA") Matters. As part of our environmental remediation projects, we are or have received notice that we could be designated as a Potentially Responsible Party (PRP) with respect to one active site under the CERCLA or state equivalents. As of March 31, 2015, we have estimated our share of the remediation costs at this site to be less than $1 million. Because the clean-up costs are estimates and are subject to revision as more information becomes available about the extent of remediation required, and because in some cases we have asserted a defense to any liability, our estimates could change. Moreover, liability under the federal CERCLA statute may be joint and several, meaning that we could be required to pay in excess of our pro rata share of remediation costs. Our understanding of the financial strength of other PRPs has been considered, where appropriate, in estimating our liabilities. Accruals for these matters are included in the reserve for environmental matters discussed above.

Waste Handling. Administrative, civil and criminal penalties can be imposed for failure to comply with waste handling requirements imposed under the Resource Conservation and Recovery Act, as amended, and comparable state laws. We believe that we are in substantial compliance with applicable requirements related to waste handling, and that we hold all necessary and up-to-date permits, registrations and other authorizations to the extent that our operations require them under such laws and regulations. Any legislative or regulatory reclassification of oil and natural gas exploration and production wastes could increase our costs to manage and dispose of such wastes.

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.

Facilities and Employees

Our principal executive offices are located at 1001 Louisiana Street, Houston, Texas 77002. Our telephone number is (713) 997-1000. As of June 1, 2015, we had 676 full-time employees in the United States. We also hire independent contractors.

Legal Proceedings

From time to time, we are a party to ongoing legal proceedings in the ordinary course of business, including workers' compensation claims and employment related disputes. We do not believe the results of these proceedings, individually or in the aggregate, will have a material adverse effect on our business, financial condition, results of operations or liquidity. For additional information, see Note 7 to our historical consolidated financial statements and related notes included elsewhere in this prospectus.

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MANAGEMENT

The following table provides information regarding the executive officers of the Issuer and the members of the board of directors of Parent (the "Board") with ages as of June 1, 2015. The supervision of the Issuer's management and the general course of its affairs and business operations is entrusted to the Board, which currently consists of twelve members.

		Position

Brent J. Smolik	54	President, Chief Executive Officer and Chairman of the Board
Clayton A. Carrell	49	Executive Vice President and Chief Operating Officer
Joan M. Gallagher	51	Senior Vice President, Human Resources and Administrative Services
Dane E. Whitehead	53	Executive Vice President and Chief Financial Officer
Marguerite N. Woung-Chapman	49	Senior Vice President, General Counsel and Corporate Secretary
Ralph Alexander	60	Director
Gregory A. Beard	43	Director
Wilson B. Handler	30	Director
John J. Hannan	62	Director
Michael S. Helfer	69	Director
Thomas R. Hix	67	Director
Ilrae Park	48	Director
Keith O. Rattie	61	Director
Robert M. Tichio	37	Director
Donald A. Wagner	51	Director
Rakesh Wilson	40	Director

Brent J. Smolik. Mr. Smolik has been our President and Chief Executive Officer since May 2012 and Chairman of the Board since August 2013, and previously served as Chairman of the Board of Managers of EPE Acquisition, LLC from May 2012 to August 2013. He was previously Executive Vice President and a member of the Executive Committee of El Paso Corporation and President of our predecessor, EP Energy Corporation (a/k/a/ El Paso Exploration & Production Company), from November 2006 to May 2012. 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 directors of Cameron International Corporation, the American Exploration and Production Council and the Producers for American Crude Oil Exports. 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. With over 30 years of energy industry experience, Mr. Smolik brings a comprehensive knowledge and understanding of our business to the Board and provides the Board with essential insight and guidance from an inside perspective on the day-to-day operations of our company.

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), from June 2010 to May 2012. 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

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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 from March 2011 to May 2012. From August 2005 until February 2011, she served as Vice President, Human Resources of our predecessor, 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 also had 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.

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 from October 2009 to May 2012. 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 from November 2009 to May 2012. 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.

Ralph Alexander. Mr. Alexander has been a director of the Board since September 2013. Mr. Alexander is a Managing Director of Riverstone Holdings LLC and joined Riverstone in September 2007. During 2007, Mr. Alexander served as a consultant to TPG Capital. For nearly 25 years, Mr. Alexander served in various positions with subsidiaries and affiliates of BP plc, one of the world's largest energy firms. From June 2004 until December 2005, he served as Chief Executive Officer of Innovene, BP's $20bn olefins and derivatives subsidiary. From 2001 until June 2004, he served as Chief Executive Officer of BP's Gas, Power and Renewables and Solar segment and was a member of the BP group executive committee. Prior to that, Mr. Alexander served as a Group Vice President in BP's Exploration and Production segment and BP's Refinery and Marketing segment. He held responsibilities for various regions of the world, including North America, Russia, the Caspian, Africa and Latin America. Prior to these positions, Mr. Alexander held various positions in the upstream, downstream and finance groups of BP. In addition to serving on the boards of a number of Riverstone portfolio companies and their affiliates, Mr. Alexander serves on the board of directors of Niska Gas Storage Partners LLC. He previously served on the boards of Stein Mart Corporation, KiOR Inc., Amyris, Inc., Foster Wheeler AG and Anglo American plc. He holds a BS and MS in

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nuclear engineering from Brooklyn Polytech (now NYU Polytechnic) and holds an MS in management science from Stanford University. He is currently Chairman of the Board of NYU Polytechnic and is a New York University Trustee. Mr. Alexander was appointed to the Board by Riverstone. We believe Mr. Alexander's extensive experience with the energy industry enables him to provide important insight and guidance to our management team and the Board.

Gregory A. Beard. Mr. Beard has been a director of the Board since August 2013 and previously served as a member of the Board of Managers of EPE Acquisition, LLC from May 2012 to August 2013. Mr. Beard joined Apollo in June 2010 as the Global Head of Natural Resources, based in the New York office. Mr. Beard joined Apollo with 19 years of investment experience, the last ten of which were 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 also served on the board of directors of many oil and natural gas companies including, Belden & Blake Corporation, Canera Resources, Cobalt International Energy, Eagle Energy, Legend Natural Gas I-IV, Mariner Energy, Phoenix Exploration, Titan Operating, Vantage Energy and Virginia Uranium. Mr. Beard has served on the board of directors of various oilfield services companies, including CDM Max, CDM Resource Management, and International Logging. Mr. Beard currently serves on the board of directors of Apex Energy, LLC, Caelus Energy Alaska, LLC, CSV Midstream Solutions GP LLC, Double Eagle Energy Holdings, LLC, Double Eagle Energy Holdings II, LLC, Jupiter Resources GP LLC, NRI Management Group, LLC, Pinnacle Agriculture Holdings, LLC, and Talos Energy, LLC and previously served as a director of Athlon Energy Inc. Mr. Beard received his BA from the University of Illinois at Urbana. Mr. Beard was appointed to the Board by Apollo. Based upon Mr. Beard's extensive investment and management experience, particularly in the energy sector, his strong financial background and his service on the boards of multiple oil and natural gas exploration and production companies and oilfield services companies, which have provided him with a deep working knowledge of our operating environment, we believe that he possesses the requisite skills to serve as a member of our Board.

Wilson B. Handler. Mr. Handler has been a director of the Board since November 22, 2013. Mr. Handler is a principal of Apollo and joined the firm in 2011. Prior to joining Apollo, Mr. Handler was an investment professional at First Reserve, where he was involved in the execution and monitoring of investments in the energy sector. Previously, he worked in the Investment Banking Division at Lehman Brothers in the Natural Resources group. Currently, Mr. Handler serves on the board of directors of CSV Mistream Solutions GP LLC and Jupiter Resources LLC and previously served as a director of Athlon Energy Inc. Mr. Handler graduated from Dartmouth College with an AB in Economics and Government. Mr. Handler was appointed to the Board by Apollo. Based upon Mr. Handler's extensive investment experience, his knowledge of the Company and experience in the energy industry, we believe he possesses the requisite skills to serve as a member of our Board.

John J. Hannan. Mr. Hannan has been a director of the Board since December 2013. Mr. Hannan is Chairman of the Board of Directors of Apollo Investment Corporation, a public investment company. He served as Chief Executive Officer of Apollo Investment Corporation from 2006 to 2008. Mr. Hannan, a senior partner of Apollo Management, L.P., co-founded Apollo Management, L.P. in 1990. Mr. Hannan is an advisor to Apollo's Natural Resources group. He has been on several public boards including Vail Resorts, Inc. and Goodman Global, Inc., and is currently on the board of Environmental Solutions Worldwide and Brown University. Mr. Hannan is actively involved in charitable organizations. He received a BBA from Adelphi University and an MBA from the Harvard Business School. Mr. Hannan was appointed to the Board by Apollo. Based on Mr. Hannan's strong investment and management experience and his service on multiple boards of

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directors, we believe that Mr. Hannan possesses the requisite set of skills to serve as a member of our Board.

Michael S. Helfer. Mr. Helfer has been a director of the Board since January 2014. He is also a director of Grupo Financiero Banamex, S.A.de C.V. ("Banamex") and certain of its wholly-owned subsidiaries. Banamex is a wholly-owned subsidiary of Citigroup Inc. Mr. Helfer is Managing Director of Ice Glen Group LLC, which provides financial and strategic advice to clients. Mr. Helfer was Vice Chairman of Citigroup, Inc. from June 2012 until his retirement in March 2014. From February 2003 until May 2012, he served as General Counsel and Corporate Secretary of Citigroup. Mr. Helfer is a member of the Council on Foreign Relations and the American Law Institute. He has served as Chairman of the New York Clearing House Association, Chairman of the Legal Aid Society of the District of Columbia, as a member of the Board of Directors of Lincoln Center Theater, and as a Trustee of the Wexner Center for the Arts. Based upon Mr. Helfer's extensive management, business and leadership experience, we believe that he possesses the requisite set of skills to serve as a member of our Board.

Thomas R. Hix. Mr. Hix has served as a director of the Board since April 2014. Mr. Hix has been a business consultant since January 2003, and previously served as Senior Vice President of Finance and Chief Financial Officer of Cooper Cameron Corporation from 1995 until his retirement in 2003. Prior to that time, Mr. Hix held several executive level finance and accounting positions in the energy industry. Mr. Hix currently serves on the board of directors of the general partner of Western Gas Equity Partners LP, as a director of Rowan Companies, PLC., and as a director of Health Care Service Corporation (a Chicago-based company operating through its Blue Cross and Blue Shield divisions in Illinois, Texas, Oklahoma and New Mexico). He also serves as a director of various non-profits, including the Houston Zoo. Mr. Hix previously served as a director of El Paso Corporation from 2004 to May 2012. Mr. Hix holds a Bachelor of Business Administration in Accounting from Texas Tech University and an MBA from Pepperdine University. As a former chief financial officer of a large, publicly-traded energy company, Mr. Hix has significant expertise in finance and accounting. Mr. Hix also provides the Board with valuable public company operating and management experience.

Ilrae Park. Mr. Park has been a director of the Board since August 2013 and previously served as a member of the Board of Managers of EPE Acquisition, LLC from December 2012 to August 2013. Mr. Park joined Korea National Oil Corporation (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 United States. He is currently the Representative and Managing Director of the U.S. Business Unit of KNOC under which three subsidiaries are running E&P businesses. At the same time, in the United States he is serving as President and board member for KNOC Eagle Ford Corporation and Executive 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 by KNOC. Based on Mr. Park's engineering background and extensive experience in the energy industry, we believe that Mr. Park possesses the requisite set of skills to serve as a member of our Board.

Keith O. Rattie. Mr. Rattie has been a member of the Board since January 2015. Mr. Rattie is the retired Chairman, President and Chief Executive Officer of Questar Corporation. He served as President of Questar from January 2001 to July 2010, as its Chief Executive Officer from May 2002 to July 2010, and as its Chairman from May 2003 to July 2012. He recently retired as a Questar director in May 2014. He also served as chairman of the board of QEP Resources following its spin-off from Questar from July 2010 until May 2012. He retired from the QEP board in February 2014. Mr. Rattie currently serves on the board of directions of Ensco plc, Rockwater Energy Solutions, and Zions First

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National Bank. He is the past chair of INGAA, and has served on the National Petroleum Council and the board of the Gas Technology Institute. Mr. Rattie has a BS degree in electrical engineering from the University of Washington and an MBA from St. Mary's College. As the former CEO of a publicly traded company, Mr. Rattie brings extensive management, business and leadership skills to our Board. Mr Rattie also provides the Board with valuable upstream and downstream E&P operations experience.

Robert M. Tichio. Mr. Tichio has been a director of the Board since September 2013. Mr. Tichio is a Partner of Riverstone Holdings LLC and joined Riverstone in 2006. Prior to joining Riverstone, Mr. Tichio was in the Principal Investment Area (PIA) of Goldman Sachs which manages the firm's private corporate equity investments. Mr. Tichio began his career at J.P. Morgan in the Mergers & Acquisition group where he concentrated on assignments that included public company combinations, asset sales, takeover defenses and leveraged buyouts. In addition to serving on the boards of a number of Riverstone portfolio companies and their affiliates, Mr. Tichio has served as a member of the board of directors of Northern Blizzard Resources Inc. since June 2011 and as a director of Midstates Petroleum Company, Inc. since October 2012 (expected to resign by end of March 2015). Mr. Tichio previously served as a member of the board of directors of Gibson Energy (TSE:GEI) from 2008 to 2013 and is a member of the Board of Visitors of the Nelson A. Rockefeller Center at Dartmouth College. He holds an MBA from Harvard Business School and a bachelor's degree from Dartmouth College. Mr. Tichio was appointed to the Board by Riverstone. We believe Mr. Tichio's extensive energy industry background, particularly his expertise in mergers and acquisitions, brings important experience and skill to our Board of Directors.

Donald A. Wagner. Mr. Wagner has been a director of the Board since August 2013 and previously served as a member of the Board of Managers of EPE Acquisition, LLC from May 2012 to August 2013. 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 AB in physics from Harvard College. Mr. Wagner was appointed to the Board by Access. Based upon Mr. Wagner's experience as a director of various companies, including public companies, and over 25 years of experience in investing, banking and private equity, we believe that Mr. Wagner possesses the requisite set of skills to serve as a member of our Board.

Rakesh Wilson. Mr. Wilson has been a director of the Board since August 2013 and previously served as a member of the Board of Managers of EPE Acquisition, LLC from May 2012 to August 2013. Mr. Wilson is a Partner of Apollo and joined Apollo in 2009. 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. 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 CSV Midstream Solutions GP LLC, Jupiter Resources GP LLC, Talos Energy, LLC and Express Energy Securities, LLC and previously served as a director of Athlon Energy Inc. and Parallel Petroleum. Mr. Wilson graduated from the University of Texas at Austin and received his MBA from INSEAD, Fontainebleau, France. Mr. Wilson was appointed to the Board by Apollo. We believe that Mr. Wilson's extensive international investment and risk management experience, his knowledge of the Company and his service on multiple boards have provided him with a strong understanding of the financial, operational

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and strategic issues facing public companies in our industry, and that he possesses the requisite set of skills to serve as a member of our Board.

Board Composition

The supervision of our management and the general course of our affairs and business operations is entrusted to the Board. The Board is currently comprised of 12 directors, with (i) four designated by Apollo, (ii) two designated by Riverstone, (iii) one designated by Access, (iv) one designated by KNOC, (v) our chief executive officer and (vi) three independent directors. In addition, Apollo has the right (but is not required) to designate an additional non-independent director. Apollo also has the right to designate any director as the Chairman of the Board and our chief executive officer, Mr. Smolik, currently serves in that capacity.

The Board is divided into three classes. The members of each class serve staggered, three-year terms (other than with respect to the initial terms of the Class I and Class II directors, which are for one and two years, respectively). Upon the expiration of the term of a class of directors, directors in that class will stand for re-election for an additional three-year term at the annual meeting of stockholders in the year in which their term expires.

•: Ilrae Park, Donald A. Wagner, Rakesh Wilson and Thomas R. Hix are Class II directors, whose initial terms will expire at the 2016 annual meeting of stockholders of Parent;
•: Gregory A. Beard, Keith O. Rattie, Robert M. Tichio and Brent J. Smolik are Class III directors, whose initial term will expire at the 2017 annual meeting of stockholders of Parent; and
•: Ralph Alexander, Wilson B. Handler, John J. Hannan and Michael S. Helfer are Class I directors, each of whom were re-elected at the 2015 annual meeting of stockholders of Parent, and whose current terms will expire at the 2018 annual meeting of stockholders of Parent.

Any additional directorships resulting from an increase in the number of directors will be distributed among the three classes so that, as nearly as possible, each class will consist of one-third of our directors.

Committees of the Board

Parent's stockholders agreement provides that for so long as each Sponsor has the right to designate a director or an observer to the Board, Parent will cause any committee of the Board to include in its membership such number of members that are consistent with, and reflects, the right of each Sponsor to designate a director or observer to the Board, except to the extent that such membership would violate applicable securities laws or stock exchange or stock market rules.

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The Board has established three standing committees to assist the Board in carrying out its duties: the Audit Committee, the Compensation Committee and the Governance and Nominating Committee. We describe the committees, their current membership and their principal responsibilities below.

Name

Ralph Alexander	Member
Gregory A. Beard	Member		Chair	Member
Wilson B. Handler	Member		Member	Member
John J. Hannan	Member
Michael S. Helfer*	Member	Member	Member	Chair
Thomas R. Hix*	Member	Chair	Member
Ilrae Park	Member		Member	Member
Keith O. Rattie*	Member	Member
Brent J. Smolik	Chairman
Robert M. Tichio	Member		Member	Member
Donald A. Wagner	Member		Member	Member
Rakesh Wilson	Member		Member	Member

*: Independent Board member.

Audit Committee

The Audit Committee consists of three members: Messrs. Hix (Chair), Helfer and Rattie. Each member of the Audit Committee satisfies the financial literacy and independence requirements of the NYSE listing standards. No Audit Committee member serves on more than three audit committees of public companies, including our Audit Committee.

The primary purpose of the Audit Committee is to assist the Board in fulfilling its oversight responsibilities with respect to:

•: the company's independent registered public accounting firm's qualifications and independence;
•: the company's third party petroleum reserves engineer;
•: the audit of the company's financial statements;
•: the performance of the company's internal audit function and independent registered public accounting firm; and
•: the preparation of the report of the Audit Committee to be included in the company's annual proxy statement under the rules of the SEC.

Our principal independent auditor, Ernst & Young LLP, reports directly to the Audit Committee. In addition, the Audit Committee provides an open avenue of communication between the internal auditors, the independent auditor and the Board.

The Audit Committee Charter can be found on our website atwww.epenergy.com.

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Compensation Committee

The Compensation Committee consists of eight members: Gregory A. Beard (chair), Wilson B. Handler, Michael S. Helfer, Thomas R. Hix, Ilrae Park, Robert M. Tichio, Donald A. Wagner and Rakesh Wilson. Parent is a "controlled company" under NYSE listing rules; as a result, it is not required to have a compensation committee composed entirely of independent directors.

The primary purpose of the Compensation Committee is to assist the Board in fulfilling its responsibility to:

•: oversee the company's management compensation policies and practices;
•: formulate, evaluate and approve the compensation and employment arrangements of the company's executive officers;
•: set, review and approve corporate goals and objectives relevant to officer compensation;
•: evaluate the performance of the CEO and his direct reports and based on this evaluation approve the compensation of such individuals;
•: oversee all compensation programs involving the issuance of equity under any equity compensation programs the company may institute from time to time; and
•: review and discuss with management the company's compensation discussion and analysis to be included in the company's annual proxy statement filed with the SEC.

The Compensation Committee Charter can be found on our website atwww.epenergy.com.

Compensation Consultant Independence and Payments

The Compensation Committee has retained Frederic W. Cook & Co. ("FW Cook") as its independent compensation consultant. The compensation consultant is directly accountable to the Compensation Committee and the committee reviews all fees paid to the consultant for executive compensation advice. The Compensation Committee reviews, on an annual basis, the performance of the compensation consultant and provides the consultant with feedback. In addition, the Compensation Committee evaluated and confirmed that the compensation consultant has no conflicts of interest in its provision of executive compensation consulting services to the committee. Fees paid to FW Cook in 2014 for executive compensation consulting to the Compensation Committee were $226,524.

Compensation Committee Interlocks and Insider Participation

No member of the Compensation Committee is a former or current officer or employee of Parent. In addition, none of our executive officers serve as a member of the compensation committee or board of directors of another entity, one of whose executive officers serve on the Compensation Committee or the Board.

Governance and Nominating Committee

The Governance and Nominating Committee consists of seven members: Michael S. Helfer (chair), Gregory A. Beard, Wilson B. Handler, Ilrae Park, Robert M. Tichio, Donald A. Wagner and Rakesh Wilson. Parent is a "controlled company" under NYSE listing rules; as a result, it is not required to have a governance and nominating committee composed entirely of independent directors.

The primary purpose of the Governance and Nominating Committee is to assist the Board in fulfilling its responsibility to:

•: identify individuals qualified to serve as directors of the company and on committees of the Board, consistent with criteria approved by the Board and Parent's stockholders agreement,

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•: select the director nominees for the next annual stockholder meeting consistent with the criteria approved by the Board and Parent's stockholders agreement;
•: advise the Board with respect to the Board composition, procedures and committees;
•: develop and recommend to the Board a set of corporate governance guidelines applicable to the company; and
•: oversee the annual performance evaluation of the Board.

The Governance and Nominating Committee Charter can be found on our website atwww.epenergy.com.

Code of Ethics

We have adopted a code of ethics, referred to as our "Code of Conduct," that applies to all of our directors and 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 atwww.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.

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COMPENSATION DISCUSSION AND ANALYSIS

The following compensation discussion and analysis, or CD&A, provides information relevant to understanding the 2014 compensation of the executive officers identified in the Summary Compensation Table below, who we refer to as our named executive officers. Executive compensation decisions are made by the compensation committee of the Board, and relate to the current positions the officers hold as executive officers of EP Energy. Unless otherwise noted, the information provided in this CD&A reflects compensation earned by our named executive officers while employed by us pursuant to the design and objectives of Parent's executive compensation programs. Our named executive officers include the following individuals:

Name		Title

Brent J. Smolik		Chairman of the Board, President and CEO
Dane E. Whitehead		Executive Vice President and CFO
Clayton A. Carrell		Executive Vice President and COO
Marguerite N. Woung-Chapman		Senior Vice President, General Counsel and Corporate Secretary
Joan M. Gallagher		Senior Vice President, Human Resources and Administrative Services
John D. Jensen(1)		Executive Vice President, Operations Services

(1): John D. Jensen voluntarily resigned from the company on May 31, 2014. His compensation information for 2014 is being presented in this CD&A and in the applicable executive compensation tables in accordance with SEC reporting requirements for executive officers who departed during the last fiscal year, but whose total compensation that was actually paid during the fiscal year would have placed them among the three most highly compensation executive officers (other than the CEO and CFO).

This discussion is divided into the following sections:

I.: Executive Summary
II.: Setting Executive Officer Compensation
III.: Elements of Total Compensation Program
IV.: 2014 Compensation Decisions
V.: Other Compensation Matters

I. Executive Summary

Compensation Program Philosophy and Design. The core of our executive compensation program is pay for performance. A significant portion of each executive's total annual compensation is at risk and dependent upon our company's achievement of specific, measurable performance goals. Our performance-based pay is designed to align our executive officers' interests with those of our stockholders and to promote the creation of stockholder value, without encouraging excessive risk-taking. In addition, our equity program rewards long-term stock performance and is designed to encourage retention following a Sponsor exit. The framework of our executive compensation program, which incorporates what we believe are top governance practices, is set forth below:

•: we provide our named executive officers with total annual compensation that includes three principal elements: base salary, annual cash incentive awards, and long-term equity-based incentive awards;
•: our annual cash incentive awards are based on achievement of pre-established financial, operational and safety performance goals, as well as individual performance;

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•: the compensation committee of the Board (the "Compensation Committee") also considers the relative total shareholder return ("TSR") of Parent in determining the amount of any annual cash incentive awards;
•: our 2014 long-term incentive awards included stock options and restricted stock awards of Parent, with delayed 3-year ratable vesting;
•: our named executive officers hold Class B shares of Parent granted in 2012 that become payable only upon a liquidity event where our Sponsors receive a return of at least one times their invested capital in our company;
•: we do not provide tax gross-ups on executive perquisites;
•: our executives officers and independent directors are subject to meaningful stock ownership requirements;
•: we have adopted a policy prohibiting our executive officers and directors from pledging or hedging shares of our stock;
•: we have a compensation recoupment ("clawback") policy that applies to our executive officers and others selected by the Board;
•: our 2014 Omnibus Incentive Plan incorporates double-trigger vesting upon a change in control, meaning both a change in control and an involuntary without cause or good reason termination of employment must occur;
•: our 2014 Omnibus Incentive Plan precludes option repricing without stockholder consent;
•: the Compensation Committee retains an independent compensation consultant to advise on executive compensation matters and best practices; and
•: the Compensation Committee reviews our compensation program to ensure that it does not provide incentives for excessive risk-taking.

2014 Financial and Operational Performance. Highlights of the company's performance over the past year include:

•

Operational and Financial Execution

•: Increased oil production 51% to a record 97.7 MBOED
•: Increased Adjusted EBITDAX* 36% to a record $1,547 million
•: Maintained a sector-leading hedge program that provides multi-year price protection

•

Long-term Value Creation

•: Increase proved oil and gas reserves 18% to 662 MMBOE at year end
•: Increased inventory 10% with the addition of 500+ future drilling locations, bringing us to a total of nearly 5,700 drilling locations

•

Transition and Portfolio Activities

•: Parent became publically traded on the NYSE on January 17, 2014

*: See "Management's Discussion and Analysis of Financial Condition and Results of Operations—Supplemental Non-GAAP Measures."

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•: Further concentrated our asset base within our current operating areas with the sale of legacy Arklatex Cotton Valley natural gas properties and conventional South Louisiana Wilcox oil and gas properties
•: Expanded our current Wolfcamp position by 25% with the acquisition of 37,000 net acres of producing properties and undeveloped acreage in the Southern Midland Basin

Despite strong financial and operational performance, Parent's TSR performance relative to its peer group during 2014 was in the third quartile (36th percentile using a 5-day moving average), and this result was taken into account by the Compensation Committee in making compensation decisions for 2014 performance.

Annual Cash Incentive Awards for 2014 Performance. Financial and operational performance metrics set for the 2014 annual cash incentive awards (the "2014 scorecard") were achieved at above target levels. However, the Compensation Committee elected to reduce the 2014 scorecard payout to target level in consideration of Parent's third-quartile relative TSR performance for 2014, as well as the steep drop in oil prices in late 2014 and its negative impact on operating cash flow, oil and gas reserves and reserve replacement costs, among other factors. Consequently, cash incentive awards for the named executive officers for 2014 performance were generally paid at target.

2014 Long-Term Incentive Awards. Following Parent's initial public offering in early 2014, the Compensation Committee granted our named executive officers certain long-term incentive awards, effective as of April 1, 2014. The grants consisted of an approximate 50/50 mix of stock options and restricted stock (based on grant date fair value), with delayed 3-year vesting. The value of the awards were set below market-median levels (at approximately 25% of market-median for each named executive officer for 2014) in recognition of the potential value of the Class B shares that were previously granted to the executives in 2012. The equity awards incorporated a delayed three-year ratable vesting schedule, with the first tranche vesting in 2017 (or earlier in event of complete sell-down by certain of our Sponsors of their company share holdings).

2015 Base Salary Freeze. At its February 2015 meeting, the Compensation Committee determined it would be prudent to freeze base salaries at 2014 levels for our named executive officers as part of the company's efforts to control costs. Consequently, our named executive officers will not receive base salary increases in 2015.

II. Setting Executive Officer Compensation

Role of Compensation Committee

The 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 independent compensation consultant as well as from our human resources department and management to assist in compensation determinations.

Role of Compensation Consultant

The Compensation Committee has retained FW Cook as its independent compensation consultant. FW Cook advises the committee on an ongoing basis with regard to the general compensation landscape and trends in executive and director compensation matters, including (i) competitive benchmarking, (ii) incentive plan design, (iii) performance metrics, (iv) public offering-related compensation considerations, (v) compensation risk-management, and (vi) updates on compensation trends and regulatory matters affecting compensation. FW Cook attends meetings of the Compensation Committee, participates in the committee's executive sessions, and is directly accountable to the

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committee. In addition, the Compensation Committee reviews FW Cook's performance on an annual basis and provides direct feedback. FW Cook is an independent compensation consulting firm and provides no services to us other than the executive compensation consulting services provided to the committee.

Role of Management and CEO in Determining Executive Compensation

While the Compensation Committee is responsible for approving and monitoring all compensation for our named executive officers, management plays a supporting role in determining executive compensation. At the Compensation Committee's request, management recommends appropriate company-wide financial and non-financial performance goals for annual incentive awards. Management works 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 makes compensation decisions for him independently.

Use of Peer Group Comparisons

The Compensation Committee has established a peer group to assist with executive compensation analysis and to compare TSR relative to our performance. TSR is a discretionary factor that the Compensation Committee considers, along with the 2014 scorecard and individual performance, in determining annual cash incentives. Each year, the committee reviews and re-confirms the composition of the company's peer group to ensure that the companies selected are appropriate. As part of this process, in May 2014 the committee, with assistance from its independent compensation consultant, evaluated the peer group in terms of market competitors, organization size and business characteristics, and overall group appropriateness. The Compensation Committee then reviewed total revenues and market capitalization of each company to determine an appropriate peer group. Based on this analysis, the Compensation Committee elected to make the following revisions to the peer group for use starting with the 2014 performance year to more closely align our peer group with companies that have comparable overall financial metrics as our company: the removal of EQT Corporation, LINN Energy and Noble Energy, and the addition of Antero Resources, Halcon Resources, Oasis Petroleum, and Rosetta Resources. No other changes were made. The table below sets forth our 2014 peer group.

Antero Resources Corp.
Cabot Oil & Gas Corp.
Cimarex Energy Co.
Concho Resources Inc.
Continental Resources Inc.
Denbury Resources Inc.
Halcon Resources Corp.

Newfield Exploration Co.
Oasis Petroleum Inc.
Pioneer Natural Resources Co.
QEP Resources Inc.
Range Resources Corp.
Rosetta Resources Inc.
SandRidge Energy Inc.

SM Energy Co.
Southwestern Energy Co.
Ultra Petroleum Corp.
Whiting Petroleum Corp.
WPX Energy Inc.

Competitive Benchmark Data

When making compensation decisions, we review the compensation paid to our CEO and other named executive officers relative to the compensation paid to similarly-situated executives at our peer companies. This practice is often referred to as "benchmarking." We also utilize survey data representing the market of companies in which we compete for executive talent as an additional means of benchmarking. We believe benchmarks are helpful and provide a point of reference, although they are not definitive.

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The Compensation Committee generally sets total direct compensation targets (sum of base salary, annual cash incentive and long-term incentive awards) for our executives near the market median of our peers. However, because comparative data is just one of several considerations used in determining executive officer compensation, actual pay may vary from the median of comparative compensation based on various factors, including:

•: company performance;
•: individual performance;
•: TSR performance;
•: scope of job responsibilities;
•: market conditions;
•: competitive pressures for that position within the industry; and
•: internal equity considerations.

For example, actual 2014 total cash compensation (2014 base salary plus annual cash incentive paid in March 2014) for our named executive officers was between 72%-99% of the market median of our peer group (based on the most recently available information disclosed in the peer companies' 2014 proxy statements). In addition, in evaluating 2014 long-term incentive targets, the committee considered the potential value of the Class B grants previously issued to the executives in 2012 and elected to grant below market-median 2014 long term incentive awards to reflect the potential upside associated with the Class B shares. Consequently, 2014 long term incentive awards for our named executive officers were made at between 22%-28% of the market median of our peer group.

III. Elements of Total Compensation Program

The table below summarizes the elements of EP Energy's 2014 executive compensation program.



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 pay relative to market
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

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Compensation Element	Objective	Key Features
Long-Term Incentive Awards	To reward stock price appreciation and encourage retention following Sponsor exit	Post-IPO equity awards granted at 25% of market median levels in 2014, with grant value allocated 50% in restricted stock and 50% in stock options Awards have delayed 3-year ratable vesting with first tranche vesting in 2017, second tranche in 2018 and third tranche in 2019 (with vesting commencing earlier in event of complete sell-down by Apollo and Riverstone of their common stock holdings)

Legacy Long-Term Equity Awards (Class B shares)*	To align interests of executive officers with our equity owners and encourage retention	One-time equity award of Class B shares made in 2012 with the following terms:
		• issued at no cost to the named executive officers and have value only to the extent the value of company increases
		• vest ratably over 5 years but accelerate in connection with certain liquidity events
		• become payable only upon occurrence of certain liquidity events where Sponsors receive a return of at least 1 times their invested capital in the company

Qualified 401(k) Plan	To provide retirement savings in a tax-efficient manner	Retirement benefits are provided under the following qualified 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 (based on IRS limits)

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Compensation Element	Objective	Key Features
		• company contributes an additional "retirement contribution" equal to 5% of each participant's eligible compensation annually (based on IRS limits)

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 2¹/2 times the executive officer's annual salary

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 sum of annual salary + target bonus for CEO; 2X sum of annual salary + target bonus for other named executive officers
		• pro-rata bonus for year in which termination occurs
		• 36 months of benefits continuation for CEO; 24 months for other named executive officers

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Compensation Element	Objective	Key Features
Perquisites	Limited perquisites provided to assist executives in carrying out duties and increase productivity	Includes financial planning assistance and subsidized annual physical examinations

*: These long-term equity awards were granted in 2012 and are being described in this CD&A to illustrate the overall mix of long-term incentive awards currently held by our named executive officers

IV. 2014 Compensation Decisions

2014 Annual Base Salaries and 2014 Target Bonus Opportunities

We entered into employment agreements with each of our named executive officers 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. In February 2014, the Compensation Committee elected to increase base salary levels for all of our named executive officers effective as of April 1, 2014. Salary increases were generally between 2%-5%. In addition, in the fall of 2014, the Compensation Committee reviewed base salary levels and elected to further increase the base salary levels of Mr. Carrell and Ms. Gallagher, effective as of October 1, 2014. These late-2014 salary increases were made to recognize the increased responsibilities of the respective executives: (i) in the case of Mr. Carrell, following an internal reorganization that occurred subsequent to the voluntary resignation of the company's executive vice president of operation services in May 2014, and (ii) in the case of Ms. Gallagher, following her assumption of additional leadership responsibilities for the company's IT function in April 2014. No adjustments were made to the named executive officers' 2014 target bonus opportunities, with the exception of the changes noted below for Ms. Woung-Chapman and Ms. Gallagher, which the Compensation Committee believes continue to be appropriate and commensurate with the responsibilities of the respective executives. The bonus target increases for Ms. Woung-Chapman and Ms. Gallagher were made to position each executive's bonus target more competitive with market levels and to recognize internal equity considerations. The following tables set forth the base salaries and annual target bonus opportunities for our named executive officers for 2014.

Annual Base Salaries

Name

Brent J. Smolik	850,000	865,000	1.8	%	865,000	0%
Dane E. Whitehead	450,000	466,000	3.6	%	466,000	0%
Clayton A. Carrell	400,000	421,000	5.2	%	485,000	15.2%
Marguerite N. Woung-Chapman	370,000	387,000	4.6	%	387,000	0%
Joan M. Gallagher	300,000	313,500	4.5	%	340,000	8.5%
John D. Jensen	400,000	421,000	5.2	%	n/a	n/a

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Target Bonus Opportunities

Name

Brent J. Smolik	100	%	100	%	0	%
Dane E. Whitehead	100	%	100	%	0	%
Clayton A. Carrell	100	%	100	%	0	%
Marguerite N. Woung-Chapman	55	%	70	%	27.2	%
Joan M. Gallagher	55	%	60	%	9.1	%
John D. Jensen	100	%	100	%	0	%

Annual Cash Incentive Awards for 2014 Performance

2014 Scorecard. In February 2014, the Compensation Committee approved our 2014 scorecard for use in determining 2014 cash incentive awards. The 2014 scorecard consists of six 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 individual scorecard components, each with a threshold, target and maximum achievement level, although no one component is material to the overall scorecard weighting or bonus determination process, in part due to the number of scorecard components and in part due to the Committee's discretion to reduce or modify cash incentive payouts based on company performance and external factors outside of the specific scorecard metrics, as noted below. In approving the 2014 scorecard, the Compensation Committee retained discretion to adjust scorecard achievement for extraordinary or unplanned events that deviated from 2014 capital plan assumptions. In addition, while the scorecard plays an important role in determining eligibility for cash incentive payouts, the Compensation Committee retains discretion to adjust actual cash incentive payouts based on TSR, business conditions and other company performance factors as it deems appropriate.

The following table summarizes the 2014 scorecard, its key components and weightings, and the level of achievement of each component. In addition, definitions of each of the scorecard components are included immediately below the scorecard table.

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2014 Scorecard



Scorecard Category	Objectives	Key Components	Weighting	Achievement
Profit	Focus on near term cash flow generation, results largely driven by oil production growth and maximizing cash flow margin	• EBITDAX ($MM)(1)	25%	Very Good. Oil volumes from the company's Eagle Ford and Altamont plays driving above target performance.

Production & Reserves	Production drives cash flow and funding of capital program Continuous focus to replace current production with future reserves	• equivalent volumes (Mboe/d)(2) • oil volumes (MBbl/d)(3) • reserve replacement costs ($/Boe)(4)	25%	Excellent. Oil volumes from Eagle Ford and Altamont driving outperformance in volume targets; reserve replacement costs better than target driven by reserve adds from Eagle Ford, Altamont and Wolfcamp type curve update.

Costs	Minimizing operating costs and improving capital efficiency are primary value drivers	• total adjusted cash costs(5) • gross development costs/well(6) • Eagle Ford • Wolfcamp • Altamont	20%	Good. Adjusted cash costs better (lower) than target driven by production growth and lower severance and ad valorem taxes; well costs better (lower) than target in Eagle Ford and Altamont, but above target (higher) in Wolfcamp due to completion optimization efforts and expansion to central and southern acreage.

Value Creation	Deliver or exceed on returns targeted in capital plan Focus on growing reserves and inventory, divestiture of non-core assets and NAV	• after tax IRR (loaded) at $3.75/MMBtu and $85/Bbl @13%(7) • increase in net asset value(8)	25%	Very Good. After tax returns above target driven by outperformance in Eagle Ford and Altamont programs; NAV improved by increase in Wolfcamp type curve, Eagle Ford downspacing and Altamont 80-acre infill locations.

Health & Safety	Safety is core company value	• safety goals relating to combined employee and contractor recordable injuries rate	5%	Good. Safety metrics favorable resulting in company's best total recordable incident rate to date; continue to stress culture of safety.

Ethics & Compliance	Designed to enhance accountability for both employees and contractors and ensure high standards of ethical conduct	• certification of compliance with our Code of Conduct by 100% of employees, • no material weaknesses in internal controls over financial reporting	Discretionary overlay	PassýFailo 100% of employees and contractors reviewed and certified compliance with our Code of Conduct; no material weaknesses found in ICFR for 2014. This category graded on a pass/fail basis only.


(1)	Adjusted EBITDAX*	Earnings before interest expense, income taxes, depreciation, depletion, and amortization, and exploration expenses. Management will also adjust out impacts from discontinued operations and non-cash items such as impairments and mark-to-market movements related to commodity hedges.
(2)	Equivalent Volumes*	Volume as reported publicly in financial results based on sales of oil, gas, and natural gas liquids, with metric reference in equivalent terms.
(3)	Oil Volumes*	Volume as reported publicly in financial results based on sales of oil.
(4)	Reserve Replacement Costs*	A measure of capital spent finding and developing reserves (completion cost) divided by Reserve Additions.
		Reserve Additions is the year-end proved extensions, discoveries, reserves revisions for price, and performance and other additions and acquisitions as defined by the SEC and reported in our Form 10-K, Supplemental Oil & Natural Gas Disclosures.
(5)	Total Adjusted Cash Operating Costs*	The sum of the following items, divided by production volume to give $/Bbl:
		• lease operating expenses
		• production taxes
		• taxes other than production and income taxes
		• general and administrative expenses (excludes non-cash portion of compensation expense).
(6)	Gross Development Cost/Well	A measure of capital spent to make a well productive. This includes drilling, completion, and facilities capital. This measure is expressed on a per well basis.
(7)	After Tax Internal Rate of Return	The after-tax economic rate of return of wells completed.
(8)	Increase in Net Asset Value	Net Asset Value is the discounted value of future cash flows from existing producing wells and future drilling inventory. This measure is expressed in terms of year-over-year growth.

*: Actual results are typically adjusted for certain circumstances that deviate from plan assumptions. The typical adjustments include commodity price impacts, acquisitions and divestitures, material capital expenditures, and unbudgeted transaction costs.

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Range of Individual Bonus Amounts. In addition to company performance, individual performance plays an important role in determining annual incentives. Each named executive officer has individual accountabilities which are evaluated and taken into account in determining his or her 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.

The range of annual cash incentive bonuses is illustrated as a percentage of base salary for each named executive officer in the following table. The target and maximum amounts are as set forth in the named executive officers' individual employment agreements. The threshold amount below is provided for illustrative purposes only and assumes threshold scorecard goal achievement with no qualitative or individual performance adjustments. As noted above, actual bonus amounts could be at any level between 0% to 200% of target as determined by the Compensation Committee.

Range of Cash Incentive Bonuses as a Percentage of Base Salary for 2014



Brent J. Smolik	0%	50%	100%	200%
Dane E. Whitehead	0%	50%	100%	200%
Clayton A. Carrell	0%	50%	100%	200%
Marguerite N. Woung-Chapman	0%	35%	70%	140%
Joan M. Gallagher	0%	30%	60%	120%
John D. Jensen	n/a	n/a	n/a	n/a

The potential range of values of the annual cash incentive awards for 2014 performance for each of the named executive officers is reflected in the Grants of Plan-Based Awards Table in the "Estimated Possible Payouts Under Non-Equity Incentive Plan Awards" column.

2014 Scorecard Results. In February 2015, the Compensation Committee reviewed the performance of our company relative to the 2014 scorecard. In reviewing performance relative to the scorecard goals, the Compensation Committee excluded the impacts of certain extraordinary items, including commodity price changes, acquisition and divestiture activity, rig breakage fees in our Wolfcamp play, and adjustment for a modest second-half 2014 increase in our capital program for incremental drilling and completion activity. The Compensation Committee determined that these items were not related to the ongoing operation of EP Energy in a manner consistent with the way the performance goals and ranges were set for compensation-related purposes. Based on these adjustments, the Compensation Committee determined that EP Energy achieved above-target performance in each of the scorecard categories.

In evaluating 2014 scorecard achievement, the Compensation Committee also considered Parent's TSR performance relative to its peer group during 2014, which was in the third quartile (36th percentile using a 5-day moving average). Although TSR is not a specific metric in the scorecard, the committee reserved the right to use stock performance as a discretionary overlay in determining scorecard achievement. The committee also took into account a number of additional performance factors, including lower operating cash flow and lower reported oil and gas reserves and higher reserve replacement costs associated with the steep drop in oil prices during the fourth quarter of 2014. Based on Parent's third quartile TSR performance during 2014 and the other performance factors noted above, the Compensation Committee felt it appropriate to use its discretion to reduce the 2014 scorecard achievement level by 19 percentage points, from 119% of target to 100% of target. The committee also felt this reduction was appropriate as part of the company's overall efforts to reduce costs in a lower oil-price environment. After reviewing each scorecard category and taking into account the discretionary adjustments noted above, the Compensation Committee approved a 2014 scorecard achievement level of 100% for annual cash incentive awards.

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The Compensation Committee also evaluated each executive officer's individual performance and contributions during 2014 and discussed with our CEO his recommendation as to the appropriate bonus levels for the executive officers reporting to him. Based on this review, the committee elected to make an upward performance adjustment to the bonus amount for Mr. Carrell to recognize his additional responsibilities and leadership efforts following the voluntary resignation of the company's executive vice president of operation services in May 2014.

2014 Annual Incentives. Based on the policies described above, the Compensation Committee approved the following annual incentive bonuses for our named executive officers for 2014 performance. The amount was calculated in accordance with the following formula:

The following table sets forth each named executive officer's annual cash incentive for 2014 performance.

Target vs. Actual
Annual Cash Incentives
for 2014 Performance



Brent J. Smolik	865,000	100%	865,000
Dane E. Whitehead	466,000	100%	466,000
Clayton A. Carrell	485,000	119%	575,042
Marguerite N. Woung-Chapman	270,900	100%	270,900
Joan M. Gallagher	204,000	100%	204,000
John D. Jensen(2)	n/a	n/a	n/a

(1): Cash incentive awards for the named executive officers were paid in March 2015 and are reported in the "Non-Equity Incentive Plan Compensation" column of the Summary Compensation Table.
(2): Mr. Jensen voluntarily resigned on May 31, 2014. Consequently, he was not entitled to and did not receive an annual cash incentive for 2014 performance.

2014 Long-Term Incentive Awards

In advance of Parent's initial public offering in early 2014, the Compensation Committee reviewed our legacy long-term incentive program and considered post-IPO long-term incentive approaches for our named executive officers, taking into consideration retention and ensuring that long-term incentives are directly tied to long-term performance and the creation of stockholder value. The committee also considered the potential value of the Class B shares granted to the named executive officers in 2012 in determining appropriate grant levels. Based on this review and with input from FW Cook and management, the Compensation Committee approved 2014 long-term incentive awards in the form of stock options and restricted stock of Parent issued from our 2014 Omnibus Incentive Plan. These equity awards incorporate a delayed three-year ratable vesting schedule, with one-third vesting as of the earlier of (i) the third-anniversary of the grant date or (ii) the one-year anniversary of a complete sell-down by Apollo and Riverstone of their shares of our common stock (the "first vesting date"), one-third vesting on the first anniversary of the first vesting date, and one-third vesting on the second

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anniversary of the first vesting date. The committee elected to issue the awards at below market-median levels (awarded at approximately 25% of market-median for each named executive officer for 2014, with market-median being "target") in light of the potential upside of the Class B shares that were granted to the executives in 2012. While the committee elected to award below market-median grants in 2014, the committee retains discretion on specific grant levels going forward.

The committee believes this program will encourage retention following a Sponsor exit, motivate superior stock performance over a multi-year period and further align the interests of our named executive officers with our stockholders.

The Compensation Committee approved the grant value of each named executive officers' equity awards and conversion methodology in early 2014, with a grant date of April 1, 2014. The equity awards were issued in an approximate 50/50 combination of stock options and restricted stock (based on grant date fair value), with options granted with an exercise price equal to the closing share price of our common stock on the grant date.

The following table compares each named executive officer's target equity opportunity for 2014 versus the actual equity amount granted as described above.

Target vs. Actual
2014 Long-Term Incentive Awards

Name	2014 Target Equity Opportunity				2014 Actual Equity Grant Value(1)

Brent J. Smolik	$	5,052,000	25	%	$	1,263,000
Dane E. Whitehead	$	2,400,000	25	%	$	600,000
Clay A Carrell	$	2,400,000	25	%	$	600,000
Marguerite N. Woung-Chapman	$	1,252,000	25	%	$	313,000
Joan M. Gallagher	$	780,000	25	%	$	195,000
John D. Jensen	$	2,400,000	25	%	$	600,000

(1): We used a Black-Scholes valuation to convert the dollar value of the grant into options, and we used a 10 day average of the closing sales price of our common stock immediately prior to and including the grant date to convert the dollar value of the grant into restricted stock.

The number of shares and the grant date fair market value of the restricted stock and stock options of Parent awarded in April 2014 to each named executive officer are reflected in the Grants of Plan-Based Awards Table.

Legacy Long-Term Incentive Program

Class B Common Stock. At the time of the formation of EP Energy in May 2012, our named executive officers, along with certain other key employees, were issued a one-time grant of Class B common stock, which shares were designed to align the interests of our executive officers with that of our equity investors, to encourage retention and to incentivize superior stock performance. The number of Class B shares awarded to each named executive officer and his or her respective ownership percentage of the outstanding Class B shares is set forth in the table below.

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Class B Common Stock

Name

Brent J. Smolik	207,985	25.40	%
Dane E. Whitehead	69,328	8.47	%
Clayton A. Carrell	69,328	8.47	%
Marguerite N. Woung-Chapman	27,731	3.39	%
Joan M. Gallagher	18,488	2.26	%
John D. Jensen	20,799	2.54	%

(1): Based on 818,909 Class B shares of Parent outstanding as of December 31, 2014.

Each Class B share represents a share in future appreciation of the company, subject to certain limitations, after the May 2012 date of grant and once certain shareholder returns have been achieved. The Class B shares 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. Once vested, the Class B shares (or a portion thereof) are generally non-forfeitable in the event of an executive officer's termination of employment for any reason other than cause. In contrast, unvested Class B shares would generally be forfeited in the event of an executive officer's termination of employment. While the time vesting component of the Class B shares provides forfeiture protection to the executive officers, vesting, in and of itself, does not result in the payment of proceeds to the holder. The Class B shares are subject to a performance hurdle and become payable upon occurrence of certain liquidity events where our Sponsors receive a return of at least one times their invested capital in our company. Unvested Class B shares held by our named executive officers would immediately vest upon the achievement of such performance measures.

In addition, in connection with certain sales of shares of common stock by two of our primary sponsors (Apollo and Riverstone), holders of shares of Class B common stock will have their shares exchanged for shares of common stock that are newly issued by Parent ("Class B Exchange"). The number of shares of common stock issued in a Class B Exchange will depend on the return on invested capital in the company received by Apollo and Riverstone (must be at least one times) subject to an adjustment multiple to replicate a hypothetical sell-down by all Sponsors in the same proportion and at the same price as those sold by Apollo and Riverstone.

Illustration of Class B Exchange

Below is an example that illustrates the aggregate number of shares of common stock of Parent that would be issued in a Class B Exchange assuming a sale by Apollo and Riverstone of 100% of their common stock holdings on December 31st of each specified year for net proceeds equal to the hypothetical per share prices noted below. The shares would be allocated among the Class B holders in accordance with each holder's respective percentage ownership.

# of Class A Shares Issued in Class B Exchange

*(MM shares)*			Year Ended December 31,
			2015		2016		2017		2018
	$	12.50		0.0		0.0		0.0		0.0
EPE	$	15.00		1.0		1.0		1.0		1.0
Share	$	17.50		3.8		3.8		3.8		1.7
Price	$	20.00		4.9		4.9		4.9		4.9
	$	22.50		6.4		6.4		6.4		6.4

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Early 2015 Compensation Decisions

2015 Base Salary Freeze

At its February 2015 meeting, the Compensation Committee determined it would be appropriate to freeze base salaries at 2014 levels for our named executive officers. The Compensation Committee believed this action would be appropriate to reflect the company's ongoing efforts to reduce costs and preserve liquidity in light of the steep drop in oil prices during the fourth quarter of 2014 and to better position the company for long-term success. Consequently, our named executive officers will not receive base salary increases in 2015.

2015 Long-Term Incentive Awards

Also in early February 2015, the Compensation Committee approved long-term incentive awards of Parent for 2015 for our named executive officers to be issued from our 2014 Omnibus Incentive Plan. In a change from 2014 grants, which included an approximate 50/50 mix of stock options and restricted stock, 2015 grants will be made entirely in restricted stock, with five-year ratable vesting. In addition, grants will be made at market-median levels. In determining the 2015 long-term incentive grant levels, the Committee considered the current value of the Class B shares (which were underwater as of December 31, 2014) and the potential dilution of the grant and determined that market-median level grants were appropriate to create additional retention and stockholder alignment. Long-term incentive grants for 2015 were issued near the end of the first quarter pursuant to the form of restricted stock award agreement previously approved by the Compensation Committee and will be reported in next year's Summary Compensation Table and Grants of Plan-Based Awards Table in accordance with SEC reporting requirements regarding equity grant issuances.

V. Other Compensation Matters

Employment Agreements

We entered into employment agreements with each of our named executive officers in May 2012. 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 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 have an initial five-year term, but the term of each agreement will be extended automatically 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. Additional detail regarding the employment agreements is set forth following the Grants of Plan-Based Awards Table.

Stock Ownership Requirements

We adopted stock ownership guidelines in early 2015 to emphasize our commitment to senior management and independent director stock ownership. These stock ownership guidelines are designed

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to emphasize stock ownership of Parent and to further align the interest of our executive officers and directors with our stockholders. These requirements are as follows:

Position		Minimum Aggregate Value

Chief Executive Officer		5X base salary
Other Named Executive Officers		2X base salary
Independent Directors		5X cash retainer

Each executive officer and independent director is required to meet the ownership threshold within five years of his or her election as an executive officer or director (or from the date of adoption of this policy, whichever is later).

As of March 1, 2015, each of our current named executive officers has already met the requisite share ownership thresholds set forth in the stock ownership guidelines, primarily due to each executive's purchase(s) of shares of Parent's common stock with his or her own funds.

Clawback Policy

We adopted a clawback policy in early 2015 applicable to our executive officers and other individuals designated by our Board. Under the policy, if it is determined that a covered employee engaged in fraud, misconduct or a violation of company policy that causes us to restate our reported financial or operating results due to material non-compliance with financial reporting requirements, the Board will review the incentive compensation paid, granted, vested or accrued to such employee during the three fiscal years prior to the date of such restatement. To the extent practicable and as permitted by applicable law, the Board will determine, in its discretion, whether to seek to recover or cancel the difference between any incentive compensation paid during the three years preceding such restatement that was based on having met or exceeded performance targets that would not have been met based upon the restated financial or operational results and the incentive compensation that would have been paid or granted to the covered employee or the incentive compensation in which the covered employee would have vested had the actual payment, granting or vesting been calculated based on the restated financial or operational results.

In addition, the Dodd-Frank Wall Street Reform and Consumer Protection Act, which was signed into law in 2010, imposes a number of executive compensation related requirements on public companies, including a requirement to adopt a clawback policy in conformance with the act (the "Dodd-Frank Clawback"). The SEC is currently in the process of preparing regulations on the Dodd-Frank Clawback, and once such regulations are finalized, we will comply accordingly. The implementation of the Dodd-Frank Clawback may require us to amend or modify our current clawback policy.

Policy on Hedging and Pledging of Company Securities

We have a robust anti-hedging policy that prohibits employees and non-employee directors from engaging in any kind of hedging transaction that seeks to reduce or limit that person's economic risk associated with his or her ownership in EP Energy securities, which includes short-selling or the purchase or sale of puts, calls, options or other derivative securities based on the company's securities.

In addition, our executives and non-employee directors are prohibited from holding EP Energy securities in a margin account or otherwise entering into any pledge arrangement that, in either case, would permit a third party to sell EP Energy securities without the individual's consent or knowledge.

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Compensation Risk Assessment

During 2014, the Compensation Committee requested FW Cook to perform a risk assessment of our company's incentive compensation arrangements for all employees, including our named executive officers. Based on its review, FW Cook concluded the company's compensation programs do not motivate undue risk and that the compensation policies and practices are not reasonably likely to have a material adverse effect on the company. See "Compensation Policies and Practices as they Relate to Risk Management" for additional detail regarding the compensation risk assessment.

162(m) IPO transition

Section 162(m) of the Internal Revenue Code imposes an annual deduction limit of $1 million on the amount of compensation paid to each of the CEO and the three other highest compensated executive officers of the Company, not including the CFO. The deduction limit does not apply to performance-based compensation that satisfies the requirements of Section 162(m). The Company is currently eligible for a post-IPO transition rule under which amounts paid under our 2014 Omnibus Incentive Plan, including annual cash incentive awards and long-term incentive equity grants, are exempt from the deduction limitations of Section 162(m). The transition rule will expire in connection with Parent's annual meeting of stockholders in 2018.

Executive Compensation

Summary Compensation Table

Name and Principal Position

Brent J. Smolik	2014	861,252	—	644,507	653,530	865,000	—	45,040	3,069,329
Chairman, President & Chief	2013	850,000	2,000,000	—	—	1,100,000	—	37,827	3,987,827
Executive Officer	2012	511,063	—	20,951,593	—	1,147,500	—	8,050	22,618,206
Dane E. Whitehead	2014	462,000	—	306,160	310,460	466,000	—	44,358	1,588,978
Executive Vice President &	2013	450,000	850,000	—	—	610,000	—	37,132	1,947,132
Chief Financial Officer	2012	270,395	—	7,167,167	—	630,000	—	8,592	8,076,154
Clayton A. Carrell	2014	431,752	—	306,160	310,460	575,042		45,658	1,669,072
Executive Vice President &	2013	400,000	600,000	—	—	540,000	—	44,350	1,584,350
Chief Operating Officer	2012	240,372	—	6,917,167	—	540,000	—	21,179	7,718,718
Marguerite N. Woung-Chapman	2014	382,752	—	159,710	161,956	270,900	—	38,914	1,014,232
Senior Vice President, General	2013	370,000	370,000	—	—	275,000	—	29,350	1,044,350
Counsel & Corporate Secretary	2012	222,382	—	2,896,849	—	280,000	—	16,907	3,416,138
Joan M. Gallagher(4) Senior Vice President, Human Resources & Administrative Services	2014	316,750	—	99,496	100,899	204,000	—	44,385	765,530
John D. Jensen(5)	2014	170,169	—	306,160	310,460	—	—	31,915	818,704
Executive Vice President,	2013	400,000	600,000	—	—	540,000	—	44,150	1,584,150
Operations Services	2012	240,372	—	6,917,167	—	510,000	—	17,222	7,684,761

(1): The amount in this column for 2014 includes the aggregate grant date fair value of the stock awards or option awards of Parent, as applicable, granted to each named executive officer under the company's 2014 Omnibus Incentive Plan computed in accordance with the Financial Accounting Standards Board Accounting Standards Codification Topic 718, "Compensation—Stock Compensation" ("FASB ASC Topic 718"). The grant date fair value used to calculate these amounts is the same as that used for our stock-based compensation disclosure in Note 8 to our financial statements included elsewhere in this prospectus.
(2): The amount in this column for 2014 reflects each named executive officer's annual cash incentive bonus earned for 2014 performance. Amounts for 2014 performance were paid in March 2015. See the discussion under "Annual Cash Incentive Awards for 2014 Performance" in the Compensation Discussion and Analysis for additional information.

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(3): The compensation reflected in the "All Other Compensation" column for 2014 for each of our named executive officers includes company matching and retirement contributions to our 401(k) Retirement Plan, annual executive physicals, financial planning assistance and certain miscellaneous expenses, which are listed in the table immediately following these footnotes.
(4): Joan M. Gallagher was not a named executive officer in 2013 and 2012 and consequently compensation information for those years is not included in this prospectus.
(5): John D. Jensen voluntarily resigned on May 31, 2014.

All Other Compensation included in the Summary Compensation Table for 2014

Name

Brent J. Smolik	28,600	1,100	14,862	478	45,040
Dane E. Whitehead	28,600	—	15,370	388	44,358
Clayton A. Carrell	28,600	1,300	15,370	388	45,658
Marguerite N. Woung-Chapman	28,600	1,300	8,674	340	38,914
Joan M. Gallagher	28,600	—	15,370	415	44,385
John D. Jensen	25,168	—	6,359	388	31,915

(A): The amounts in this column reflect our cost for executive officer annual physicals.
(B): The amounts in this column reflect the cost for financial and tax planning assistance we provided to our named executive officers. This amount is imputed as income and no tax gross-up is provided.
(C): The amount in this column reflects the cost for meals associated with spouse travel in connection with Parent's initial public offering. This amount is imputed as income and no tax gross-up is provided. The aircraft cost associated with such spousal travel was paid directly by the individual executive officers with their own funds and was not a perquisite.

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Grants of Plan-Based Awards
During the Year Ended December 31, 2014



			Estimated Possible Payouts Under Non-Equity Incentive Plan Awards(1)										Grant Date Fair Value of Stock and Option Awards ($)(5)
											Exercise or Base Price of Option Awards ($/Sh)(4)
		Date of Compensation Committee Action
Name	Grant Date	Date of Compensation Committee Action	Threshold ($)		Target ($)		Maximum ($)
Brent J. Smolik
Short-Term Incentive	N/A	N/A		432,500		865,000		1,730,000
Stock Options	04/01/2014	02/06/2014								72,388		19.82		653,530
Restricted Stock	04/01/2014	02/06/2014							32,518					644,507
Dane E. Whitehead
Short-Term Incentive	N/A	N/A		233,000		466,000		932,000
Stock Options	04/01/2014	02/06/2014								34,388		19.82		310,460
Restricted Stock	04/01/2014	02/06/2014							15,447					306,160
Clayton A. Carrell
Short-Term Incentive	N/A	N/A		242,500		485,000		970,000
Stock Options	04/01/2014	02/06/2014								34,388		19.82		310,460
Restricted Stock	04/01/2014	02/06/2014							15,447					306,160
Marguerite N. Woung-Chapman
Short-Term Incentive	N/A	N/A		135,450		270,900		541,800
Stock Options	04/01/2014	02/06/2014								17,939		19.82		161,956
Restricted Stock	04/01/2014	02/06/2014							8,058					159,710
Joan M. Gallagher
Short-Term Incentive	N/A	N/A		102,000		204,000		408,000
Stock Options	04/01/2014	02/06/2014								11,176		19.82		100,899
Restricted Stock	04/01/2014	02/06/2014							5,020					99,496
John D. Jensen(6)
Short-Term Incentive	N/A	N/A		N/A		N/A		N/A
Stock Options	04/01/2014	02/06/2014								34,388		19.82		310,460
Restricted Stock	04/01/2014	02/06/2014							15,447					306,160

(1): These columns show the potential value of the payout of the annual cash incentive bonuses for 2014 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 earned for 2014 performance is shown in the Summary Compensation Table under the "Non-Equity Incentive Plan Compensation" column.
(2): This column shows the number of shares of restricted stock of Parent granted in 2014 to the named executive officers. The shares are subject to delayed three-year ratable vesting with the first tranche vesting in 2017, second tranche in 2018 and third tranche in 2019 (with vesting commencing earlier in event of complete sell-down by Apollo and Riverstone of their common stock holdings).
(3): This column shows the number of stock options of Parent granted in 2014 to the named executive officers. The options are subject to delayed three-year ratable vesting with the first tranche vesting in 2017, second tranche in 2018 and third tranche in 2019 (with vesting commencing earlier in event of complete sell-down by Apollo and Riverstone of their common stock holdings).
(4): This column shows the exercise price for the stock options granted during 2014, which is the closing market price of a share of our common stock on the date of grant.
(5): This column shows the grant date fair value of the restricted stock and stock options computed in accordance with FASB ASC Topic 718 granted to the named executive officers during 2014. Generally, the grant date fair value is the amount expensed in our financial statements over the vesting schedule of the restricted stock and stock options.
(6): John D. Jensen voluntarily resigned as of May 31, 2014. Pursuant to the terms of our 2014 Omnibus Incentive Plan, the stock options and restricted stock granted to him in 2014 as set forth in this table were forfeited as of his termination date.

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 "Compensation Discussion and Analysis" above.

Equity Awards

The following is a description of the material factors necessary to understand the information regarding the stock awards and option awards reflected in the Grants of Plan-Based Awards table. The

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equity awards reflected in the table are shares of restricted stock and nonqualified stock options of Parent which were approved by the Compensation Committee and granted to our named executive officers on April 1, 2014. The equity awards were granted under our 2014 Omnibus Incentive Plan. The grant date fair value per share for the restricted stock awards granted on April 1, 2014 was $19.82. The grant date fair value per option for stock options granted on April 1, 2014 was $9.03, computed using a Black-Scholes option-pricing model based on several assumptions. These assumptions are based on management's best estimate at the time of grant and are listed below, as follows:


Expected Term in Years	7.0
Expected Volatility	40	%
Expected Dividends	—
Risk-Free Interest Rate	2.3	%

Restricted shares are subject to forfeiture in the event of a termination of employment. The restrictions will lapse on any unvested shares of restricted stock and any unvested stock options become fully exercisable in the event of an executive's termination of employment without cause or by the executive for "good reason," if applicable, within two years following a change in control of EP Energy. The total value of the restricted stock can be realized only if the executives remain employed by EP Energy for the required vesting period. Stock options generally expire ten years from the date of grant. However, stock options are subject to forfeiture and/or time limitations on exercise in the event of a termination of employment.

Employment Agreements

As discussed above, we entered into employment agreements with our named executive officers in May 2012. The employment agreements have an initial five-year term, but the term of each agreement will be extended automatically 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. 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. Under the terms of the agreement, Mr. Smolik's minimum annual base salary is $850,000 (subject to periodic review and increase at the discretion of the Compensation Committee, increased to $865,000 as of April 1, 2014), 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. 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 minimum annual base salary is $450,000 (subject to periodic review and increase at the discretion of the Compensation Committee, increased to $466,000 as of April 1, 2014), 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 eligible to participate in all benefit plans and programs that are available to other senior executives of

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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 minimum annual base salary is $400,000 (subject to periodic review and increase at the discretion of the Compensation Committee, increased to $485,000 as of October 1, 2014), 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 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.

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 minimum annual base salary is $370,000 (subject to periodic review and increase at the discretion of the Compensation Committee, increased to $387,000 as of April 1, 2014), with an annual cash bonus target equal to 55% (increased to 70% in 2014) 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 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.

Joan M. Gallagher

We entered into an employment agreement with Ms. Gallagher, effective May 24, 2012, to serve as our Senior Vice President, HR and Administrative Services. Under the terms of the agreement, Ms. Gallagher's minimum annual base salary is $300,000 (subject to periodic review and increase at the discretion of the Compensation Committee, increased to $340,000 as of October 1, 2014), with an annual cash bonus target equal to 55% (increased to 60% in 2014) of her annual base salary, with higher or lower amounts (0% to 200% of target) payable depending on performance relative to targeted results. Ms. Gallagher is eligible to participate in all benefit plans and programs that are available to other senior executives of our company. Ms. Gallagher'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 was $400,000 (subject to periodic review and increase at the discretion of the Compensation Committee, increased to $421,000 as of April 1, 2014), 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 was eligible to participate in all benefit plans and programs available to other senior executives of our company. Mr. Jensen's employment agreement contains provisions related to the payment of benefits upon certain termination

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events, as well as certain non-compete, non-solicitation and confidentiality restrictions. Mr. Jensen voluntarily resigned from the company in May 2014.

Outstanding Equity Awards

The following table provides information with respect to outstanding equity awards held by the named executive officers as of December 31, 2014.

Outstanding Equity Awards
at Fiscal Year-End 2014

	Option Awards

	Option Awards									Stock Awards
	Number of Securities Underlying Unexercised Options at Fiscal Year-End (#)									Stock Awards
													Market Value of Shares or Units of Stock That Have Not Vested ($)(1)
						Option Exercise Price ($)				Number of Shares or Units of Stock That Have Not Vested (#)
								Option Expiration Date
Name	Exercisable		Unexercisable					Option Expiration Date
Brent J. Smolik		0		72,388	(2)		19.82		04/01/2024		32,518	(3)		339,488
											207,985	(4)		(5)
Dane E. Whitehead		0		34,388	(2)		19.82		04/01/2024		15,447	(3)		161,267
											69,328	(4)		(5)
Clayton A. Carrell		0		34,388	(2)		19.82		04/01/2024		15,447	(3)		161,267
											69,328	(4)		(5)
Marguerite N. Woung-Chapman		0		17,939	(2)		19.82		04/01/2024		8,058	(3)		84,126
											27,731	(4)		(5)
Joan M. Gallagher		0		11,176	(2)		19.82		04/01/2024		5,020	(3)		52,409
											18,488	(4)		(5)
John D. Jensen(6)		—		—			—		—		20,799	(4)		(5)

(1): The values represented in this column have been calculated by multiplying $10.44, the closing price of Parent's common stock on December 31, 2014, by the number of shares of stock.
(2): These are stock options of Parent that were granted as part of the 2014 annual grant of long-term incentive awards. The options are subject to a delayed three-year ratable vesting schedule with the first tranche vesting on April 1, 2017, second tranche on April 1, 2018 and third tranche on April 1, 2019 (with vesting commencing earlier in event of complete sell-down by Apollo and Riverstone of their common stock holdings).
(3): These are shares of restricted stock of Parent that were granted as part of the 2014 annual grant of long-term incentive awards. The restricted shares are subject to a delayed three-year ratable vesting schedule with the first tranche vesting on April 1, 2017, second tranche on April 1, 2018 and third tranche on April 1, 2019 (with vesting commencing earlier in event of complete sell-down by Apollo and Riverstone of their common stock holdings).
(4): These are shares of Class B common stock of Parent held by each of our named executive officers as of December 31, 2014. The Class B shares are subject to time-based vesting requirements (vest ratably over 5 years, with 20% vesting on each of May 24, 2013, 2014, 2015, 2016 and 2017) as well as a performance hurdle, and such shares do not become payable until the performance hurdle is achieved (e.g., certain liquidity events in which our private equity sponsors receive a return of at least one times their invested capital in our company). The performance hurdle applicable to the Class B common shares has not yet been met, and consequently, all of the Class B shares owned by the named executive officers are reported as unvested shares for purposes of this table.
(5): Because the number of shares of common stock that would be issued to our named executive officers in a Class B Exchange depends on the total value received by our private equity sponsors, the market value of the shares of Class B common stock is not readily determinable. See "Compensation Discussion and Analysis" for further detail. For illustrative purposes only and assuming that Apollo and Riverstone sold 100% of their

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shares of common stock on December 31, 2014 for net proceeds of $10.44 per share (the closing share price on December 31^st), the Class B shares held by our named executive officers would have been worth $0 and would not have been exchanged for shares of common stock of Parent, as a sale at such price would not have triggered the performance hurdle applicable to the Class B Shares.

(6): John D. Jensen voluntarily resigned as of May 31, 2014.

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 with good reason then the executive will be 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 as of the termination date;
•: 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 will be the payment of any accrued obligations. For purposes of the above, "good reason" means, as to any executive, the occurrence of any of the following events without the executive's consent: (a) a reduction in the executive's annual base salary other than a reduction of not more than 5% in connection with a general reduction in base salaries that affects all similarly situated executives in substantially the same proportions which is implemented in response to a material downturn in the U.S. domestic oil and natural gas exploration and development industry; (b) a failure of the company to cause the executive to be eligible under benefit plans that provide benefits that are substantially comparable in the aggregate to those provided to the executive as of the effective date of the employment agreement; (c) any material breach by the company of the employment agreement; (d) a material diminution in the executive's title, authority, duties, or responsibilities; (e) the requirement that the executive's principal place of employment be outside a 35 mile radius of his or her then-current principal place; (f) any purported termination of the executive's employment for cause which does not comply with the employment agreement; and solely with respect to Mr. Smolik, (g) the failure of the company to re-elect him as a member of the Board in connection with any election of directors. The term "cause" means the executive's (i) willful failure to perform the executive's material duties, (ii) willful and material breach of the employment agreement, (iii) conviction of or plea of guilty or no contest to, any felony or any crime involving moral turpitude, or (iv) engaging in actual fraud or willful material misconduct in the performance of the executive's duties under the employment agreement.

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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 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.

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.

2014 Omnibus Incentive Plan Awards

Stock Options

As discussed in the "Compensation Discussion and Analysis," the stock options of Parent issued under our 2014 Omnibus Incentive Plan to the named executive officers in 2014 are subject to a delayed 3-year vesting schedule with vesting commencing in 2017 (or earlier in the event of a completed sell-down by Apollo and Riverstone of their common stock holdings). If the executive's employment is involuntarily terminated by the company without cause or in the event of the executive's termination due to disability, a pro-rata portion of the unvested options will vest on the date of the executive's termination of employment. The options will fully vest in the event of the executive's termination due to death. In addition, options will fully vest in the event of an executive's termination of employment without cause or by the executive for good reason within two years following a change in control of EP Energy. Unless stock options expire by their own terms, vested options may be exercised for three-months following a voluntary termination by the executive or an involuntary termination by the company without cause or one year in the event of termination due to death or disability. Vested but unexercised stock options are forfeited in the event of a termination for cause.

Restricted Stock

As discussed in the "Compensation Discussion and Analysis," the restricted shares of Parent issued under our 2014 Omnibus Incentive Plan to the named executive officers are subject to a delayed 3-year vesting schedule with vesting commencing in 2017 (or earlier in the event of a completed sell-down by Apollo and Riverstone of their common stock holdings). If the executive's employment is involuntarily terminated by the company without cause or in the event of the executive's termination due to disability, a pro-rata portion of the shares of restricted stock that remain subject to the restriction period will vest on the date of the executive's termination of employment. The shares of restricted stock will fully vest in the event of the executive's termination due to death. In addition, shares of restricted stock will fully vest in the event of an executive's termination of employment without cause or by the executive for good reason within two years following a change in control of EP Energy.

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Restricted shares that remain subject to the restriction period will be immediately forfeited in the event of a voluntary termination by the executive or a termination for cause.

Legacy LTI Awards

Common Stock

Each of our named executive officers holds shares of common stock of Parent issued in connection with the formation of EP Energy in 2012, which include "buy-in" shares purchased by the executives with their own funds and a "matching" award of common stock equal to 50% of the buy-in shares purchased. These common shares are 100% vested, but remain subject to transfer restrictions until the earlier of May 2016 and certain liquidity events. In addition, the shares are subject to repurchase at the company's election in certain termination scenarios as follows:

Voluntary Termination without Good Reason or Involuntary Termination with Cause

In the event of a named executive officer's voluntary termination without good reason 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 shares of common stock held by such executive for a purchase price equal to the lesser of the original cost paid by the executive to purchase the shares and the fair market value of the shares on the repurchase date. As the "matching" award of common stock was awarded to the executives at no cost, this repurchase option would generally cause the shares of common stock to be repurchased for no consideration.

Involuntary Termination without Cause or Voluntary Termination with 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, then for a period of one year following the termination, the company may elect (but is not required) to repurchase the shares of common stock held by such executive for a purchase price equal to the fair market value of the shares on the repurchase date.

Class B Common Stock

As discussed in the "Compensation Discussion and Analysis," the shares of Class B common stock of Parent issued to the named executive officers in 2012 vest ratably over five years. Below is a description of the impact of certain termination scenarios on the Class B shares.

Involuntary Termination with Cause

In the event of a named executive officer's termination with cause, all shares of Class B common stock held by such executive (whether vested or unvested) would be forfeited without consideration.

Voluntary Termination without Good Reason

In the event of a named executive officer's voluntary termination, 25% of the executive's vested Class B shares and all unvested Class B shares would be 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 shares of Class B common stock held by such executive at the fair market value of such shares (as determined by the Board) on the repurchase date.

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Involuntary Termination without Cause or Voluntary Termination with 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, a pro-rata portion of the unvested shares of Class B common stock would vest as of the termination date (pro-rata vesting relating solely to the single tranche of Class B common stock that would have vested as of the next vesting date). All remaining unvested shares of Class B common stock would be 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 shares of Class B common stock held by such executive at the fair market value of such shares (as determined by the Board) on the repurchase date.

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Estimated Severance, Accelerated Equity, 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, 2014 under the scenarios noted below.

Name

Brent J. Smolik
Severance Payment	—	—	—	6,055,000	—	6,055,000
Equity Acceleration(3)	—	339,488	28,292	28,292	—	339,488
Continued Medical	—	—	19,398	69,462	—	69,462
Disability Income	—	—	300,000	—	—	—
Survivor Benefit	—	2,162,500	—	—	—	—
Dane E. Whitehead
Severance Payment	—	—	—	2,330,000	—	2,330,000
Equity Acceleration(3)	—	161,267	13,436	13,436	—	161,267
Continued Medical	—	—	19,398	46,308	—	46,308
Disability Income	—	—	279,600	—	—	—
Survivor Benefit	—	1,165,000	—	—	—	—
Clayton A. Carrell
Severance Payment	—	—	—	2,425,000	—	2,425,000
Equity Acceleration(3)	—	161,267	13,436	13,436	—	161,267
Continued Medical	—	—	19,398	46,308	—	46,308
Disability Income	—	—	291,000	—	—	—
Survivor Benefit	—	1,212,500	—	—	—	—
Marguerite N. Woung-Chapman
Severance Payment	—	—	—	1,586,700	—	1,586,700
Equity Acceleration(3)	—	84,126	7,016	7,016		84,126
Continued Medical	—	—	9,078	21,972	—	21,972
Disability Income	—	—	232,200	—	—	—
Survivor Benefit	—	967,500	—	—	—	—
Joan M. Gallagher
Severance Payment	—	—	—	1,292,000	—	1,292,000
Equity Acceleration(3)	—	52,409	4,374	4,374	—	52,409
Continued Medical	—	—	19,398	46,308	—	46,308
Disability Income	—	—	204,000	—	—	—
Survivor Benefit	—	850,000	—	—	—	—
John D. Jensen(4)
Severance Payment	—	n/a	n/a	n/a	n/a	n/a
Equity Acceleration	—	n/a	n/a	n/a	n/a	n/a
Continued Medical	—	n/a	n/a	n/a	n/a	n/a
Disability Income	—	n/a	n/a	n/a	n/a	n/a
Survivor Benefit	—	n/a	n/a	n/a	n/a	n/a

(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.
(2): For purposes solely of the equity acceleration disclosure in this column, the value listed would only accelerate vest in the event of the named executive officer's involuntary termination of employment without cause; a good reason termination without a change in control would not result in the accelerated vesting of equity.
(3): This row shows the value of shares of restricted stock granted under our 2014 Omnibus Incentive Plan that vest in the event of the named executive officer's termination calculated using $10.44, the closing price of

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Parent's common stock on December 31, 2014. Outstanding stock options that vest would have been underwater (option exercise price is above the December 31, 2014 closing stock price) and therefore no value is included in this row for options.

(4): John D. Jensen voluntarily resigned as of May 31, 2014.

Compensation Policies and Practices as they Relate to Risk Management

With the help of its compensation consultant FW Cook, during 2014 the Compensation Committee reviewed our compensation policies and practices for all employees, including the named executive officers, and determined that our compensation policies and practices do not encourage inappropriate risk-taking and are not reasonably likely to have a material adverse effect on the company.

Specifically, the Compensation Committee noted a number of design features of our compensation programs that mitigate these risks, including:

•: employees are in structured programs which have a maximum earning opportunity;
•: performance metrics for our annual incentive program are aligned with stockholder interests and utilize multiple metrics;
•: the Compensation Committee has discretion in determining compensation payouts;
•: leverage for the most significant potential for value creation resides in the Class B share program, which is aligned with long-term company performance;
•: employee wealth creation is determined by sustained multi-year performance, not by any single year;
•: the company does not use open-ended compensation arrangements or ones that motivate leveraging the company's balance sheet; and
•: the company's programs are overseen by an independent compensation committee who has engaged an independent consultant to provide advice regarding market trends relating to the form, design, and amount of compensation.

In addition, in connection with this review, the Compensation Committee determined it would be prudent to adopt certain tools to mitigate compensation risk, including an incentive plan clawback policy, stock ownership guidelines and an anti-hedging policy, each of which were adopted by our Board in early 2015.

Director Compensation

The independent non-employee directors of Parent receive cash and equity-based compensation for their services as directors, as follows:

•: an annual cash retainer of $70,000;
•: an additional annual retainer of $15,000 for service as the chair of the Audit Committee or the Compensation Committee and $10,000 for service as the chair of any other board committee;
•: for non-chair committee members, an additional annual cash retainer of $7,500 for membership on the Audit Committee and $5,000 for membership on the Compensation Committee or any other board committee; and
•: an annual award of restricted stock of Parent granted under our 2014 Omnibus Incentive Plan, having a value as of the grant date of $175,000.

Annual cash retainers are paid in quarterly installments at the end of each quarter, unless the director elects to receive the retainer in the form of restricted stock. Annual restricted stock grants are

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made each year on the date of Parent's annual meeting of stockholders (or in the case of 2014, on May 1, 2014) and vest one year from the date of grant. An independent director who joins the Board at any time other than the annual meeting will receive a pro-rated restricted stock grant as of the first business day of the month following the director's appointment to the Board, with such award vesting one year from the date of grant. Directors may, at their election, receive their annual cash retainer in the form of restricted stock, which award would be issued at the same time as the annual restricted stock grant and would be subject to the same vesting restrictions. Directors also receive reimbursement for out-of-pocket expenses associated with attending board or committee meetings.

Director Compensation Table

The following table sets forth the aggregate dollar amount of all fees paid to each of our independent directors during 2014 for their services on the Board. The independent directors do not receive stock options or pension benefits.

Director Compensation
for the Year Ended December 31, 2014(1)

Name

Michael S. Helfer	82,500	218,740	—	301,240
Thomas R. Hix	63,750	174,998	—	238,748
Keith O. Rattie(5)	—	—	—	—

(1): Our sponsor-appointed non-independent directors do not receive any compensation from us for serving on the Board; consequently they are not included in the Director Compensation Table above. In addition, employee directors do not receive any additional compensation for serving on the Board. Amounts paid as reimbursable business expenses to each director for attending Board functions are not reflected in this table. We do not consider the directors' reimbursable business expenses for attending board functions and other business expenses required to perform board duties to have a personal benefit. Accordingly, they are not considered a perquisite.
(2): This column includes the value of a director's annual cash retainer, including the additional retainer for directors who chair a Committee of the Board and the additional retainer for members of the Audit Committee and Compensation Committee. Pursuant to Parent's director compensation program, whereby a director may elect to receive the annual cash retainer in the form of restricted stock, the amount reflected in this column for Messrs. Helfer and Hix for 2014 includes $61,875 and $61,875, respectively, that each director elected to receive in the form of restricted stock of Parent. The restricted stock received in lieu of cash was issued on May 1, 2014 in connection with the annual restricted stock award, with each director being awarded 3,088 shares, each share having a grant date fair value of $20.04.
(3): The amount in this column represents the aggregate grant date fair value of the annual restricted stock awards of Parent granted in 2014 to the directors. Each of Messrs. Helfer and Hix received a grant of 8,732 shares of restricted stock on May 1, 2014 as their annual equity retainer, each share having a grant date fair value of $20.04. In addition, Mr. Helfer received a pro-rated equity grant of 2,564 shares of restricted stock on February 3, 2014, each share having a grant date fair value of $17.06.

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(4): As of December 31, 2014, Messrs. Helfer and Hix had 14,384 and 11,820, respectively, of restricted shares of Parent outstanding, comprised of the annual equity retainer, pro-rated equity retainer (where applicable) and shares received in lieu of cash at the election of the director.
(5): Mr. Rattie was appointed to the Board of Directors on January 1, 2015 and consequently received no compensation from us during 2014.

Equity Compensation Plan Information

The following table provides information concerning the EP Energy Corporation 2014 Omnibus Incentive Plan as of December 31, 2014.

	(a)		(b)		(c)

Plan Category	Number of Securities to be Issued upon Exercise of Outstanding Options, Warrants and Rights		Weighted-Average Exercise Price of Outstanding Options, Warrants and Rights		Number of Securities Remaining Available for Future Issuance under Equity Compensation Plans (Excluding Securities Reflected in Column (a)
Equity compensation plans approved by stockholders		—		—		—
Equity compensation plans not approved by stockholders		219,352	$	19.82		11,179,603

Total		219,352				11,179,603

2014 Omnibus Incentive Plan

In connection with Parent's initial public offering, Parent adopted the 2014 Omnibus Incentive Plan, which plan was approved by the Board and became effective on January 15, 2014, the day prior to Parent's initial public offering. The purpose of the 2014 Omnibus Incentive Plan is to promote the interests of the company and its stockholders by enhancing the company's ability to attract and retain employees and non-employee directors through suitable recognition of their ability and experience. The 2014 Omnibus Incentive Plan is further intended to align the employees' and non-employee directors' interests and efforts with the long-term interests of the company's stockholders, and to provide participants with a direct incentive to achieve the company's strategic and financial goals.

The 2014 Omnibus Incentive Plan authorizes the granting of awards for up to ten years from the plan's effective date. The plan will remain in effect, subject to the right of our Board to terminate the plan at any time, until no awards remain outstanding. The Compensation Committee of our Board is the plan administrator. The Compensation Committee is authorized to delegate its duties and responsibilities as plan administrator to one or more senior executives of the company or any committee thereof, subject to certain limitations. Our Board will serve as plan administrator with respect to awards to non-employee directors. The plan administrator has the full power to select employees and non-employee directors to receive awards under the plan; determine the terms and conditions of awards; construe and interpret the plan and any awards granted thereunder; and, subject to certain limitations, amend the terms and conditions of outstanding awards. The plan administrator's determinations and interpretations under the 2014 Omnibus Incentive Plan are binding on all interested parties.

The 2014 Omnibus Incentive Plan authorizes the issuance of up to 12,433,749 shares of our common stock. The shares to be delivered under the plan may be made available from any combination of shares held in the company's treasury, authorized but unissued shares of Parent's common stock or

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previously issued shares of Parent's common stock reacquired by the company, including shares purchased on the open market, as determined by the plan administrator.

Any shares that are potentially deliverable under an award granted under the 2014 Omnibus Plan that is canceled, forfeited, settled in cash, expires or is otherwise terminated without delivery of such shares shall not be counted as having been issued under the plan. Likewise, shares that have been issued in connection with an award of restricted stock that is canceled or forfeited prior to vesting or settled in cash, causing the shares to be returned to the company, will not be counted as having been issued under the plan. In addition, shares that are held back or tendered (either actually or constructively by attestation) to cover the exercise price or tax withholding obligations with respect to an award will not be counted as having been issued under the plan.

In the event of a change in capitalization, as defined in the 2014 Omnibus Plan, the plan administrator shall make such adjustments as it determines are appropriate and equitable to (i) the maximum number and class of shares of common stock or other stock or securities with respect to which awards may be granted under the plan, (ii) the maximum number and class of shares of common stock or other stock or securities that may be issued upon exercise of stock options, (iii) the individual annual grant limits for Section 162(m), (iv) the number and class of shares of common stock or other stock or securities that are subject to outstanding awards and the option price or grant price therefor, if applicable, and (v) performance goals.

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SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

All of our equity interests are held indirectly by EPE Acquisition, LLC, which is a direct wholly owned subsidiary of Parent and we do not have any limited liability company units issued and outstanding. The following table sets forth information regarding the beneficial ownership of Parent's common stock as of June 1, 2015, and shows the percentage owned by:

•: each person known to beneficially own more than 5% of Parent's common stock;
•: each of our Named Executive Officers;
•: each member of the Board; and
•: all of the executive officers and members of the Board as a group.

The percentage of ownership is based on 247,984,586 shares of common stock outstanding as of June 1, 2015.

The percentages of Parent's common stock 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

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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 Parent's Common Stock

Name of Beneficial Owner	Shares		Percentage of Ownership
Apollo Funds(1)		112,596,207		45.4	%
Riverstone(2)		31,276,726		12.6	%
Access(3)		34,943,104		14.1	%
KNOC(4)		31,276,726		12.6	%
Brent J. Smolik(5)		1,109,424		*
Dane E. Whitehead(6)		444,612		*
Clayton A. Carrell(7)		366,497		*
Joan M. Gallagher(6)		160,132		*
Marguerite N. Woung-Chapman(6)		220,772		*
Ralph Alexander(8)		—		—
Gregory A. Beard(9)		—		—
Wilson B. Handler(9)		—		—
John J. Hannan(9)		—		—
Michael S. Helfer(6)		33,670		*
Thomas R. Hix(6)		50,926		*
Ilrae Park(10)		—		—
Keith O. Rattie(6)		28,194		*
Robert M. Tichio(8)		—		—
Donald A. Wagner(11)		—		—
Rakesh Wilson(9)		—		—
All directors and named executive officers as a group		2,414,227		*

*: Indicates less than 1%
(1): Includes shares held of record by Apollo Investment Fund VII, L.P. ("AIF VII"), Apollo Overseas Partners (Delaware 892) VII, L.P. ("AOP (Delaware 892)"), AOP VII (EPE Intermediate), L.P. ("AOP Intermediate"), Apollo Investment Fund (PB) VII, L.P. ("AIF (PB) VII"), ANRP (EPE Intermediate), L.P. ("ANRP Intermediate"), ANRP (Corp AIV), L.P. ("ANRP (Corp AIV)"), EPE Domestic Co-Investors, L.P. ("Domestic Co-Investors"), EPE Overseas Co-Investors (FC), L.P. ("Overseas Co-Investors"), EPE 892 Co-Investors I, L.P. ("Co-Investor I"), EPE 892 Co-Investors II, L.P. ("Co-Investor II"), and EPE 892 Co-Investors III, L.P. ("Co-Investor III," and together with AIF VII, AOP (Delaware 892), AOP Intermediate, AIF (PB) VII, ANRP Intermediate, ANRP (Corp AIV), Domestic Co-Investors, Overseas Co-Investors, Co-Investor I and Co-Investor II, the "Apollo Funds"). Apollo Management VII, L.P. ("Management VII") is the manager of AIF VII, AOP (Delaware 892), AOP Intermediate and AIF (PB) VII. Apollo Commodities Management, L.P. with respect to Series I ("Commodities Management") is the manager of ANRP Intermediate and ANRP (Corp AIV). EPE Acquisition Holdings, LLC ("Acquisition Holdings") is the general partner of Domestic Co-Investors, Overseas Co-Investors, Co-Investor I, CoInvestor II and Co-Investor III. Management VII and Commodities Management are the members and managers of Acquisition Holdings. AIF VII Management, LLC ("AIF VII LLC") is the general partner of Management VII. 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

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Management. Apollo Commodities Management GP, LLC ("Commodities GP") is the general partner of Commodities 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 Harris and Marc Rowan are the managers, as well as executive officers, of Management Holdings GP, and as such may be deemed to have voting and dispositive control of the shares of stock held of record by the Apollo Funds. The address of each of AIF VII, AOP (Delaware 892), AOP Intermediate, AIF (PB) VII, Domestic Co-Investors, Co-Investor I, Co-Investor II and Co-Investor III is One Manhattanville Road, Suite 201, Purchase, New York 10577. The address of Overseas Co-Investors is c/o Intertrust Corporate Services (Cayman) Limited, 190 Elgin Street, George Town, Grand Cayman KY1-9005, Cayman Islands. The address of ANRP Intermediate, ANRP (Corp AIV), Commodities Management, Commodities GP, Acquisition Holdings, Management VII, AIF VII LLC, Apollo Management, Management GP, Management Holdings and Management Holdings GP, and Messrs. Black, Harris and Rowan, is 9 W. 57th Street, 43rd Floor, New York, New York 10019.

(2): Riverstone V Everest Holdings, L.P. and Riverstone V FT Corp Holdings, L.P. are the record holders of 19,942,040 shares of common stock and 11,334,686 shares of common stock, respectively. Riverstone Energy Partners V, L.P. is the general partner of each of Riverstone V Everest Holdings, L.P. and Riverstone V FT Corp Holdings, L.P. Riverstone Energy GP V, LLC is the general partner of Riverstone Energy Partners V, L.P. Riverstone Energy GP V, LLC is managed by a seven person managing committee. Pierre F. Lapeyre, Jr., David M. Leuschen, John Browne, James T. Hackett, Michael B. Hoffman, N. John Lancaster and Andrew W. Ward, as the members of the managing committee of Riverstone Energy GP V, LLC, may be deemed to share beneficial ownership of the shares of common stock owned of record by Riverstone V Everest Holdings, L.P. and Riverstone V FT Corp Holdings, L.P. These individuals expressly disclaim any such beneficial ownership. The business address for each of the persons named in this footnote is c/o Riverstone Holdings, 712 Fifth Avenue, 36th Floor, New York, New York 10019.
(3): Represents beneficial ownership attributable to record ownership of 31,276,726 shares of common stock by Texas Oil & Gas Holdings LLC ("TOGH"). Each of RSB Limited, Access Industries Holdings LLC, Access Industries, LLC, Access Industries Management, LLC and Len Blavatnik may be deemed to beneficially own the shares of common stock held directly by TOGH. RSB Limited holds a majority of the outstanding membership interests in TOGH and, as a result, may be deemed to share voting and investment power over the shares of common stock held directly by TOGH. Access Industries Holdings LLC holds a majority of the outstanding voting interests in RSB Limited and, as a result, may be deemed to share voting and investment power over the shares of common stock beneficially owned by TOGH and RSB Limited. Access Industries, LLC holds a majority of the outstanding voting membership interests in Access Industries Holdings LLC and, as a result, may be deemed to share voting and investment power over the shares of common stock beneficially owned by TOGH, RSB Limited and Access Industries Holdings LLC. Access Industries Management, LLC controls Access Industries Holdings LLC, Access Industries, LLC and TOGH and, as a result, may be deemed to share voting and investment power over the shares of common stock beneficially owned by TOGH, RSB Limited, Access Industries Holdings LLC and Access Industries, LLC. Len Blavatnik controls Access Industries Management, LLC and a majority of the outstanding voting interests in Access Industries, LLC and, as a result,

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may be deemed to share voting and investment power over the shares of common stock beneficially owned by TOGH, RSB Limited, Access Industries Holdings LLC, Access Industries, LLC and Access Industries Management, LLC. Because of their relationships with TOGH, RSB Limited, Access Industries Holdings LLC, Access Industries, LLC, Access Industries Management, LLC and Len Blavatnik, each of AI Energy Holding LLC ("AIEH"), Altep 2014 L.P. ("Altep 2014") and Access Industries, Inc. may be deemed to share voting and investment power over the shares of common stock beneficially owned by TOGH, RSB Limited, Access Industries Holdings LLC, Access Industries, LLC, Access Industries Management, LLC and Len Blavatnik. Each of RSB Limited, Access Industries Holdings LLC, Access Industries, LLC Access Industries Management, LLC, AIEH, Altep 2014, Access Industries, Inc. and Len Blavatnik, and each of their affiliated entities and the officers, partners, members, and managers thereof, other than TOGH, disclaims beneficial ownership of the shares held by TOGH. Also represents beneficial ownership of 3,556,387 shares of common stock held directly by AIEH. Each of Access Industries Management, LLC and Len Blavatnik may be deemed to beneficially own the shares of common stock held directly by AIEH. Access Industries Management, LLC controls AIEH and, as a result, may be deemed to share voting and investment power over the shares beneficially owned by AIEH. Len Blavatnik controls Access Industries Management, LLC and, as a result, may be deemed to share voting and investment power over the shares of common stock beneficially owned by AIEH. Because of their relationships with AIEH, Access Industries Management, LLC and Len Blavatnik, each of TOGH, RSB Limited, Access Industries Holdings LLC, Access Industries, LLC, Altep 2014 and Access Industries, Inc. may be deemed to share voting and investment power over the shares of common stock beneficially owned by AIEH, Access Industries Management, LLC and Len Blavatnik. Each of Access Industries Management, LLC, RSB Limited, Access Industries Holdings LLC, Access Industries, LLC, Altep 2014, Access Industries, Inc. and Len Blavatnik, and each of their affiliated entities and the officers, partners, members and managers thereof, other than AIEH, disclaims beneficial ownership of the shares held by AIEH. Also represents beneficial ownership of 109,991 shares of common stock held directly by Altep 2014. Each of Access Industries, Inc. and Len Blavatnik may be deemed to beneficially own the shares of common stock held directly by Altep 2014. Access Industries, Inc. is the general partner of Altep 2014 and, as a result, may be deemed to have voting and investment power over the shares owned directly by Altep 2014. Len Blavatnik controls Access Industries, Inc. and, as a result, may be deemed to share voting and investment power over the shares of common stock held by Altep 2014. Because of their relationships with Altep 2014, Access Industries, Inc. and Len Blavatnik, each of TOGH, RSB Limited, Access Industries Holdings LLC, Access Industries, LLC and AIEH may be deemed to share voting and investment power over the shares of common stock beneficially owned by Altep 2014, Access Industries, Inc. and Len Blavatnik. Each of Access Industries, Inc., RSB Limited, Access Industries Holdings LLC, Access Industries, LLC, Access Industries Management, LLC, AIEH and Len Blavatnik, and each of their affiliated entities and the officers, partners, members and managers thereof, other than Altep 2014, disclaims beneficial ownership of the shares held by Altep 2014. The address for TOGH, RSB Limited, Access Industries Holdings LLC, Access Industries, LLC, Access Industries Management, LLC, AIEH, Altep 2014, Access Industries, Inc. and Len Blavatnik is c/o Access Industries, Inc., 730 Fifth Avenue, 20th Floor, New York, NY 10019.

(4): KNOC is the state-owned oil and gas company of the Republic of Korea. Moon Kyu Suh, Joong Hyun Kim, Youn Sung Byun, Byung Jin Song, Chang Seok Jeong, Kang Hyun Shin, Hag Yong Sung, Han Joo Yoo, Woon Wha Park, Bo Hyun Chon, One Shick Shin,

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Gye Hyung Lee and Byung Og Ahn, as directors of KNOC (collectively, the "KNOC Directors" and each, a "KNOC Director"), exercise investment and voting power with respect to the shares of common stock owned by KNOC. Based on the foregoing relationships, each of the KNOC Directors may be deemed to be the beneficial owners of the shares of common stock owned by KNOC. Each KNOC Director disclaims beneficial ownership of such shares of common stock except to the extent of his or her pecuniary interest therein. The address of each KNOC Director and KNOC is c/o Korea National Oil Corporation, 305, Jongga-Ro, Jung-Gu, Ulsan, Korea 681-816.

(5): Mr. Smolik's beneficial ownership includes 123,705 shares held in a family limited partnership (Smolik Interests Limited Partnership) and 17,035 shares held in a family trust (BJS 2012 Trust, Brent Smolik Trustee). The address of Mr. Smolik is c/o EP Energy Corporation, 1001 Louisiana Street, Houston, Texas 77002.
(6): The address of each of the directors is c/o EP Energy Corporation, 1001 Louisiana Street, Houston, Texas 77002.
(7): Mr. Carrell's beneficial ownership excludes 1,300 shares owned by his daughter. Mr. Carrell disclaims beneficial ownership in those shares. The address of Mr. Carrell is c/o EP Energy Corporation, 1001 Louisiana Street, Houston, Texas 77002.
(8): The address of each of the directors is c/o Riverstone Holdings LLC, 712 Fifth Avenue, 19th Floor, New York, New York 10019.
(9): The address of each of the directors is c/o Apollo Global Management, LLC, 9 West 57^th Street, New York, New York 10019.
(10): The address of the director is c/o Korea National Oil Corporation, 305, Jongga-Ro, Jung-Gu, Ulsan, Korea 681-816.
(11): The address of the director is c/o Access Industries Holdings LLC, 730 Fifth Avenue, 20th Floor, New York, New York 10019.

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CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

Related Party Transactions Policy

The Board has adopted a written related party transactions policy. The policy defines a related party transaction as one in which Parent is a participant, the amount involved equals or exceeds $120,000, and a related party has a direct or indirect material interest. The policy defines a related party as any executive officer, director or director nominee, person known to be the beneficial owner of 5% or more of Parent's voting securities, immediate family member of any of the foregoing persons, or firm or corporation in which any of the foregoing persons is employed as an officer, is a general partner, or in which such person has a 10% or greater beneficial ownership interest.

The policy includes procedures to review and approve, as necessary, any related party transactions prior to the transaction being entered into, or ratify any related party transactions that have not been previously approved. Other than certain pre-approved transactions specifically set forth in the policy, any related party transaction involving executive officers or their immediate family members other than the CEO or the general counsel are referred to the CEO and general counsel for approval. Any related person transaction involving the general counsel and his or her immediate family members will be referred to the CEO for approval. Any related person transaction involving 5% or greater stockholders, directors, director nominees or the CEO and their immediate family members will be referred to the Governance and Nominating Committee for approval. All related party transactions are reported annually to the Governance and Nominating Committee.

In determining whether to approve a related party transaction, the CEO, general counsel or Governance and Nominating Committee will consider whether:

•: the terms of the transaction are fair to Parent and would be on the same basis if the transaction did not involve a related party;
•: there are business reasons to enter into the transaction;
•: the transaction would impair the independence of an outside director;
•: the transaction would present an improper conflict of interest for any director or executive officer; and
•: the transaction is material.

The policy for approval of related party transactions can be found on our website atwww.epenergy.com.

In addition, under our Parent's stockholders agreement, the consummation of any transaction involving Parent, on the one hand, and any legacy stockholder, director or affiliate of any legacy stockholder or director, on the other hand (each such transaction, a "Related Person Transaction"), will in each case require the approval of a majority of the directors, other than those directors that are (or whose affiliates are) party to such Related Person Transaction or have been designated by the legacy stockholders who are party, or whose affiliates are party to, such Related Person Transaction. This approval is not required for (among other things): (i) any transaction that is consummated in the ordinary course of business, on arm's length terms andde minimis in nature (it being understood that any transaction or series of related transactions that involves goods, services, property or other consideration valued in excess of $10,000 will not be deemed to bede minimis); and (ii) an acquisition of additional securities by a legacy stockholder pursuant to an exercise of its preemptive rights under the stockholders agreement.

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Amended and Restated Transaction Fee Agreement

In connection with the closing of the Acquisition in May 2012, we were subject to a transaction fee agreement with certain of our Sponsors for the provision of certain structuring, financial, investment banking and other similar advisory services. At the time of the Acquisition, we paid a one-time transaction fee of $71.5 million to the Sponsors in the aggregate in exchange for services rendered in connection with structuring, arranging the financing and performing other services. On December 20, 2013, the Transaction Fee Agreement was amended and restated in its entirety pursuant to which the requirement to pay an additional transaction fee to the Sponsors under the agreement was eliminated (and, as described below, an additional fee became payable under the amended and restated Management Fee Agreement). The amended and restated Transaction Fee Agreement terminated automatically in accordance with its terms upon the closing of Parent's initial public offering in January 2014.

Amended and Restated Management Fee Agreement

In connection with the closing of the Acquisition in May 2012, we entered into a management fee agreement with our Sponsors relating to the provision of certain management consulting and advisory services to the company following the acquisition. On December 20, 2013, the management fee agreement was amended and restated in its entirety (as so amended, the "Amended and Restated Management Fee Agreement") pursuant to which an additional fee became payable to the Sponsors in respect of management and similar services rendered prior to Parent's initial public offering. In January 2014, we paid a quarterly management fee of $6.25 million to our Sponsors pursuant to the Amended and Restated Management Fee Agreement. In addition, subject to the terms and conditions of the Amended and Restated Management Fee Agreement, upon the closing of Parent's initial public offering in January 2014, we paid the Sponsors an additional transaction fee equal to approximately $83 million. Below is a breakdown of the payments made to the Sponsors under the Amended and Restated Management Fee Agreement during 2014:

2014 Management Fee



Apollo	$	3,409,090
Riverstone	$	946,970
Access	$	946,970
KNOC	$	946,970

Total	$	6,250,000

2014 Transaction Fee



Apollo	$	45,466,554
Riverstone	$	12,629,598
Access	$	12,629,598
KNOC	$	12,629,598

Total	$	83,355,348

The Amended and Restated Management Fee Agreement, including the obligation to pay the quarterly management fee, terminated automatically in accordance with its terms upon the closing of Parent's initial public offering in January 2014.

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Supply Agreement

We are party to certain supply agreements with a subsidiary of Momentive Performance Materials Holdings LLC ("Momentive") to provide fracturing materials for our Eagle Ford drilling operations. Momentive is an affiliate of Apollo, one of our Sponsors. During 2014, we made payments to Momentive in the amount of $112,357,718 pursuant to these contracts. The supply agreements were entered into as market-based, arm's length transactions, and none of our Apollo-appointed Board members has a direct or indirect material interest in these payments.

Participation of Apollo Global Securities, LLC and Riverstone Capital Services LLC in the Sale of the Initial Notes

Apollo Global Securities, LLC is an affiliate of Apollo, one of the Sponsors, and acted as an initial purchaser in the sales of the initial notes. Apollo Global Securities, LLC received $675,000 of the gross spread in the sale of the initial notes.

Riverstone Capital Services LLC is an affiliate of Riverstone, one of the Sponsors, and acted as an initial purchaser in the sale of the initial notes. Riverstone Capital Services LLC received $225,000 of the gross spread in the sale of the initial notes.

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DESCRIPTION OF OTHER INDEBTEDNESS

The following sets forth a summary of the terms of certain of our indebtedness. This summary is not a complete description of all the terms of the agreements governing the indebtedness.

The RBL Facility

General. In connection with the Acquisition, the Issuer, as borrower, entered into a $2,000 million reserve-based borrowing base revolving credit facility (the "RBL Facility") with JPMorgan Chase Bank, N.A. as the administrative agent. The RBL Facility provides for revolving loans, swing line loans and letters of credit. After completing a borrowing base redetermination in March 2013, the aggregate amount of the RBL Facility was increased to $2,500 million. In October 2014, the Issuer completed its borrowing base redetermination, increasing the borrowing base to $2,750 million. In April 2015, the Issuer entered into an amendment to the RBL Facility whereby the lenders agreed to extend the maturity date (including the revolving commitment period) of the facility for all lenders by two years from May 24, 2017 to May 24, 2019, subject to an earlier maturity date in the event that, (i) more than $25.0 million of the Issuer's senior secured term loans are outstanding on the date that is 180 days prior to the maturity date of such senior secured term loans or (ii) more than $25.0 million of the Issuer's 2019 Senior Secured Notes are outstanding on the date that is 180 days prior to the maturity date of such notes. In addition, the Issuer completed its semi-annual redetermination, reaffirming the borrowing base at $2,750 million.

Interest Rates and Fees. Under the RBL Facility, we have a choice of borrowing at an interest rate equal to either an alternate base rate or the then-current LIBOR, in each case, plus an applicable margin. The applicable margin varies depending on the percentage of our borrowing base utilized at a given time and ranges from 150 to 250 basis points per annum for LIBOR based borrowings and ranges from 50 to 150 basis points per annum for base rate borrowings.

In addition to paying interest on outstanding principal under the RBL Facility, we are required to pay a commitment fee to the lenders in respect of the unutilized commitments. The commitment fee rate ranges from 37.5 to 50 basis points per annum based on our borrowing base usage at a given time.

Prepayments and Adjustments of the Borrowing Base. The borrowing base will be redetermined semi-annually on April 30^th and October 31^st of each year. In addition, the borrower may, no more than twice a year, and the lenders may, no more than once a year, elect to cause an interim redetermination of the borrowing base between the semi-annually scheduled redeterminations. If following a scheduled or interim redetermination of the borrowing base the aggregate amount of outstanding revolving loans, swingline loans and letters of credit exceeds the borrowing base, we will be required to elect within 10 business days to (i) within 30 days after such election, provide additional collateral having a borrowing base value sufficient to eliminate the deficiency; (ii) within 30 days after such election, prepay the loans (or cash collateralize the letters of credit) in an amount sufficient to eliminate such deficiency; (iii) prepay such deficiency in six equal monthly installments beginning on the 30th day after our receipt of notice of the deficiency from the administrative agent; or (iv) undertake a combination of clauses (i), (ii) and (iii); provided that any such deficiency must be cured prior to the maturity date of the RBL Facility.

If the borrowing base is reduced as a result of the incurrence of certain debt, early monetization or termination of hedge positions (above a certain agreed-upon threshold) or disposition of borrowing base assets (above a certain agreed-upon threshold) and the aggregate amount of outstanding revolving loans, swingline loans and letters of credit exceeds such reduced borrowing base, we are required to

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prepay the loans (or cash collateralize letters of credit) in an amount sufficient to eliminate such deficiency within two business days following receipt of the RBL Facility administrative agent's written notice of such deficiency.

Guarantees and Security. All obligations under the RBL Facility are fully and unconditionally guaranteed on a joint and several basis by, subject to certain exceptions, all of the Issuer's existing and future direct and indirect wholly owned material domestic restricted subsidiaries, referred to collectively as guarantors (together with the Issuer, referred to as "credit parties"). All obligations under the RBL Facility, and the guarantees of those obligations, are secured:

•: on a first-priority basis by a perfected pledge of all of the Issuer's capital stock and all of the capital stock of each direct, wholly owned, domestic, material restricted subsidiary held by the credit parties;
•: on a first-priority basis by perfected real property mortgages on not less than 80% of the PV-10 value of the proved oil and gas reserves included in the borrowing base under the RBL Facility;
•: on a first-priority basis by a perfected security interest in substantially all other tangible (other than real property and other oil and gas properties) and intangible assets of the credit parties (together with the collateral described in the preceding sentences, collectively referred to as the "RBL Facility Priority Collateral"); and
•: on a second-priority basis by a perfected security interest in the Term Loan Priority Collateral described below under "Senior Secured Term Loans."

The obligations under the RBL Facility are also guaranteed by EPE Acquisition LLC, the direct parent of the Issuer. EPE Acquisition's guarantee is limited recourse to the equity interests of the Issuer owned by EPE Acquisition.

Restrictive Covenants and Other Matters. The RBL Facility contains restrictive covenants that may limit EP Energy LLC's ability and the ability of its restricted subsidiaries to, among other things, (i) incur additional indebtedness; (ii) create liens; (iii) engage in mergers or consolidations; (iv) change our lines of business; (v) sell or transfer assets; (vi) pay dividends and distributions or repurchase the borrower's capital stock; (vii) amend material agreements governing our subordinated indebtedness; (viii) prepay, repay or repurchase certain junior indebtedness; (ix) engage in transactions with affiliates; (x) make investments, acquisitions, loans and advances; and (xi) enter into certain commodity and other regulated non-commodity hedging agreements. Each of these covenants is subject to customary or agreed-upon exceptions, baskets and thresholds.

In addition, the RBL Facility requires the Issuer to maintain a ratio of its consolidated total debt, net of unrestricted cash and cash equivalents, to consolidated trailing 12-month EBITDAX (as defined in the credit agreement governing the RBL Facility) of not more than 5.0 to 1.0, with a step-down to 4.75 to 1.0 one year after entering into the RBL Facility and a further step down to 4.5 to 1.0 two years after entering into the RBL Facility and thereafter. We are currently subject to 4.5 to 1.0 covenant level and will be in compliance pro forma for the Refinancing Transactions.

The credit agreement governing the RBL Facility also contains certain other customary affirmative covenants and events of default, subject to customary or agreed-upon exceptions, baskets and thresholds (including equity cure provisions).

Senior Secured Term Loans

Overview. In connection with the Acquisition, the Issuer, as borrower, entered into a $750 million aggregate principal amount (the "original term loans") senior secured term loan facility with Citibank, N.A. as the administrative and collateral agent, which will mature on May 24, 2018. In August 2012 and May 2013, the Issuer completed repricing amendments of the term loan facility that reduced the

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LIBOR floor and applicable margin applicable to the original term loans. In October 2012, the Issuer obtained $400 million aggregate principal amount of incremental term loans (the "incremental term loans") under the term loan facility pursuant an incremental facility amendment, which will mature on April 30, 2019. We refer to the original term loans and the incremental term loans as our "senior secured term loans."

Interest Rates. The original term loans bear interest, at our option, at a rate equal to the alternate base rate plus an applicable margin of 3.75% or the then-current LIBOR, subject to a 0.75% floor, plus an applicable margin of 2.75%. The incremental term loans bear interest, at our option, at a rate equal to the alternate base rate plus an applicable margin of 4.50% or the then-current LIBOR, subject to a 1.00% floor, plus an applicable margin of 3.50%.

Prepayments. The term loans are prepayable at any time without premium or penalty.

We are also required to offer to prepay our senior secured term loans, subject to customary reinvestment rights and other customary exceptions, with (a) the net cash proceeds from any non-ordinary course disposition of any Term Loan Priority Collateral and (ii) the net cash proceeds from any non-ordinary-course asset sale of RBL Facility Priority Collateral in excess of the amount required to be paid to the lenders under the RBL Facility or the holders of certain other indebtedness. We are also required to offer to prepay our senior secured term loans following the occurrence of a change of control at 101% of the outstanding principal amount thereof, plus accrued and unpaid interest to the date of repayment.

Guarantees and Security. All obligations under our senior secured term loans are fully and unconditionally guaranteed on a joint and several basis by each of the guarantors under the RBL Facility, and all such obligations and guarantees are secured (i) on a first-priority basis by a perfected pledge of the capital stock of all first-tier foreign subsidiaries that are directly owned by the Issuer or any guarantor (which pledge will be limited to 65% of the voting capital stock and 100% of the non-voting capital stock of such subsidiary) (referred to as the "Term Loan Priority Collateral") and (ii) on a second-priority basis by a security interest in the RBL Facility Priority Collateral. The agent for the senior secured term loans has entered into an intercreditor agreement governing the relationship between the lenders of the senior secured term loans and holders of any other indebtedness that is secured on a pari passu basis with the senior secured term loans.

Restrictive Covenants and Other Matters. The loan agreement governing our senior secured term loans contains restrictive covenants that may restrict the Issuer's ability and the ability of its restricted subsidiaries to, among other things, (i) incur additional indebtedness, (ii) make certain investments, loan, and advances, (iii) consolidate, merge, sell or otherwise dispose of all or any part of its assets or to purchase, lease or otherwise acquire all or any substantial part of assets of any other person, (iv) prepay subordinated indebtedness, pay dividends or make distributions or other restricted payments, (v) create liens on certain assets and (vi) enter into certain transactions with affiliates. Each of these covenants is subject to customary or agreed-upon exceptions, baskets and thresholds. The loan agreement governing our senior secured term loans does not contain any financial maintenance covenant.

The loan agreement governing our senior secured term loans also contains certain other customary affirmative covenants and events of default, subject to customary or agreed-upon exceptions, baskets and thresholds.

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Existing Senior Notes

As of March 31, 2015, on a pro forma basis after giving effect to the Refinancing Transactions (assuming the purchase of $750 million aggregate principal amount of our 2019 Senior Secured Notes in the Tender Offer), the Issuers had $2,000 million outstanding aggregate principal amount of 9.375% Senior Notes due 2020 (the "2020 Senior Notes") and $350 million outstanding aggregate principal amount of 7.750% Senior Notes due 2022 (the "2022 Senior Notes" and, together with the 2020 Senior Notes, the "existing senior notes"). The 2020 Senior Notes were issued in connection with the financing of the Acquisition and the 2022 Senior Notes were issued on August 8, 2012 to repay a portion of the borrowings under the RBL Facility, as well as for other general corporate purposes.

Maturity and Interest Payment Dates. The 2020 Senior Notes will mature on May 1, 2020. The 2022 Senior Notes will mature on September 1, 2022. Interest on the existing senior notes is payable semi-annually on May 1 and November 1 of each year in the case of the 2020 Senior Notes and March 1 and September 1 of each year in the case of the 2022 Senior Notes.

Guarantee. All of the existing senior notes are fully and unconditionally guaranteed on a joint and several basis by each of the guarantors under the RBL Facility.

Restrictive Covenants and Other Matters. The indentures governing the existing senior notes contain restrictive covenants that may restrict the Issuer's ability and the ability of its restricted subsidiaries to, among other things, (i) incur additional indebtedness, (ii) make certain investments, loan, and advances, (iii) consolidate, merge, sell or otherwise dispose of all or any part of its assets or to purchase, lease or otherwise acquire all or any substantial part of assets of any other person, (iv) prepay subordinated indebtedness, pay dividends or make distributions or other restricted payments, (v) create liens on certain assets and (vi) enter into certain transactions with affiliates. Each of these covenants is subject to customary or agreed-upon exceptions, baskets and thresholds.

The indentures governing the existing senior notes also contain customary events of default, subject to customary or agreed- upon exceptions, baskets and thresholds.

Upon the occurrence of a change of control, as defined in each of the applicable indentures, each holder has the right to require the Issuers to repurchase some or all of such holder's existing senior notes at a purchase price in cash equal to 101% of the principal amount thereof, plus accrued and unpaid interest, if any, to the repurchase date.

Optional Redemption. The Issuers may redeem some or all of the 2020 Senior Notes at any time on or prior to May 1, 2016, at a redemption price equal to 100% of the aggregate principal amount of the 2020 Senior Notes to be redeemed, plus a make-whole premium and accrued and unpaid interest, if any, to the redemption date. On or after May 1, 2016, the Issuers may also redeem some or all of the 2020 Senior Notes at the redemption prices specified in the indenture relating to the 2020 Senior Notes.

The Issuers may redeem some or all of the 2022 Senior Notes at any time on or prior to September 1, 2017, at a redemption price equal to 100% of the aggregate principal amount of the 2022 Senior Notes to be redeemed, plus a make-whole premium and accrued and unpaid interest, if any, to the redemption date. On or after September 1, 2017, the Issuers may also redeem some or all of the 2022 Senior Notes at the redemption prices specified in the indenture relating to the 2022 Senior Notes. At any time on or prior to September 1, 2015, the Issuers may also redeem up to 35% of the original aggregate principal amount of the 2022 Senior Notes with the net cash proceeds of equity offerings that are contributed to the Issuers, at a redemption price equal to 107.750% of the aggregate principal amount of the 2022 Senior Notes to be redeemed, plus accrued and unpaid interest, if any, to the redemption date.

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THE EXCHANGE OFFER

Terms of the Exchange Offer

We are offering to exchange our exchange notes for a like aggregate principal amount of our initial notes.

The exchange notes that we propose to issue in this exchange offer will be substantially identical to the form and terms of our initial notes except that, unlike our initial notes, the exchange notes (i) have been registered under the Securities Act and will be freely tradable by persons who are not affiliates of ours or subject to restrictions due to being a broker-dealer and (ii) are not entitled to the registration rights applicable to the initial notes under the Registration Rights Agreement. In addition, our obligation to pay additional interest on the initial notes due to the failure to consummate the exchange offer by a prior date does not apply to the exchange notes. You should read the description of the exchange notes in the section in this prospectus entitled "Description of the Exchange Notes."

Initial notes may be exchanged only for a minimum principal denomination of $2,000 and in integral multiples of $1,000 in excess thereof.

We reserve the right in our sole discretion to purchase or make offers for any initial notes that remain outstanding following the expiration or termination of this exchange offer and, to the extent permitted by applicable law, to purchase initial notes in the open market or privately negotiated transactions, one or more additional tender or exchange offers or otherwise. The terms and prices of these purchases or offers could differ significantly from the terms of this exchange offer.

Expiration Date; Extensions; Amendments; Termination

This exchange offer will expire at 5:00 p.m., New York City time, on August 4, 2015 unless we extend it in our reasonable discretion. The expiration date of this exchange offer will be at least 20 business days after the commencement of the exchange offer in accordance with Rule 14e-1(a) under the Exchange Act.

We expressly reserve the right to delay acceptance of any initial notes, extend or terminate this exchange offer and not accept any initial notes that we have not previously accepted if any of the conditions described below under "—Conditions to the Exchange Offer" have not been satisfied or waived by us. We will notify the exchange agent of any extension by oral notice promptly confirmed in writing or by written notice. We will also notify the holders of the initial notes by a press release or other public announcement communicated before 6 p.m., New York City time, on the next business day after the previously scheduled expiration date unless applicable laws require us to do otherwise.

We also expressly reserve the right to amend the terms of this exchange offer in any manner. If we make any material change, we will promptly disclose this change in a manner reasonably calculated to inform the holders of our initial notes of the change including providing public announcement or giving oral or written notice to these holders. A material change in the terms of this exchange offer could include a change in the timing of the exchange offer, a change in the exchange agent and other similar changes in the terms of this exchange offer. If we make any material change to this exchange offer, we will disclose this change by means of a post-effective amendment to the registration statement which includes this prospectus and will distribute an amended or supplemented prospectus to each registered holder of initial notes. In addition, we will extend this exchange offer for an additional five to ten business days as required by the Exchange Act, depending on the significance of the amendment, if the exchange offer would otherwise expire during that period. We will promptly notify the exchange agent by oral notice, promptly confirmed in writing, or written notice of any delay in acceptance, extension, termination or amendment of this exchange offer.

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Procedures for Tendering Initial Notes

Proper Execution and Delivery of Letters of Transmittal

To tender your initial notes in this exchange offer, you must useone of the three alternative procedures described below:

(1): Regular delivery procedure: Complete, sign and date the letter of transmittal, or a facsimile of the letter of transmittal. Have the signatures on the letter of transmittal guaranteed if required by the letter of transmittal. Mail or otherwise deliver the letter of transmittal or the facsimile together with the certificates representing the initial notes being tendered and any other required documents to the exchange agent before 5:00 p.m., New York City time, on the expiration date.
(2): Book-entry delivery procedure: Send a timely confirmation of a book-entry transfer of your initial notes, if this procedure is available, into the exchange agent's account at DTC in accordance with the procedures for book-entry transfer described under "—Book-Entry Delivery Procedure" below, before 5:00 p.m., New York City time, on the expiration date.
(3): Guaranteed delivery procedure: If time will not permit you to complete your tender by using the procedures described in (1) or (2) above before the expiration date and this procedure is available, comply with the guaranteed delivery procedures described under "—Guaranteed Delivery Procedure" below.

The method of delivery of the initial notes, the letter of transmittal and all other required documents is at your election and risk. Instead of delivery by mail, we recommend that you use an overnight or hand-delivery service. If you choose the mail, we recommend that you use registered mail, properly insured, with return receipt requested.In all cases, you should allow sufficient time to assure timely delivery. You should not send any letters of transmittal or initial notes to us. You must deliver all documents to the exchange agent at its address provided below. You may also request your broker, dealer, commercial bank, trust company or nominee to tender your initial notes on your behalf.

Only a holder of initial notes may tender initial notes in this exchange offer. A holder is any person in whose name initial notes are registered on our books or any other person who has obtained a properly completed bond power from the registered holder.

If you are the beneficial owner of initial notes that are registered in the name of a broker, dealer, commercial bank, trust company or other nominee and you wish to tender your notes, you must contact that registered holder promptly and instruct that registered holder to tender your notes on your behalf. If you wish to tender your initial notes on your own behalf, you must, before completing and executing the letter of transmittal and delivering your initial notes, either make appropriate arrangements to register the ownership of these notes in your name or obtain a properly completed bond power from the registered holder. The transfer of registered ownership may take considerable time.

You must have any signatures on a letter of transmittal or a notice of withdrawal guaranteed by:

(1)

a member firm of a registered national securities exchange or of the Financial, Industry Regulatory Authority, Inc. ("FINRA"),

(2)

a commercial bank or trust company having an office or correspondent in the United States, or

(3)

an eligible guarantor institution within the meaning of Rule 17Ad-15 under the Exchange Act,unless the initial notes are tendered:

(i): by a registered holder or by a participant in DTC whose name appears on a security position listing as the owner, who has not completed the box entitled "Special Issuance

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Instructions" or "Special Delivery Instructions" on the letter of transmittal and only if the exchange notes are being issued directly to this registered holder or deposited into this participant's account at DTC, or

(ii): for the account of a member firm of a registered national securities exchange or of FINRA, a commercial bank or trust company having an office or correspondent in the United States or an eligible guarantor institution within the meaning of Rule 17Ad-15 under the Exchange Act.

If the letter of transmittal or any bond powers are signed by:

(1): the registered holder(s) of the initial notes tendered: the signature must correspond with the name(s) written on the face of the initial notes without alteration, enlargement or any change whatsoever.
(2): a participant in DTC: the signature must correspond with the name as it appears on the security position listing as the holder of the initial notes.
(3): a person other than the registered holder of any initial notes: these initial notes must be endorsed or accompanied by bond powers and a proxy that authorize this person to tender the initial notes on behalf of the registered holder, in satisfactory form to us as determined in our sole discretion, in each case, as the name of the registered holder or holders appears on the initial notes.
(4): trustees, executors, administrators, guardians, attorneys-in-fact, officers of corporations or others acting in a fiduciary or representative capacity: these persons should so indicate when signing. Unless waived by us, evidence satisfactory to us of their authority to so act must also be submitted with the letter of transmittal.

To tender your initial notes in this exchange offer, you must make the following representations:

(1): you are authorized to tender, sell, assign and transfer the initial notes tendered and to acquire exchange notes issuable upon the exchange of such tendered initial notes, and that we will acquire good and unencumbered title thereto, free and clear of all liens, restrictions, charges and encumbrances and not subject to any adverse claim when the same are accepted by us,
(2): any exchange notes acquired by you pursuant to the exchange offer are being acquired in the ordinary course of business, whether or not you are the holder,
(3): you or any other person who receives exchange notes, whether or not such person is the holder of the exchange notes, has no arrangement or understanding with any person to participate in a distribution of such exchange notes (within the meaning of the Securities Act) and is not participating in, and does not intend to participate in, the distribution of such exchange notes,
(4): you or such other person who receives exchange notes, whether or not such person is the holder of the exchange notes, is not an "affiliate," (as defined in Rule 405 of the Securities Act), of ours, or if you or such other person is an affiliate, you or such other person will comply with the registration and prospectus delivery requirements of the Securities Act to the extent applicable,
(5): if you are not a broker-dealer, you represent that you are not engaged in, and do not intend to engage in, a distribution of exchange notes, and
(6): if you are a broker-dealer that will receive exchange notes for your own account in exchange for initial notes that were acquired by you as a result of market-making or other trading activities, you acknowledge that you will deliver a prospectus meeting the requirements of the

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Securities Act in connection with any resale, offer to resell or other transfer of such exchange notes.

You must also warrant that the acceptance of any tendered initial notes by us and the issuance of exchange notes in exchange therefor shall constitute performance in full of our obligations under the registration rights agreement relating to the initial notes.

To effectively tender notes through DTC, the financial institution that is a participant in DTC will electronically transmit its acceptance through the Automatic Tender Offer Program. DTC will then edit and verify the acceptance and send an agent's message to the exchange agent for its acceptance. An agent's message is a message transmitted by DTC to the exchange agent stating that DTC has received an express acknowledgment from the participant in DTC tendering the notes that this participant has received and agrees to be bound by the terms of the letter of transmittal, and that we may enforce this agreement against this participant.

Book-Entry Delivery Procedure

Any financial institution that is a participant in DTC's systems may make book-entry deliveries of initial notes by causing DTC to transfer these initial notes into the exchange agent's account at DTC in accordance with DTC's procedures for transfer. To effectively tender the initial notes through DTC, the financial institution that is a participant in DTC will electronically transmit its acceptance through the Automatic Tender Offer Program. DTC will then edit and verify the acceptance and send an agent's message to the exchange agent for its acceptance. An agent's message is a message transmitted by DTC to the exchange agent stating that DTC has received an express acknowledgment from the participant in DTC tendering the initial notes that this participant has received and agrees to be bound by the terms of the letter of transmittal, and that we may enforce this agreement against this participant. The exchange agent will make a request to establish an account for the initial notes at DTC for purposes of the exchange offer within two business days after the date of this prospectus.

A delivery of initial notes through a book-entry transfer into the exchange agent's account at DTC will only be effective if an agent's message, or the letter of transmittal or a facsimile of the letter of transmittal with any required signature guarantees and any other required documents, is transmitted to and received by the exchange agent at the address indicated below under "—Exchange Agent" before the expiration date unless the guaranteed delivery procedures described below are complied with.Delivery of documents to DTC does not constitute delivery to the exchange agent.

Guaranteed Delivery Procedure

If you are a registered holder of initial notes and desire to tender your notes, and (1) these notes are not immediately available, (2) time will not permit your notes or other required documents to reach the exchange agent before the expiration date or (3) the procedures for book-entry transfer cannot be completed on a timely basis, you may still tender in this exchange offer if:

(1): you tender through a member firm of a registered national securities exchange or of FINRA, a commercial bank or trust company having an office or correspondent in the United States, or an eligible guarantor institution within the meaning of Rule 17Ad-15 under the Exchange Act,
(2): before the expiration date, the exchange agent receives a properly completed and duly executed letter of transmittal (or facsimile of the letter of transmittal), and a notice of guaranteed delivery, substantially in the form provided by us, with your name and address as holder of the initial notes and the amount of notes tendered, stating that the tender is being made by that letter and notice and guaranteeing that within three New York Stock Exchange trading days after the expiration date, the certificates for all the initial notes tendered, in

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proper form for transfer, or a book-entry confirmation with an agent's message, as the case may be, and any other documents required by the letter of transmittal will be deposited by the eligible institution with the exchange agent, and

(3): the certificates for all your tendered initial notes in proper form for transfer or a book-entry confirmation as the case may be, and all other documents required by the letter of transmittal are received by the exchange agent within three New York Stock Exchange trading days after the expiration date.

Acceptance of Initial Notes for Exchange; Delivery of Exchange Notes

Your tender of initial notes will constitute an agreement between you and us governed by the terms and conditions provided in this prospectus and in the related letter of transmittal.

We will be deemed to have received your tender as of the date when your duly signed letter of transmittal accompanied by your initial notes tendered, or a timely confirmation of a book-entry transfer of these notes into the exchange agent's account at DTC with an agent's message, or a notice of guaranteed delivery from an eligible institution is received by the exchange agent.

All questions as to the validity, form, eligibility, including time of receipt, acceptance and withdrawal of tenders will be determined by us in our sole discretion. Our determination will be final and binding.

We reserve the absolute right to reject any and all initial notes not properly tendered or any initial notes which, if accepted, would, in our opinion or our counsel's opinion, be unlawful. We also reserve the absolute right to waive any conditions of this exchange offer or irregularities or defects in tender as to particular notes with the exception of conditions to this exchange offer relating to the obligations of broker dealers, which we will not waive. If we waive a condition to this exchange offer, the waiver will be applied equally to all noteholders. Our interpretation of the terms and conditions of this exchange offer, including the instructions in the letter of transmittal, will be final and binding on all parties. Unless waived, any defects or irregularities in connection with tenders of initial notes must be cured within such time as we shall determine. We, the exchange agent or any other person will be under no duty to give notification of defects or irregularities with respect to tenders of initial notes. We and the exchange agent or any other person will incur no liability for any failure to give notification of these defects or irregularities. Tenders of initial notes will not be deemed to have been made until such irregularities have been cured or waived. The exchange agent will return without cost to their holders any initial notes that are not properly tendered and as to which the defects or irregularities have not been cured or waived promptly following the expiration date.

If all the conditions to the exchange offer are satisfied or waived on the expiration date, we will accept all initial notes properly tendered and will issue the exchange notes promptly thereafter. Please refer to the section of this prospectus entitled "—Conditions to the Exchange Offer" below. For purposes of this exchange offer, initial notes will be deemed to have been accepted as validly tendered for exchange when, as and if we give oral or written notice of acceptance to the exchange agent.

We will issue the exchange notes in exchange for the initial notes tendered pursuant to a notice of guaranteed delivery by an eligible institution only against delivery to the exchange agent of the letter of transmittal, the tendered initial notes and any other required documents, or the receipt by the exchange agent of a timely confirmation of a book-entry transfer of initial notes into the exchange agent's account at DTC with an agent's message, in each case, in form satisfactory to us and the exchange agent.

If any tendered initial notes are not accepted for any reason provided by the terms and conditions of this exchange offer or if initial notes are submitted for a greater principal amount than the holder desires to exchange, the unaccepted or non-exchanged initial notes will be returned without expense to

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the tendering holder, or, in the case of initial notes tendered by book-entry transfer procedures described above, will be credited to an account maintained with the book-entry transfer facility, promptly after withdrawal, rejection of tender or the expiration or termination of the exchange offer.

By tendering into this exchange offer, you will irrevocably appoint our designees as your attorney-in-fact and proxy with full power of substitution and resubstitution to the full extent of your rights on the initial notes tendered. This proxy will be considered coupled with an interest in the tendered initial notes. This appointment will be effective only when, and to the extent that we accept your notes in this exchange offer. All prior proxies on these initial notes will then be revoked and you will not be entitled to give any subsequent proxy. Any proxy that you may give subsequently will not be deemed effective. Our designees will be empowered to exercise all voting and other rights of the holders as they may deem proper at any meeting of noteholders or otherwise. The initial notes will be validly tendered only if we are able to exercise full voting rights on the initial notes, including voting at any meeting of the noteholders, and full rights to consent to any action taken by the note holders.

Withdrawal of Tenders

Except as otherwise provided in this prospectus, you may withdraw tenders of initial notes at any time before 5:00 p.m., New York City time, on the expiration date.

For a withdrawal to be effective, you must send a written or facsimile transmission notice of withdrawal to the exchange agent before 5:00 p.m., New York City time, on the expiration date at the address provided below under "—Exchange Agent" and before acceptance of your tendered notes for exchange by us.

Any notice of withdrawal must:

(1): specify the name of the person having tendered the initial notes to be withdrawn,
(2): identify the notes to be withdrawn, including, if applicable, the registration number or numbers and total principal amount of these notes,
(3): be signed by the person having tendered the initial notes to be withdrawn in the same manner as the original signature on the letter of transmittal by which these notes were tendered, including any required signature guarantees, or be accompanied by documents of transfer sufficient to permit the trustee for the initial notes to register the transfer of these notes into the name of the person having made the original tender and withdrawing the tender,
(4): specify the name in which any of these initial notes are to be registered, if this name is different from that of the person having tendered the initial notes to be withdrawn, and
(5): if applicable because the initial notes have been tendered through the book-entry procedure, specify the name and number of the participant's account at DTC to be credited, if different than that of the person having tendered the initial notes to be withdrawn.

We will determine all questions as to the validity, form and eligibility, including time of receipt, of all notices of withdrawal and our determination will be final and binding on all parties. Initial notes that are withdrawn will be deemed not to have been validly tendered for exchange in this exchange offer.

The exchange agent will return without cost to their holders all initial notes that have been tendered for exchange and are not exchanged for any reason, promptly after withdrawal, rejection of tender or expiration or termination of this exchange offer.

You may retender properly withdrawn initial notes in this exchange offer by following one of the procedures described under "—Procedures for Tendering Initial Notes" above at any time before the expiration date.

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Conditions to the Exchange Offer

We will complete this exchange offer only if:

(1): there is no change in the laws and regulations which would impair our ability to proceed with this exchange offer,
(2): there is no change in the current interpretation of the staff of the SEC which permits resales of the exchange notes, and
(3): there is no stop order issued by the SEC which would suspend the effectiveness of the registration statement which includes this prospectus or the qualification of the indenture for the exchange notes under the Trust Indenture Act.

These conditions are for our sole benefit. We may assert any one of these conditions regardless of the circumstances giving rise to it and may also waive any one of them, in whole or in part, at any time and from time to time, if we determine in our reasonable discretion that it has not been satisfied, subject to applicable law. Notwithstanding the foregoing, all conditions to the exchange offer must be satisfied or waived before the expiration of this exchange offer. If we waive a condition to this exchange offer, the waiver will be applied equally to all note holders. We will not be deemed to have waived our rights to assert or waive these conditions if we fail at any time to exercise any of them. Each of these rights will be deemed an ongoing right which we may assert at any time and from time to time.

If we determine that we may terminate this exchange offer because any of these conditions is not satisfied, we may:

(1): refuse to accept and return to their holders any initial notes that have been tendered,
(2): extend the exchange offer and retain all initial notes tendered before the expiration date, subject to the rights of the holders of these notes to withdraw their tenders, or
(3): waive any condition that has not been satisfied and accept all properly tendered initial notes that have not been withdrawn or otherwise amend the terms of this exchange offer in any respect as provided under the section in this prospectus entitled "—Expiration Date; Extensions; Amendments; Termination."

Accounting Treatment

We will record the exchange notes at the same carrying value as the initial notes as reflected in our accounting records on the date of the exchange. Accordingly, we will not recognize any gain or loss for accounting purposes. We will amortize the costs of the offering of the initial notes and the exchange offer and the unamortized expenses related to the issuance of the exchange notes over the term of the notes.

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Exchange Agent

We have appointed Wilmington Trust, National Association as exchange agent for this exchange offer. You should direct all questions and requests for assistance on the procedures for tendering and all requests for additional copies of this prospectus or the letter of transmittal to the exchange agent as follows:

By Mail, Hand or Overnight Delivery:

Wilmington Trust, National Association
Rodney Square North
1100 North Market Street
Wilmington, Delaware 19890-1626
Attention: Workflow Management—5^th Floor

By Facsimile:
(302) 636-4139

For Information or Confirmation by Telephone:
(302) 636-6470

Fees and Expenses

We will bear the expenses of soliciting tenders in this exchange offer, including fees and expenses of the exchange agent and trustee and accounting, legal, printing and related fees and expenses.

We will not make any payments to brokers, dealers or other persons soliciting acceptances of this exchange offer. However, we will pay the exchange agent reasonable and customary fees for its services and will reimburse the exchange agent for its reasonable out-of-pocket expenses in connection with this exchange offer. We will also pay brokerage houses and other custodians, nominees and fiduciaries their reasonable out-of-pocket expenses for forwarding copies of the prospectus, letters of transmittal and related documents to the beneficial owners of the initial notes and for handling or forwarding tenders for exchange to their customers.

We will pay all transfer taxes, if any, applicable to the exchange of initial notes in accordance with this exchange offer. However, tendering holders will pay the amount of any transfer taxes, whether imposed on the registered holder or any other persons, if:

(1): certificates representing exchange notes or initial notes for principal amounts not tendered or accepted for exchange are to be delivered to, or are to be registered or issued in the name of, any person other than the registered holder of the notes tendered,
(2): tendered initial notes are registered in the name of any person other than the person signing the letter of transmittal, or
(3): a transfer tax is payable for any reason other than the exchange of the initial notes in this exchange offer.

If you do not submit satisfactory evidence of the payment of any of these taxes or of any exemption from this payment with the letter of transmittal, we will bill you directly the amount of these transfer taxes.

Your Failure to Participate in the Exchange Offer Will Have Adverse Consequences

The initial notes were not registered under the Securities Act or under the securities laws of any state and you may not resell them, offer them for resale or otherwise transfer them unless they are subsequently registered or resold under an exemption from the registration requirements of the

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Securities Act and applicable state securities laws. If you do not exchange your initial notes for exchange notes in accordance with this exchange offer, or if you do not properly tender your initial notes in this exchange offer, you will not be able to resell, offer to resell or otherwise transfer the initial notes unless they are registered under the Securities Act or unless you resell them, offer to resell or otherwise transfer them under an exemption from the registration requirements of, or in a transaction not subject to, the Securities Act.

In addition, except as set forth in this paragraph, you will not be able to obligate us to register the initial notes under the Securities Act. You will not be able to require us to register your initial notes under the Securities Act unless:

(1): the initial purchasers request us to register initial notes that are not eligible to be exchanged for exchange notes in the exchange offer; or
(2): you are not eligible to participate in the exchange offer; or
(3): you may not resell the exchange notes you acquire in the exchange offer to the public without delivering a prospectus and the prospectus contained in the exchange offer registration statement is not appropriate or available for such resales by you; or
(4): you are a broker-dealer and hold initial notes that are part of an unsold allotment from the original sale of the initial notes,

in which case the registration rights agreement requires us to file a registration statement for a continuous offer in accordance with Rule 415 under the Securities Act for the benefit of the holders of the initial notes described in this sentence. We do not currently anticipate that we will register under the Securities Act any initial notes that remain outstanding after completion of the exchange offer.

Delivery of Prospectus

Each broker-dealer that receives exchange notes for its own account in exchange for initial notes, where such initial notes were acquired by such broker-dealer as a result of market-making activities or other trading activities, must acknowledge that it will deliver a prospectus in connection with any resale of such exchange notes. See "Plan of Distribution."

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DESCRIPTION OF EXCHANGE NOTES

General

On May 28, 2015, EP Energy LLC, a Delaware limited liability company, and Everest Acquisition Finance Inc., a Delaware corporation (each an "Issuer" and together, the "Issuers"), issued $800 million aggregate principal amount of 6.375% Senior Notes due 2023 (the "initial notes") under an indenture (the "indenture") dated as of May 28, 2015, entered into by and among the Issuers, the Subsidiary Guarantors (as defined below) and Wilmington Trust, National Association, as Trustee. In this "Description of Exchange Notes," (i) "we," "us" and "our" mean EP Energy LLC and its Subsidiaries and (ii) the term "Issuers" refers only to EP Energy LLC and Everest Acquisition Finance Inc., but not to any of their Subsidiaries.

The Issuers will issue the exchange notes under the indenture. The terms of the exchange notes are identical in all material respects to the initial notes except that upon completion of the exchange offer, the exchange notes will be registered under the Securities Act and free of any covenants regarding registration rights. We refer to the initial notes as the "initial notes." We refer to the exchange notes as the "exchange notes." Unless otherwise indicated by the context, references in the "Description of Exchange Notes" section to the "notes" include the initial notes and the exchange notes.

The following summary of certain provisions of the indenture and the notes does not purport to be complete and is subject to, and is qualified in its entirety by reference to, all the provisions of those agreements, including the definitions of certain terms therein and those terms made a part thereof by the TIA. We urge you to read those agreements because they, not this description, define your rights as holders of the notes. Capitalized terms used in this "Description of Exchange Notes" section and not otherwise defined have the meanings set forth under "—Certain Definitions."

The Issuers will issue the exchange notes in exchange for initial notes, in an initial aggregate principal amount of up to $800 million. The Issuers may issue additional notes from time to time. Any offering of additional notes is subject to the covenant described below under the caption "—Certain Covenants—Limitation on Incurrence of Indebtedness and Issuance of Disqualified Stock and Preferred Stock." The notes and any additional notes subsequently issued under the indenture may, at our election, be treated as a single class for all purposes under the indenture, including, without limitation, waivers, amendments, redemptions and offers to purchase;provided that if the additional notes are not fungible with the notes for U.S. federal income tax purposes, the additional notes will have a separate CUSIP number, if applicable. Unless the context otherwise requires, for all purposes of the indenture and this "Description of Exchange Notes," references to the notes include any additional notes actually issued.

Principal of, premium, if any, and interest on the exchange notes will be payable, and the exchange notes may be exchanged or transferred, at the office or agency designated by the Issuers (which initially shall be the designated office or agency of the Trustee).

The exchange notes will be issued only in fully registered form, without coupons, in minimum denominations of $2,000 and any integral multiple of $1,000 in excess thereof;provided that exchange notes may be issued in denominations of less than $2,000 solely to accommodate book-entry positions that have been created by a DTC participant in denominations of less than $2,000. No service charge will be made for any registration of transfer or exchange of the notes, but in certain circumstances the Issuers may require payment of a sum sufficient to cover any transfer tax or other similar governmental charge payable in connection therewith.

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Terms of the Exchange Notes

The notes will be senior obligations of the Issuers and will mature on June 15, 2023. Each note will bear interest at a rate of 6.375% per annum from the Issue Date or from the most recent date to which interest has been paid or provided for, payable semiannually to holders of record at the close of business on June 1 or December 1 immediately preceding the interest payment date on June 15 and December 15 of each year, commencing December 15, 2015.

Optional Redemption

On or after June 15, 2018 the Issuers may redeem the notes at their option, in whole at any time or in part from time to time, upon not less than 30 nor more than 60 days' prior notice mailed by first-class mail to each holder's registered address, or delivered electronically if held by DTC, at the following redemption prices (expressed as a percentage of principal amount), plus accrued and unpaid interest and additional interest, if any, to, but excluding, the redemption date (subject to the right of holders of record on the relevant record date to receive interest due on the relevant interest payment date), if redeemed during the 12-month period commencing on June 15 of the years set forth below:

Period

2018	104.781	%
2019	103.188	%
2020	101.594	%
2021 and thereafter	100.000	%

In addition, prior to June 15, 2018 the Issuers may redeem the notes at their option, in whole at any time or in part from time to time, upon not less than 30 nor more than 60 days' prior notice mailed by the Issuers by first-class mail to each holder's registered address, or delivered electronically if held by DTC, at a redemption price equal to 100% of the principal amount of the notes redeemed plus the Applicable Premium as of, and accrued and unpaid interest and additional interest, if any, to, but excluding, the applicable redemption date (subject to the right of holders of record on the relevant record date to receive interest due on the relevant interest payment date).

Notwithstanding the foregoing, at any time and from time to time on or prior to June 15, 2018 the Issuers may redeem in the aggregate up to 35% of the original aggregate principal amount of the notes (calculated after giving effect to any issuance of additional notes) in an aggregate amount equal to the net cash proceeds of one or more Equity Offerings (1) by Holdings or (2) by any direct or indirect parent of Holdings to the extent the net cash proceeds thereof are contributed to the common equity capital of Holdings or used to purchase Capital Stock (other than Disqualified Stock) of Holdings, at a redemption price (expressed as a percentage of principal amount thereof) of 106.375%, plus accrued and unpaid interest and additional interest, if any, to, but excluding, the redemption date (subject to the right of holders of record on the relevant record date to receive interest due on the relevant interest payment date);provided,however, that at least 50% of the original aggregate principal amount of the notes (calculated after giving effect to any issuance of additional notes) must remain outstanding after each such redemption;provided,further, that such redemption shall occur within 180 days after the date on which any such Equity Offering is consummated upon not less than 30 nor more than 60 days' notice mailed by the Issuer, or delivered electronically if held by DTC, to each holder of notes being redeemed and otherwise in accordance with the procedures set forth in the indenture.

Notice of any redemption upon any Equity Offering may be given prior to the completion thereof, and any such redemption or notice may, at the Issuers' discretion, be subject to one or more conditions precedent, including, but not limited to, completion of the related Equity Offering.

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Selection

In the case of any partial redemption, selection of notes for redemption will be made by the Trustee in compliance with the requirements of the principal national securities exchange, if any, on which the notes are listed (and the Issuers shall notify the Trustee of any such listing), or if the notes are not so listed, on a pro rata basis to the extent practicable or by lot or by such other method as the Trustee shall deem fair and appropriate (and, in such manner that complies with the requirements of DTC, if applicable);provided that no notes of $2,000 or less shall be redeemed in part. If any note is to be redeemed in part only, the notice of redemption relating to such note shall state the portion of the principal amount thereof to be redeemed. A new note in principal amount equal to the unredeemed portion thereof will be issued in the name of the holder thereof upon cancellation of the original note. On and after the redemption date, interest will cease to accrue on notes or portions thereof called for redemption so long as the Issuers have deposited with the paying agent funds sufficient to pay the principal of, plus accrued and unpaid interest and additional interest (if any) on, the notes to be redeemed.

Mandatory Redemption; Offers to Purchase; Open Market Purchases

The Issuers will not be required to make any mandatory redemption or sinking fund payments with respect to the notes. However, under certain circumstances, the Issuers may be required to offer to purchase notes as described under the captions "—Change of Control" and "—Certain Covenants—Asset Sales." We may at any time and from time to time purchase notes in the open market or otherwise.

Ranking

The indebtedness evidenced by the notes will be senior Indebtedness of the Issuers, will rankpari passu in right of payment with all existing and future senior Indebtedness of the Issuers and will be senior in right of payment to all existing and future Subordinated Indebtedness of the Issuers.

The indebtedness evidenced by the Subsidiary Guarantees will be senior Indebtedness of the applicable Subsidiary Guarantor, will rankpari passu in right of payment with all existing and future senior Indebtedness of such Subsidiary Guarantor and will be senior in right of payment, to all existing and future Subordinated Indebtedness of such Subsidiary Guarantor.

At March 31, 2015, on a pro forma basis after giving effect to the Refinancing Transactions:

(1): Holdings and its Subsidiaries would have had $1,617 million in aggregate principal amount of Secured Indebtedness outstanding, including the loans under the Term Loan Facility, of which $971 million of Secured Indebtedness would have been outstanding under the Credit Agreement, and approximately $1.7 billion would have been available and undrawn (after giving effect to issued and undrawn letters of credit), and to all of which the notes will be subordinated to the extent of the value of the collateral securing such Indebtedness; and
(2): Holdings and its Subsidiaries would have had $3,150 million in aggregate principal amount of senior unsecured Indebtedness outstanding, including the Existing Senior Notes and the notes.

Although the indenture limits the Incurrence of Indebtedness and the issuance of Disqualified Stock by Holdings and its Restricted Subsidiaries, and the issuance of Preferred Stock by the Restricted Subsidiaries of Holdings that are not Subsidiary Guarantors, such limitation is subject to a number of significant qualifications and exceptions. Holdings and its Subsidiaries are able to Incur additional amounts of Indebtedness. Under certain circumstances the amount of such Indebtedness could be substantial and, subject to certain limitations, such Indebtedness may be Secured Indebtedness. See "—Certain Covenants—Limitation on Incurrence of Indebtedness and Issuance of Disqualified Stock and Preferred Stock" and "—Liens."

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Holdings is a holding company that has no material assets or operations other than the equity in the assets of its Subsidiaries. Unless a Subsidiary is a Subsidiary Guarantor, claims of creditors of such Subsidiary, including trade creditors, and claims of preferred stockholders (if any) of such Subsidiary, generally will have priority with respect to the assets and earnings of such Subsidiary over the claims of creditors of the Issuers, including holders of the notes. The notes, therefore, will be effectively subordinated to holders of indebtedness and other creditors (including trade creditors) and preferred stockholders (if any) of Subsidiaries of Holdings that are not Subsidiary Guarantors. Our only Subsidiaries that are not Subsidiary Guarantors will be (i) non-Wholly Owned Subsidiaries and (ii) Foreign Subsidiaries, as well as Domestic Subsidiaries (x) that own no material assets (directly or through their Subsidiaries) other than equity interests of one or more of Foreign Subsidiaries that are CFCs or (y) that are Subsidiaries of Foreign Subsidiaries.

See "Risk Factors—Risks Related to Our Indebtedness and the Notes—The notes will be structurally subordinated to all liabilities of our non-guarantor subsidiaries."

Subsidiary Guarantees

Each of Holdings' direct and indirect Wholly Owned Restricted Subsidiaries (other than Everest Acquisition Finance Inc.) that are Domestic Subsidiaries and that are borrowers or guarantors under the Credit Agreement jointly and severally irrevocably and unconditionally guarantee on a senior basis the performance and punctual payment when due, whether at Stated Maturity, by acceleration or otherwise, of all obligations of the Issuers under the indenture and the notes, whether for payment of principal of, premium, if any, or interest or additional interest on the notes, expenses, indemnification or otherwise (all such obligations guaranteed by such Subsidiary Guarantors being herein called the "Subsidiary Guaranteed Obligations"). Such Subsidiary Guarantors agree to pay, in addition to the amount stated above, any and all expenses (including reasonable counsel fees and expenses) incurred by the Trustee in enforcing any rights under the Subsidiary Guarantees.

Each Subsidiary Guarantee will be limited to an amount not to exceed the maximum amount that can be guaranteed by the applicable Subsidiary Guarantor without rendering the Subsidiary Guarantee, as it relates to such Subsidiary Guarantor, voidable under applicable law relating to fraudulent conveyance or fraudulent transfer or similar laws affecting the rights of creditors generally. See "Risk Factors—Risks Related to Our Indebtedness and the Notes—Because each subsidiary guarantor's liability under its guarantee may be reduced to zero, avoided or released under certain circumstances, you may not receive any payments from some or all of the subsidiary guarantors." After the Issue Date, Holdings will cause each Wholly Owned Restricted Subsidiary (other than an Excluded Subsidiary) that Incurs or guarantees certain Indebtedness of Holdings or any of its Restricted Subsidiaries or issues shares of Disqualified Stock and Everest Acquisition Finance Inc. to execute and deliver to the Trustee a supplemental indenture pursuant to which such Restricted Subsidiary will guarantee payment of the notes on the same unsecured senior basis. See "—Certain Covenants—Future Subsidiary Guarantors."

Each Subsidiary Guarantee will be a continuing guarantee and shall, subject to the next two succeeding paragraphs:

(1): remain in full force and effect until payment in full of all the Subsidiary Guaranteed Obligations of such Subsidiary Guarantor;
(2): be binding upon each such Subsidiary Guarantor and its successors; and
(3): inure to the benefit of and be enforceable by the Trustee, the holders and their successors, transferees and assigns.

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Each Subsidiary's Subsidiary Guarantee will be automatically released upon:

(1): the sale, disposition, exchange or other transfer (including through merger, consolidation, amalgamation or otherwise) of the Capital Stock (including any sale, disposition or other transfer following which the applicable Subsidiary Guarantor is no longer a Restricted Subsidiary), of the applicable Subsidiary Guarantor if such sale, disposition, exchange or other transfer is made in a manner not in violation of the indenture;
(2): the designation of such Subsidiary Guarantor as an Unrestricted Subsidiary in accordance with the covenant described under "—Certain Covenants—Limitation on Restricted Payments" and the definition of "Unrestricted Subsidiary";
(3): the release or discharge of the guarantee by such Subsidiary Guarantor of the Credit Agreement or other Indebtedness or the guarantee of any other Indebtedness which resulted in the obligation to guarantee the notes;
(4): the Issuers' exercise of their legal defeasance option or covenant defeasance option as described under "—Defeasance" or if the Issuers' obligations under the indenture are discharged in accordance with the terms of the indenture; and
(5): the occurrence of a Covenant Suspension Event.

A Restricted Subsidiary's Subsidiary Guarantee also will be automatically released upon the applicable Subsidiary ceasing to be a Subsidiary as a result of any foreclosure of any pledge or security interest securing Bank Indebtedness or other exercise of remedies in respect thereof.

Change of Control

Upon the occurrence of a Change of Control, each holder will have the right to require the Issuers to repurchase all or any part of such holder's notes at a purchase price in cash equal to 101% of the principal amount thereof, plus accrued and unpaid interest, if any, to, but excluding, the date of repurchase (the "Change of Control Payment") (subject to the right of holders of record on the relevant record date to receive interest due on the relevant interest payment date), except to the extent the Issuers have previously or concurrently elected to redeem notes as described under "—Optional Redemption."

In the event that at the time of such Change of Control, the terms of the Bank Indebtedness restrict or prohibit the repurchase of notes pursuant to this covenant, then prior to the delivery of the notice to holders provided for in the immediately following paragraph but in any event within 30 days following any Change of Control, the Issuers shall:

(1): repay in full all Bank Indebtedness or, if doing so will allow the purchase of notes, offer to repay in full all Bank Indebtedness and repay the Bank Indebtedness of each lender and/or noteholder who has accepted such offer; or
(2): obtain the requisite consent under the agreements governing the Bank Indebtedness to permit the repurchase of the notes as provided for in the immediately following paragraph.

See "Risk Factors—Risks Related to Our Indebtedness and the Notes—We may not be able to repurchase the notes upon a change of control."

Within 30 days following any Change of Control, except to the extent that the Issuers have exercised their right to redeem the notes by delivery of a notice of redemption as described under

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"—Optional Redemption," the Issuers shall mail a notice (a "Change of Control Offer") to each holder with a copy to the Trustee (or deliver a notice pursuant to the procedures of DTC) stating:

(1): that a Change of Control has occurred and that such holder has the right to require the Issuers to repurchase such holder's notes for the Change of Control Payment (subject to the right of holders of record on a record date to receive interest on the relevant interest payment date);
(2): the circumstances regarding such Change of Control;
(3): the repurchase date (which shall be no earlier than 30 days nor later than 60 days from the date such notice is sent); and
(4): the instructions determined by the Issuers, consistent with this covenant, that a holder must follow in order to have its notes purchased.

A Change of Control Offer may be made in advance of a Change of Control, and conditioned upon such Change of Control, if a definitive agreement is in place for the Change of Control at the time of making of the Change of Control Offer.

In addition, the Issuers will not be required to make a Change of Control Offer upon a Change of Control if: (i) a third party makes the Change of Control Offer in the manner, at the times and otherwise in compliance with the requirements set forth in the indenture applicable to a Change of Control Offer made by the Issuers and purchases all notes properly tendered and not withdrawn under such Change of Control Offer; or (ii) a notice of redemption of all outstanding notes has been given pursuant to the indenture as described above under the caption "—Optional Redemption," unless and until there is a default in payment of the applicable redemption price.

If holders of not less than 90% in aggregate principal amount of the outstanding notes validly tender and do not withdraw such notes in a Change of Control Offer and the Issuers, or any third party making a Change of Control Offer in lieu of the Issuers as described above, purchase all of the notes validly tendered and not withdrawn by such holders, the Issuers or such third party will have the right, upon not less than 30 nor more than 60 days' prior written notice, given not more than 30 days following such purchase pursuant to the Change of Control Offer described above, to redeem all notes that remain outstanding following such purchase at a price in cash equal to the Change of Control Payment.

Notes repurchased by the Issuers pursuant to a Change of Control Offer will have the status of notes issued but not outstanding or will be retired and canceled at the option of the Issuers. Notes purchased by a third party pursuant to the preceding paragraph will have the status of notes issued and outstanding.

The Issuers will comply, to the extent applicable, with the requirements of Section 14(e) of the Exchange Act and any other securities laws or regulations in connection with the repurchase of notes pursuant to this covenant. To the extent that the provisions of any securities laws or regulations conflict with provisions of this covenant, the Issuers will comply with the applicable securities laws and regulations and will not be deemed to have breached its obligations under this covenant by virtue thereof.

This Change of Control repurchase provision is a result of negotiations between the Issuers and the initial purchasers. The Issuers have no present intention to engage in a transaction involving a Change of Control, although it is possible that the Issuers could decide to do so in the future. Subject to the limitations discussed below, the Issuers could, in the future, enter into certain transactions, including acquisitions, refinancings or other recapitalizations, that would not constitute a Change of Control under the indenture, but that could increase the amount of indebtedness outstanding at such time or otherwise affect the Issuers' capital structure or credit rating.

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The occurrence of events which would constitute a Change of Control would constitute a default under the Credit Agreement. Future Bank Indebtedness of the Issuers may contain prohibitions on certain events which would constitute a Change of Control or require such Bank Indebtedness to be repurchased upon a Change of Control. Moreover, the exercise by the holders of their right to require the Issuers to repurchase the notes could cause a default under such Bank Indebtedness, even if the Change of Control itself does not, due to the financial effect of such repurchase on the Issuers. Finally, the Issuers' ability to pay cash to the holders upon a repurchase may be limited by the Issuers' then existing financial resources. There can be no assurance that sufficient funds will be available when necessary to make any required repurchases. See "Risk Factors—Risks Related to Our Indebtedness and the Notes—We may not be able to repurchase the notes upon a change of control."

The definition of Change of Control includes a phrase relating to the sale, lease or transfer of "all or substantially all" the assets of Holdings and its Subsidiaries taken as a whole. Although there is a developing body of case law interpreting the phrase "substantially all," under New York law, which governs the indenture, there is no precise established definition of the phrase under applicable law. Accordingly, the ability of a holder of notes to require the Issuers to repurchase such notes as a result of a sale, lease or transfer of less than all of the assets of Holdings and its Subsidiaries taken as a whole to another Person or group may be uncertain.

The provisions under the indenture relating to the Issuers' obligation to make an offer to repurchase the notes as a result of a Change of Control may be waived or modified with the written consent of the holders of a majority in principal amount of the notes.

Certain Covenants

Set forth below are summaries of certain covenants contained in the indenture. If on any date following the Issue Date, (i) the notes have Investment Grade Ratings from both Rating Agencies, and (ii) no Default has occurred and is continuing under the indenture then, beginning on that day (the occurrence of the events described in the foregoing clauses (i) and (ii) being collectively referred to as a "Covenant Suspension Event"), the covenants specifically listed under the following captions in this "Description of Exchange Notes" section of this prospectus will not be applicable to the notes (collectively, the "Suspended Covenants"):

(1): "—Limitation on Incurrence of Indebtedness and Issuance of Disqualified Stock and Preferred Stock";
(2): "—Limitation on Restricted Payments";
(3): "—Dividend and Other Payment Restrictions Affecting Subsidiaries";
(4): "—Asset Sales";
(5): "—Transactions with Affiliates";
(6): clause (4) of the first paragraph of "—Merger, Amalgamation, Consolidation or Sale of All or Substantially All Assets"; and
(7): "—Future Subsidiary Guarantors."

If and while Holdings and its Restricted Subsidiaries are not subject to the Suspended Covenants, the notes will be entitled to substantially less covenant protection. In the event that Holdings and its Restricted Subsidiaries are not subject to the Suspended Covenants under the indenture for any period of time as a result of the foregoing, and on any subsequent date (the "Reversion Date") one or both of the Rating Agencies withdraw their Investment Grade Rating or downgrade the rating assigned to the notes below an Investment Grade Rating, then Holdings and its Restricted Subsidiaries will thereafter again be subject to the Suspended Covenants under the indenture with respect to future events. The

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period of time between the Covenant Suspension Event and the Reversion Date is referred to in this description as the "Suspension Period." The Issuers will provide the Trustee with written notice of each Covenant Suspension Event or Reversion Date within five Business Days of the occurrence thereof. The Trustee will have no duty to monitor or provide notice to the holders of notes of any Covenant Suspension Event or Reversion Date.

On each Reversion Date, all Indebtedness Incurred, or Disqualified Stock or Preferred Stock issued, during the Suspension Period will be classified as having been Incurred or issued pursuant to the first paragraph of "—Limitation on Incurrence of Indebtedness and Issuance of Disqualified Stock and Preferred Stock" below or one of the clauses set forth in the second paragraph of "—Limitation on Incurrence of Indebtedness and Issuance of Disqualified Stock and Preferred Stock" below (to the extent such Indebtedness or Disqualified Stock or Preferred Stock would be permitted to be Incurred or issued thereunder as of the Reversion Date and after giving effect to Indebtedness Incurred or issued prior to the Suspension Period and outstanding on the Reversion Date). To the extent such Indebtedness or Disqualified Stock or Preferred Stock would not be so permitted to be Incurred or issued pursuant to the first or second paragraph of "—Limitation on Incurrence of Indebtedness and Issuance of Disqualified Stock and Preferred Stock," such Indebtedness or Disqualified Stock or Preferred Stock will be deemed to have been outstanding on the Issue Date, so that it is classified as permitted under clause (c) of the second paragraph under "—Limitation on Incurrence of Indebtedness and Issuance of Disqualified Stock and Preferred Stock." Calculations made after the Reversion Date of the amount available to be made as Restricted Payments under "—Limitation on Restricted Payments" will be made as though the covenant described under "—Limitation on Restricted Payments" had been in effect since the Issue Date and prior to, but not during, the Suspension Period. Accordingly, Restricted Payments made during the Suspension Period will not reduce the amount available to be made as Restricted Payments under the first paragraph of "—Limitation on Restricted Payments." As described above, however, no Default or Event of Default will be deemed to have occurred on the Reversion Date as a result of any actions taken by Holdings or its Restricted Subsidiaries during the Suspension Period. Within 30 days of such Reversion Date, the Issuers must comply with the terms of the covenant described under "—Certain Covenants—Future Subsidiary Guarantors."

For purposes of the "—Asset Sales" covenant, on the Reversion Date, the unutilized Excess Proceeds amount will be reset to zero.

There can be no assurance that the notes will ever achieve or maintain Investment Grade Ratings.

Limitation on Incurrence of Indebtedness and Issuance of Disqualified Stock and Preferred Stock

The indenture provides that:

(1): Holdings will not, and will not permit any of the Restricted Subsidiaries to, directly or indirectly, Incur any Indebtedness (including Acquired Indebtedness) or issue any shares of Disqualified Stock; and
(2): Holdings will not permit any of the Restricted Subsidiaries (other than a Subsidiary Guarantor) to issue any shares of Preferred Stock;

provided,however, that Holdings and any Subsidiary Guarantor may Incur Indebtedness (including Acquired Indebtedness) or issue shares of Disqualified Stock, and any Restricted Subsidiary of Holdings that is not a Subsidiary Guarantor may Incur Indebtedness (including Acquired Indebtedness), issue shares of Disqualified Stock or issue shares of Preferred Stock, in each case if the Fixed Charge Coverage Ratio of Holdings for the most recently ended four full fiscal quarters for which internal financial statements are available immediately preceding the date on which such additional Indebtedness is Incurred or such Disqualified Stock or Preferred Stock is issued would have

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been at least 2.00 to 1.00 determined on apro forma basis (including apro forma application of the net proceeds therefrom), as if the additional Indebtedness had been Incurred, or the Disqualified Stock or Preferred Stock had been issued, as the case may be, and the application of proceeds therefrom had occurred at the beginning of such four-quarter period;provided,further, that any Restricted Subsidiary that is not a Subsidiary Guarantor may not incur Indebtedness or issue shares of Disqualified Stock or Preferred Stock in excess of an amount, together with any Refinancing Indebtedness thereof pursuant to clause (o) below, equal to, after giving pro forma effect to such incurrence or issuance (including pro forma effect to the application of the net proceeds therefrom), the greater of $150.0 million and 2% of Adjusted Consolidated Net Tangible Assets of Holdings and the Restricted Subsidiaries at the time of Incurrence (plus, in the case of any Refinancing Indebtedness, the Additional Refinancing Amount).

The foregoing limitations will not apply to:

(a): the Incurrence by Holdings or any Restricted Subsidiary of Indebtedness (including under any Credit Agreement and the issuance and creation of letters of credit and bankers' acceptances thereunder) up to an aggregate principal amount outstanding at the time of Incurrence that, when aggregated with the principal amount of all other Indebtedness then outstanding and Incurred pursuant to this clause (a), together with any Refinancing Indebtedness in respect thereof Incurred pursuant to clause (o) below, does not exceed the greatest of (1) $3.0 billion, (2) the sum of (x) $500.0 million and (y) 30% of Adjusted Consolidated Net Tangible Assets of Holdings and the Restricted Subsidiaries at the time of Incurrence and (3) the Borrowing Base at the time of Incurrence (plus, in the case of any Refinancing Indebtedness, the Additional Refinancing Amount);
(b): the Incurrence by the Issuers and the Subsidiary Guarantors of Indebtedness represented by (1) the notes and the Subsidiary Guarantees, as applicable (not including any additional notes but including exchange notes and related guarantees thereof) and (2) Indebtedness, including in respect of the Secured Notes and the Term Loan Facility (including any guarantees thereof), in an aggregate principal amount for this clause (b)(2) outstanding at any time that, together with any Refinancing Indebtedness in respect thereof Incurred pursuant to clause (o) below, does not exceed $1,500 million (plus, in the case of any Refinancing Indebtedness, the Additional Refinancing Amount);
(c): Indebtedness existing on the Issue Date (other than Indebtedness described in clauses (a) and (b)), including the Existing Senior Notes and any guarantee thereof;
(d): Indebtedness (including Capitalized Lease Obligations) Incurred by Holdings or any Restricted Subsidiary, Disqualified Stock issued by Holdings or any Restricted Subsidiary and Preferred Stock issued by any Restricted Subsidiary to finance (whether prior to or within 270 days after) the acquisition, lease, construction, repair, replacement or improvement of property (real or personal) or equipment (whether through the direct purchase of assets or the Capital Stock of any Person owning such assets) in an aggregate principal amount that, when aggregated with the principal amount or liquidation preference of all other Indebtedness, Disqualified Stock or Preferred Stock then outstanding and Incurred pursuant to this clause (d), together with any Refinancing Indebtedness in respect thereof Incurred pursuant to clause (o) below, does not exceed the greater of $350.0 million and 5% of Adjusted Consolidated Net Tangible Assets at the time of Incurrence (plus, in the case of any Refinancing Indebtedness, the Additional Refinancing Amount);
(e): Indebtedness Incurred by Holdings or any Restricted Subsidiary constituting reimbursement obligations with respect to letters of credit and bank guarantees issued in the ordinary course of business, including without limitation letters of credit in respect of workers' compensation claims, health, disability or other benefits to employees or former employees or their families

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or property, casualty or liability insurance or self-insurance, and letters of credit in connection with the maintenance of, or pursuant to the requirements of, environmental or other permits or licenses from governmental authorities, or other Indebtedness with respect to reimbursement type obligations regarding workers' compensation claims;

(f): Indebtedness arising from agreements of Holdings or any Restricted Subsidiary providing for indemnification, adjustment of purchase price or similar obligations, in each case, Incurred in connection with the Transactions, any Investments, any acquisition or disposition of any business, assets or a Subsidiary in accordance with the terms of the indenture, other than guarantees of Indebtedness Incurred by any Person acquiring all or any portion of such business, assets or Subsidiary for the purpose of financing such acquisition;
(g): Indebtedness of Holdings to a Restricted Subsidiary;provided that (except in respect of intercompany current liabilities incurred in the ordinary course of business in connection with the cash management, tax and accounting operations of Holdings and its Subsidiaries) any such Indebtedness owed to a Restricted Subsidiary that is not a Subsidiary Guarantor is subordinated in right of payment to the obligations of the Issuers under the notes;provided,further, that any subsequent issuance or transfer of any Capital Stock or any other event which results in any such Restricted Subsidiary ceasing to be a Restricted Subsidiary or any other subsequent transfer of any such Indebtedness (except to Holdings or another Restricted Subsidiary or any pledge of such Indebtedness constituting a Permitted Lien but not the transfer thereof upon foreclosure) shall be deemed, in each case, to be an Incurrence of such Indebtedness not permitted by this clause (g);
(h): shares of Preferred Stock of a Restricted Subsidiary issued to Holdings or another Restricted Subsidiary;provided that any subsequent issuance or transfer of any Capital Stock or any other event which results in any Restricted Subsidiary that holds such shares of Preferred Stock of another Restricted Subsidiary ceasing to be a Restricted Subsidiary or any other subsequent transfer of any such shares of Preferred Stock (except to Holdings or another Restricted Subsidiary) shall be deemed, in each case, to be an issuance of shares of Preferred Stock not permitted by this clause (h);
(i): Indebtedness of a Restricted Subsidiary to Holdings or another Restricted Subsidiary;provided that if a Subsidiary Guarantor incurs such Indebtedness to a Restricted Subsidiary that is not an Issuer or a Subsidiary Guarantor (except in respect of intercompany current liabilities incurred in the ordinary course of business in connection with the cash management, tax and accounting operations of Holdings and its Subsidiaries), such Indebtedness is subordinated in right of payment to the Subsidiary Guarantee of such Subsidiary Guarantor;provided,further, that any subsequent issuance or transfer of any Capital Stock or any other event which results in any Restricted Subsidiary holding such Indebtedness ceasing to be a Restricted Subsidiary or any other subsequent transfer of any such Indebtedness (except to Holdings or another Restricted Subsidiary or any pledge of such Indebtedness constituting a Permitted Lien but not the transfer thereof upon foreclosure) shall be deemed, in each case, to be an Incurrence of such Indebtedness not permitted by this clause (i);
(j): Hedging Obligations that are not incurred for speculative purposes but (1) for the purpose of fixing or hedging interest rate risk with respect to any Indebtedness that is permitted by the terms of the indenture to be outstanding; (2) for the purpose of fixing or hedging currency exchange rate risk with respect to any currency exchanges; or (3) for the purpose of fixing or hedging commodity price risk with respect to any commodity purchases or sales (including, without limitation, any commodity Hedging Obligation that is intended in good faith, at inception of execution, to hedge or manage any of the risks related to existing and/or

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forecasted Hydrocarbon production (whether or not contracted)) and, in each case, extensions or replacements thereof;

(k): obligations (including reimbursement obligations with respect to letters of credit, bank guarantees, warehouse receipts and similar instruments) in respect of performance, bid, appeal, surety bonds, completion guarantees and similar obligations provided by Holdings or any Restricted Subsidiary in the ordinary course of business or consistent with past practice or industry practice;
(l): Indebtedness or Disqualified Stock of Holdings or Indebtedness, Disqualified Stock or Preferred Stock of any Restricted Subsidiary in an aggregate principal amount or liquidation preference, which when aggregated with the principal amount or liquidation preference of all other Indebtedness, Disqualified Stock and Preferred Stock then outstanding and Incurred pursuant to this clause (l), together with any Refinancing Indebtedness in respect thereof Incurred pursuant to clause (o) below, does not exceed the greater of $500.0 million and 7% of Adjusted Consolidated Net Tangible Assets at the time of Incurrence (plus, in the case of any Refinancing Indebtedness, the Additional Refinancing Amount) (it being understood that any Indebtedness Incurred pursuant to this clause (l) shall cease to be deemed Incurred or outstanding for purposes of this clause (l) but shall be deemed Incurred for purposes of the first paragraph of this covenant from and after the first date on which Holdings, or the Restricted Subsidiary, as the case may be, could have Incurred such Indebtedness under the first paragraph of this covenant without reliance upon this clause (l));
(m): Indebtedness or Disqualified Stock of Holdings or any Restricted Subsidiary and Preferred Stock of any Restricted Subsidiary in an aggregate principal amount or liquidation preference at any time outstanding not greater than 100.0% of (i) the net cash proceeds received by Holdings and its Restricted Subsidiaries since immediately after May 24, 2012 plus (ii) the amount of net cash proceeds received by Holdings in excess of $3,200 million prior to or on May 24, 2012, in each case from the issue or sale of Equity Interests of Holdings or any direct or indirect parent entity of Holdings (which proceeds are contributed to Holdings or its Restricted Subsidiary) or cash contributed to the capital of Holdings (in each case other than proceeds of Disqualified Stock or sales of Equity Interests to, or contributions received from, Holdings or any of its Subsidiaries) to the extent such net cash proceeds or cash have not been applied pursuant to such clauses to make Restricted Payments or to make other Investments, payments or exchanges pursuant to the third paragraph of "—Limitation on Restricted Payments" or to make Permitted Investments (other than Permitted Investments specified in clauses (1) and (3) of the definition thereof);
(n): any guarantee by Holdings or any Restricted Subsidiary of Indebtedness or other obligations of Holdings or any Restricted Subsidiary so long as the Incurrence of such Indebtedness Incurred by Holdings or such Restricted Subsidiary is permitted under the terms of the indenture;provided that (i) if such Indebtedness is by its express terms subordinated in right of payment to the notes or the Subsidiary Guarantee of such Restricted Subsidiary, as applicable, any such guarantee with respect to such Indebtedness shall be subordinated in right of payment to the notes or such Subsidiary Guarantee, as applicable, substantially to the same extent as such Indebtedness is subordinated to the notes or the Subsidiary Guarantee, as applicable and (ii) if such guarantee is of Indebtedness of Holdings, such guarantee is Incurred in accordance with, or not in contravention of, the covenant described under "—Future Subsidiary Guarantors" solely to the extent such covenant is applicable;
(o): the Incurrence by Holdings or any of the Restricted Subsidiaries of Indebtedness or Disqualified Stock or Preferred Stock of a Restricted Subsidiary that serves to refund, refinance or defease any Indebtedness Incurred or Disqualified Stock or Preferred Stock

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issued as permitted under the first paragraph of this covenant and clauses (a)(2), (a)(3), (b), (c), (d), (l), (m), (o), (p) and (t) of this paragraph up to the outstanding principal amount (or, if applicable, the liquidation preference face amount, or the like) or, if greater, committed amount (only to the extent the committed amount could have been Incurred on the date of initial Incurrence) of such Indebtedness or Disqualified Stock or Preferred Stock, in each case at the time such Indebtedness was Incurred or Disqualified Stock or Preferred Stock was issued pursuant to the first paragraph of this covenant or clauses (a)(2), (a)(3), (b), (c), (d), (l), (m), (o), (p) and (t) of this paragraph, or any Indebtedness, Disqualified Stock or Preferred Stock Incurred to so refund or refinance such Indebtedness, Disqualified Stock or Preferred Stock, including any additional Indebtedness, Disqualified Stock or Preferred Stock Incurred to pay premiums (including tender premiums), accrued and unpaid interest, expenses, defeasance costs and fees in connection therewith (subject to the following proviso, "Refinancing Indebtedness") prior to its respective maturity;provided,however, that such Refinancing Indebtedness (other than Refinancing Indebtedness in respect of Indebtedness Incurred pursuant to clauses (a)(2) and (a)(3)):

(1): has a Weighted Average Life to Maturity at the time such Refinancing Indebtedness is Incurred which is not less than the shorter of (x) the remaining Weighted Average Life to Maturity of the Indebtedness, Disqualified Stock or Preferred Stock being refunded, refinanced or defeased and (y) the Weighted Average Life to Maturity that would result if all payments of principal on the Indebtedness, Disqualified Stock and Preferred Stock being refunded or refinanced that were due on or after the date that is one year following the last maturity date of any notes then outstanding were instead due on such date (provided that this subclause (1) will not apply to any refunding or refinancing of any Secured Indebtedness);
(2): to the extent such Refinancing Indebtedness refinances (a) Indebtedness junior to the notes or a Subsidiary Guarantee, as applicable, such Refinancing Indebtedness is junior to the notes or the Subsidiary Guarantee, as applicable, or (b) Disqualified Stock or Preferred Stock, such Refinancing Indebtedness is Disqualified Stock or Preferred Stock; and
(3): shall not include (x) Indebtedness of a Restricted Subsidiary that is not a Subsidiary Guarantor that refinances Indebtedness of Holdings, an Issuer or a Subsidiary Guarantor, or (y) Indebtedness of Holdings or a Restricted Subsidiary that refinances Indebtedness of an Unrestricted Subsidiary;

(p)

Indebtedness, Disqualified Stock or Preferred Stock of (x) Holdings or any Restricted Subsidiary incurred to finance an acquisition or (y) Persons that are acquired by Holdings or any Restricted Subsidiary or merged, consolidated or amalgamated with or into Holdings or any Restricted Subsidiary in accordance with the terms of the indenture;provided that after giving effect to such acquisition or merger, consolidation or amalgamation, either:

(1): Holdings would be permitted to incur at least $1.00 of additional Indebtedness pursuant to the Fixed Charge Coverage Ratio test set forth in the first paragraph of this covenant; or
(2): the Fixed Charge Coverage Ratio of Holdings would be greater than immediately prior to such acquisition or merger, consolidation or amalgamation;

(q)

Indebtedness Incurred by a Receivables Subsidiary in a Qualified Receivables Financing that is not recourse to Holdings or any Restricted Subsidiary other than a Receivables Subsidiary (except for Standard Securitization Undertakings);

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(r): Indebtedness arising from the honoring by a bank or other financial institution of a check, draft or similar instrument drawn against insufficient funds in the ordinary course of business;provided that such Indebtedness is extinguished within five Business Days of its Incurrence;
(s): Indebtedness of Holdings or any Restricted Subsidiary supported by a letter of credit or bank guarantee issued pursuant to Bank Indebtedness, in a principal amount not in excess of the stated amount of such letter of credit;
(t): Indebtedness of Restricted Subsidiaries that are not Subsidiary Guarantors and Indebtedness Incurred on behalf of, or representing guarantees of Indebtedness of, joint ventures of Holdings and any Restricted Subsidiary;provided, however, that the aggregate principal amount of Indebtedness Incurred under this clause (t), when aggregated with the principal amount of all other Indebtedness then outstanding and Incurred pursuant to this clause (t), together with any Refinancing Indebtedness in respect thereof Incurred pursuant to clause (o) above, does not exceed the greater of $150.0 million and 2% of Adjusted Consolidated Net Tangible Assets at the time of Incurrence (plus in the case of any Refinancing Indebtedness, the Additional Refinancing Amount) (it being understood that any Indebtedness incurred pursuant to this clause (t) shall cease to be deemed incurred or outstanding for purposes of this clause (t) but shall be deemed incurred for the purposes of the first paragraph of this covenant from and after the first date on which such Restricted Subsidiary could have incurred such Indebtedness under the first paragraph of this covenant without reliance upon this clause (t));
(u): Indebtedness of Holdings or any Restricted Subsidiary consisting of (1) the financing of insurance premiums or (2) take-or-pay obligations contained in supply arrangements, in each case, in the ordinary course of business; and
(v): Indebtedness consisting of Indebtedness issued by Holdings or a Restricted Subsidiary to current or former officers, directors, managers and employees thereof or any direct or indirect parent thereof, their respective estates, spouses or former spouses, in each case to finance the purchase or redemption of Equity Interests of Holdings or any direct or indirect parent of Holdings to the extent described in clause (4) of the third paragraph of the covenant described under "—Limitation on Restricted Payments".

For purposes of determining compliance with this covenant:

(1): in the event that an item of Indebtedness, Disqualified Stock or Preferred Stock (or any portion thereof) meets the criteria of more than one of the categories of permitted Indebtedness described in clauses (a) through (v) above or is entitled to be Incurred pursuant to the first paragraph of this covenant, then Holdings shall, in its sole discretion, classify or reclassify, or later divide, classify or reclassify (as if Incurred at such later time), such item of Indebtedness, Disqualified Stock or Preferred Stock (or any portion thereof) in any manner that complies with this covenant;provided, that (i) only Indebtedness outstanding under the Credit Agreement in excess of $2,000 million may be classified or reclassified as not incurred under clause (a) of the second paragraph of this covenant and (ii) the Secured Notes and the Term Loan Facility (including any guarantees thereof) outstanding on May 24, 2012, shall at all times be treated as incurred pursuant to clause (b) of the second paragraph of this covenant;
(2): at the time of incurrence, Holdings will be entitled to divide and classify an item of Indebtedness in more than one of the types of Indebtedness described in the first and second paragraphs above (or any portion thereof) without givingpro forma effect to the Indebtedness Incurred pursuant to any other clause or paragraph above (or any portion thereof) when

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calculating the amount of Indebtedness that may be Incurred pursuant to any such clause or paragraph (or any portion thereof);

(3): in connection with the Incurrence or issuance, as applicable, of any Indebtedness, Disqualified Stock or Preferred Stock, the Issuer or applicable Restricted Subsidiary may elect at any time prior to the actual Incurrence or issuance of such Indebtedness, Disqualified Stock or Preferred Stock, as applicable, to treat all or any portion of the commitments relating to such Indebtedness, Disqualified Stock or Preferred Stock as being Incurred or issued on the date of such election, and any related subsequent actual Incurrence or issuance of such Indebtedness, Disqualified Stock or Preferred Stock will be deemed for all purposes under the indenture to have been Incurred on the date of such election;
(4): if any Indebtedness denominated in U.S. dollars is exchanged, converted or refinanced into Indebtedness denominated in a foreign currency, then (in connection with such exchange, conversion or refinancing, and thereafter), the U.S. dollar amount limitations set forth in any of clauses (a) through (v) above with respect to such exchange, conversion or refinancing shall be deemed to be the amount of such foreign currency, as applicable, into which such Indebtedness has been exchanged, converted or refinanced at the time of such exchange, conversion or refinancing; and
(5): if any Indebtedness denominated in a foreign currency is exchanged, converted or refinanced into Indebtedness denominated in U.S. dollars, then (in connection with such exchange, conversion or refinancing, and thereafter), the U.S. dollar amount limitations set forth in any of clauses (a) through (v) above with respect to such exchange, conversion or refinancing shall be deemed to be the amount of U.S. dollars into which such Indebtedness has been exchanged, converted or refinanced at the time of such exchange, conversion or refinancing.

Accrual of interest, the accretion of accreted value, the payment of interest or dividends in the form of additional Indebtedness, Disqualified Stock or Preferred Stock, as applicable, amortization of original issue discount, the accretion of liquidation preference and increases in the amount of Indebtedness outstanding solely as a result of fluctuations in the exchange rate of currencies will not be deemed to be an Incurrence of Indebtedness, Disqualified Stock or Preferred Stock for purposes of this covenant. Guarantees of, or obligations in respect of letters of credit relating to, Indebtedness which is otherwise included in the determination of a particular amount of Indebtedness shall not be included in the determination of such amount of Indebtedness;provided that the Incurrence of the Indebtedness represented by such guarantee or letter of credit, as the case may be, was in compliance with this covenant.

For purposes of determining compliance with any U.S. dollar-denominated restriction on the Incurrence of Indebtedness other than as provided in clauses (3) and (4) above, the U.S. dollar-equivalent principal amount of Indebtedness denominated in a foreign currency shall be calculated based on the relevant currency exchange rate in effect on the date such Indebtedness was Incurred, in the case of term debt, or first committed or first Incurred (whichever yields the lower U.S. dollar equivalent), in the case of revolving credit debt.

Notwithstanding any other provision of this covenant, the maximum amount of Indebtedness that Holdings and its Restricted Subsidiaries may Incur pursuant to this covenant shall not be deemed to be exceeded, with respect to any outstanding Indebtedness, solely as a result of fluctuations in the exchange rate of currencies.

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Limitation on Restricted Payments

The indenture provides that Holdings will not, and will not permit any of the Restricted Subsidiaries to, directly or indirectly:

(1): declare or pay any dividend or make any distribution on account of any of Holdings' or any of the Restricted Subsidiaries' Equity Interests, including any payment made in connection with any merger, amalgamation or consolidation involving Holdings (other than (A) dividends or distributions payable solely in Equity Interests (other than Disqualified Stock) of Holdings; or (B) dividends or distributions by a Restricted Subsidiary so long as, in the case of any dividend or distribution payable on or in respect of any class or series of securities issued by a Restricted Subsidiary that is not a Wholly Owned Restricted Subsidiary, Holdings or a Restricted Subsidiary receives at least its pro rata share of such dividend or distribution in accordance with its Equity Interests in such class or series of securities);
(2): purchase or otherwise acquire or retire for value any Equity Interests of Holdings or any direct or indirect parent of Holdings;
(3): make any principal payment on, or redeem, repurchase, defease or otherwise acquire or retire for value, in each case prior to any scheduled repayment or scheduled maturity, any Subordinated Indebtedness of an Issuer or any Subsidiary Guarantor (other than the payment, redemption, repurchase, defeasance, acquisition or retirement of (A) Subordinated Indebtedness in anticipation of satisfying a sinking fund obligation, principal installment or final maturity, in each case due within one year of the date of such payment, redemption, repurchase, defeasance, acquisition or retirement and (B) Indebtedness permitted under clauses (g) and (i) of the second paragraph of the covenant described under "—Limitation on Incurrence of Indebtedness and Issuance of Disqualified Stock and Preferred Stock"; or
(4): make any Restricted Investment

(all such payments and other actions set forth in clauses (1) through (4) above being collectively referred to as "Restricted Payments"), unless, at the time of such Restricted Payment:

(a): no Default shall have occurred and be continuing or would occur as a consequence thereof;
(b): immediately after giving effect to such transaction on apro forma basis, Holdings could Incur $1.00 of additional Indebtedness under the provisions of the first paragraph of the covenant described under "—Limitation on Incurrence of Indebtedness and Issuance of Disqualified Stock and Preferred Stock"; and
(c): such Restricted Payment, together with the aggregate amount of all other Restricted Payments made by Holdings and the Restricted Subsidiaries after the Issue Date (including Restricted Payments permitted by clauses (1), (2) (with respect to the payment of dividends on Refunding Capital Stock (as defined below) pursuant to clause (c) thereof), (6)(c), (8) and (13)(b) of the next succeeding paragraph, but excluding all other Restricted Payments permitted by the next succeeding paragraph), is less than the amount equal to the Cumulative Credit.

"Cumulative Credit" means the sum of (without duplication):

(1): 50% of the Consolidated Net Income of Holdings for the period from July 1, 2012 to the end of Holdings' most recently ended fiscal quarter for which internal financial statements are available at the time of such Restricted Payment (taken as one accounting period, the "Reference Period") (or in case such Consolidated Net Income for such period is a deficit, minus 100% of such deficit),plus

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(2)

100% of (i) the aggregate net proceeds, including cash and the Fair Market Value (as determined in good faith by Holdings) of property other than cash, received by Holdings after May 24, 2012 plus (ii) the aggregate net proceeds, including cash and the Fair Market Value (as determined in good faith by Holdings) of property other than cash, received by Holdings in excess of $3,200 million prior to or on May 24, 2012 (in each case other than net proceeds to the extent such net proceeds have been used to incur Indebtedness, Disqualified Stock, or Preferred Stock pursuant to clause (m) of the second paragraph of the covenant described under "—Limitation on Incurrence of Indebtedness and Issuance of Disqualified Stock and Preferred Stock") from the issue or sale of Equity Interests of Holdings or any direct or indirect parent entity of Holdings (excluding Refunding Capital Stock (as defined below), Designated Preferred Stock, Excluded Contributions, and Disqualified Stock), including Equity Interests issued upon exercise of warrants or options (other than an issuance or sale to Holdings or a Restricted Subsidiary),plus

(3)

100% of (i) the aggregate amount of contributions to the capital of Holdings received in cash and the Fair Market Value (as determined in good faith by Holdings) of property other than cash after May 24, 2012 plus (ii) the aggregate amount of contributions to the capital of Holdings received in cash and the Fair Market Value (as determined in good faith by Holdings) of property other than cash, in excess of $3,200 million prior to or on May 24, 2012 (in each case other than Excluded Contributions, Refunding Capital Stock, Designated Preferred Stock, and Disqualified Stock and other than contributions to the extent such contributions have been used to incur Indebtedness, Disqualified Stock, or Preferred Stock pursuant to clause (m) of the second paragraph of the covenant described under "—Limitation on Incurrence of Indebtedness and Issuance of Disqualified Stock and Preferred Stock"),plus

(4)

100% of the principal amount of any Indebtedness, or the liquidation preference or maximum fixed repurchase price, as the case may be, of any Disqualified Stock of Holdings or any Restricted Subsidiary issued after May 24, 2012 (other than Indebtedness or Disqualified Stock issued to a Restricted Subsidiary) which has been converted into or exchanged for Equity Interests in Holdings (other than Disqualified Stock) or any direct or indirect parent of Holdings (provided in the case of any such parent, such Indebtedness or Disqualified Stock is retired or extinguished),plus

(5)

100% of the aggregate amount received by Holdings or any Restricted Subsidiary in cash and the Fair Market Value (as determined in good faith by Holdings) of property other than cash received by Holdings or any Restricted Subsidiary from:

(A): the sale or other disposition (other than to Holdings or a Restricted Subsidiary) of Restricted Investments made by Holdings and the Restricted Subsidiaries and from repurchases and redemptions of such Restricted Investments from Holdings and the Restricted Subsidiaries by any Person (other than Holdings or any Restricted Subsidiary) and from repayments of loans or advances, and releases of guarantees, which constituted Restricted Investments (other than in each case to the extent that the Restricted Investment was made pursuant to clause (7) of the succeeding paragraph),
(B): the sale (other than to Holdings or a Restricted Subsidiary) of the Capital Stock of an Unrestricted Subsidiary, or
(C): a distribution or dividend from an Unrestricted Subsidiary,plus

(6)

in the event any Unrestricted Subsidiary has been redesignated as a Restricted Subsidiary or has been merged, consolidated or amalgamated with or into, or transfers or conveys its assets to, or is liquidated into, Holdings or a Restricted Subsidiary, the Fair Market Value (as

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determined in good faith by Holdings) of the Investment of Holdings or the Restricted Subsidiaries in such Unrestricted Subsidiary (which, if the fair market value of such Investment shall exceed $25.0 million, shall be determined by the Board of Directors of Holdings) at the time of such redesignation, combination or transfer (or of the assets transferred or conveyed, as applicable) (other than in each case to the extent that the designation of such Subsidiary as an Unrestricted Subsidiary was made pursuant to clause (7) of the succeeding paragraph or constituted a Permitted Investment).

The foregoing provisions will not prohibit:

(1)

the payment of any dividend or distribution or the consummation of any irrevocable redemption within 60 days after the date of declaration thereof, if at the date of declaration or the giving notice of such irrevocable redemption, as applicable, such payment would have complied with the provisions of the indenture;

(2)

(a) the redemption, repurchase, retirement or other acquisition of any Equity Interests ("Retired Capital Stock") or Subordinated Indebtedness of Holdings, any direct or indirect parent of Holdings or any Subsidiary Guarantor in exchange for, or out of the proceeds of, the substantially concurrent sale of, Equity Interests of Holdings or any direct or indirect parent of Holdings or contributions to the equity capital of Holdings (other than any Disqualified Stock or any Equity Interests sold to a Subsidiary of Holdings) (collectively, including any such contributions, "Refunding Capital Stock"),

(b): the declaration and payment of dividends on the Retired Capital Stock out of the proceeds of the substantially concurrent sale (other than to a Subsidiary of Holdings) of Refunding Capital Stock, and
(c): if immediately prior to the retirement of Retired Capital Stock, the declaration and payment of dividends thereon was permitted under clause (6) of this paragraph and not made pursuant to clause (2)(b), the declaration and payment of dividends on the Refunding Capital Stock (other than Refunding Capital Stock the proceeds of which were used to redeem, repurchase, retire or otherwise acquire any Equity Interests of any direct or indirect parent of Holdings) in an aggregate amount per year no greater than the aggregate amount of dividends per annum that were declarable and payable on such Retired Capital Stock immediately prior to such retirement;

(3)

the redemption, repurchase, defeasance, or other acquisition or retirement of Subordinated Indebtedness of an Issuer or any Subsidiary Guarantor made by exchange for, or out of the proceeds of the substantially concurrent sale of, new Indebtedness of an Issuer or a Subsidiary Guarantor, which is Incurred in accordance with the covenant described under "—Limitation on Incurrence of Indebtedness and Issuance of Disqualified Stock and Preferred Stock" so long as:

(a): the principal amount (or accreted value, if applicable) of such new Indebtedness does not exceed the principal amount (or accreted value, if applicable), plus any accrued and unpaid interest, of the Subordinated Indebtedness being so redeemed, repurchased, defeased, acquired or retired for value (plus the amount of any premium required to be paid under the terms of the instrument governing the Subordinated Indebtedness being so redeemed, repurchased, acquired or retired, any tender premiums, plus any defeasance costs, fees and expenses incurred in connection therewith),
(b): such Indebtedness is subordinated to the notes or the related Subsidiary Guarantee, as the case may be, at least to the same extent as such Subordinated Indebtedness so purchased, exchanged, redeemed, repurchased, defeased, acquired or retired for value,

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(c): such Indebtedness has a final scheduled maturity date equal to or later than the earlier of (x) the final scheduled maturity date of the Subordinated Indebtedness being so redeemed, repurchased, acquired or retired and (y) 91 days following the last maturity date of any notes then outstanding, and
(d): such Indebtedness has a Weighted Average Life to Maturity at the time Incurred which is not less than the shorter of (x) the remaining Weighted Average Life to Maturity of the Subordinated Indebtedness being so redeemed, repurchased, defeased, acquired or retired and (y) the Weighted Average Life to Maturity that would result if all payments of principal on the Subordinated Indebtedness being redeemed, repurchased, defeased, acquired or retired that were due on or after the date that is one year following the last maturity date of any notes then outstanding were instead due on such date;

(4)

a Restricted Payment to pay for the repurchase, retirement or other acquisition for value of Equity Interests of Holdings or any direct or indirect parent of Holdings held by any future, present or former employee, director, officer, manager or consultant of Holdings or any direct or indirect parent of Holdings or any Subsidiary of Holdings pursuant to any management equity plan or stock option plan or any other management or employee benefit plan or other agreement or arrangement;provided,however, that the aggregate Restricted Payments made under this clause (4) do not exceed $50.0 million in any calendar year (which shall increase to $100.0 million subsequent to the consummation of an underwritten public Equity Offering of common stock), with unused amounts in any calendar year being permitted to be carried over to succeeding calendar years subject to a maximum of $75.0 million in any calendar year (which shall increase to $150.0 million subsequent to the consummation of an underwritten public Equity Offering);provided,further,however, that such amount in any calendar year may be increased by an amount not to exceed:

(a): the cash proceeds received by Holdings or any of the Restricted Subsidiaries from the sale of Equity Interests (other than Disqualified Stock) of Holdings or any direct or indirect parent of Holdings (to the extent contributed to Holdings) to employees, directors, officers, managers or consultants of Holdings and the Restricted Subsidiaries or any direct or indirect parent of Holdings that occurs after the Issue Date (provided that the amount of such cash proceeds utilized for any such repurchase, retirement, other acquisition or dividend will not increase the amount available for Restricted Payments under clause (3) of the first paragraph under "—Limitation on Restricted Payments"),plus
(b): the cash proceeds of key man life insurance policies received by Holdings or any direct or indirect parent of Holdings (to the extent contributed to Holdings) or the Restricted Subsidiaries after the Issue Date;

provided that Holdings may elect to apply all or any portion of the aggregate increase contemplated by clauses (a) and (b) above in any calendar year; andprovided, further, that cancellation of Indebtedness owing to Holdings or any Restricted Subsidiary from any present or former employees, directors, managers, officers or consultants of Holdings, any Restricted Subsidiary or the direct or indirect parents of Holdings in connection with a repurchase of Equity Interests of Holdings or any of its direct or indirect parents will not be deemed to constitute a Restricted Payment for purposes of this covenant or any other provision of the indenture;

(5): the declaration and payment of dividends or distributions to holders of any class or series of Disqualified Stock of Holdings or any Restricted Subsidiary issued or incurred in accordance with the covenant described under "—Limitation on Incurrence of Indebtedness and Issuance of Disqualified Stock and Preferred Stock";

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(6)

(a) the declaration and payment of dividends or distributions to holders of any class or series of Designated Preferred Stock (other than Disqualified Stock) issued after the Issue Date;

(b): a Restricted Payment to any direct or indirect parent of Holdings, the proceeds of which will be used to fund the payment of dividends to holders of any class or series of Designated Preferred Stock (other than Disqualified Stock) of any direct or indirect parent of Holdings issued after the Issue Date;provided that the aggregate amount of dividends declared and paid pursuant to this clause (b) does not exceed the net cash proceeds actually received by Holdings from any such sale of Designated Preferred Stock (other than Disqualified Stock) issued after the Issue Date; and
(c): the declaration and payment of dividends on Refunding Capital Stock that is Preferred Stock in excess of the dividends declarable and payable thereon pursuant to clause (2) of this paragraph;

provided,however, in the case of each of (a) and (c) above of this clause (6), that for the most recently ended four full fiscal quarters for which internal financial statements are available immediately preceding the date of issuance of such Designated Preferred Stock, after giving effect to such issuance (and the payment of dividends or distributions) on apro forma basis (including a pro forma application of the net proceeds therefrom), Holdings would have had a Fixed Charge Coverage Ratio of at least 2.00 to 1.00;

(7): Investments in Unrestricted Subsidiaries having an aggregate Fair Market Value (as determined in good faith by Holdings), taken together with all other Investments made pursuant to this clause (7) that are at that time outstanding, not to exceed the greater of $175.0 million and 2.5% of Adjusted Consolidated Net Tangible Assets at the time of such Investment,plus an amount equal to any returns (including dividends, interest, distributions, returns of principal, profits on sale, repayments, income and similar amounts) actually received in respect of any such Investment made pursuant to this clause (7) (with the Fair Market Value of each Investment being measured at the time made and without giving effect to subsequent changes in value);provided,however, that if any Investment pursuant to this clause (7) is made in any Person that is not an Issuer or a Restricted Subsidiary at the date of the making of such Investment and such Person becomes an Issuer or a Restricted Subsidiary after such date, such Investment shall thereafter be deemed to have been made pursuant to clause (1) of the definition of Permitted Investments and shall cease to have been made pursuant to this clause (7) for so long as such Person continues to be an Issuer or a Restricted Subsidiary;
(8): the payment of dividends after a public offering of Capital Stock of Holdings or any direct or indirect parent of Holdings on Holdings' Capital Stock (or a Restricted Payment to any such direct or indirect parent of Holdings to fund the payment by such direct or indirect parent of Holdings of dividends on such entity's Capital Stock) of up to 6% per annum of the total market capitalization of Holdings or any such direct or indirect parent of Holdings as of the date of such public offering, other than public offerings with respect to Holdings' (or such direct or indirect parent's) Capital Stock registered on Form S-4 or Form S-8 and other than any public sale constituting an Excluded Contribution;
(9): Restricted Payments in an aggregate amount not to exceed the aggregate amount of Excluded Contributions;
(10): other Restricted Payments in an aggregate amount, when taken together with all other Restricted Payments made pursuant to this clause (10) that are at that time outstanding, not to exceed the greater of $225.0 million and 3% of Adjusted Consolidated Net Tangible Assets

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at the time of such Restricted Payment,plus, in the case of Restricted Payments constituting Investments made pursuant to this clause (10), an amount equal to any returns (including dividends, interest, distributions, returns of principal, profits on sale, repayments, income and similar amounts) actually received in respect of any such Restricted Payments constituting Investments;

(11)

the distribution, as a dividend or otherwise, of shares of Capital Stock of, or Indebtedness owed to Holdings or a Restricted Subsidiary by, Unrestricted Subsidiaries;

(12)

(a) with respect to any taxable period for which Holdings and/or any of its Subsidiaries are members of a consolidated, combined, affiliated, unitary or similar income tax group for U.S. federal and/or applicable state or local income tax purposes of which a direct or indirect parent of Holdings is the common parent, or for which Holdings is a partnership or disregarded entity for U.S. federal income tax purposes that is wholly-owned (directly or indirectly) by a C corporation for U.S. federal and/or applicable state or local income tax purposes, distributions to any direct or indirect parent of Holdings in an amount not to exceed the amount of any U.S. federal, state and/or local income taxes that Holdings and/or its Subsidiaries, as applicable, would have paid for such taxable period had Holdings and/or its Subsidiaries, as applicable, been a stand-alone corporate taxpayer or a stand-alone corporate group, and (b) with respect to any taxable period ending after the Issue Date for which Holdings is a partnership or disregarded entity for U.S. federal income tax purposes (other than a partnership or disregarded entity described in clause (a)), distributions to any direct or indirect parent of Holdings in an amount necessary to permit such direct or indirect parent of Holdings to make a pro rata distribution to its owners such that each direct or indirect owner of Holdings receives an amount from such pro rata distribution sufficient to enable such owner to pay its U.S. federal, state and/or local income taxes (as applicable) attributable to its direct or indirect ownership of Holdings and its Subsidiaries with respect to such taxable period (assuming that each owner is subject to tax at the highest combined marginal federal, state, and/or local income tax rate applicable to any owner for such taxable period and taking into account the deductibility of state and local income taxes for U.S. federal income tax purposes (and any limitations thereon), the alternative minimum tax, any cumulative net taxable loss of Holdings for prior taxable periods ending after the Issue Date to the extent such loss is of a character that would allow such loss to be available to reduce taxes in the current taxable period (taking into account any limitations on the utilization of such loss to reduce such taxes and assuming such loss had not already been utilized) and the character (e.g., long-term or short-term capital gain or ordinary or exempt) of the applicable income);

(13)

any Restricted Payment, if applicable:

(a): in amounts required for any direct or indirect parent of Holdings to pay fees and expenses (including franchise or similar taxes) required to maintain its corporate existence, customary salary, bonus and other benefits payable to, and indemnities provided on behalf of, officers and employees of any direct or indirect parent of Holdings and general corporate operating and overhead expenses of any direct or indirect parent of Holdings in each case to the extent such fees and expenses are attributable to the ownership or operation of Holdings, if applicable, and its Subsidiaries;
(b): in amounts required for any direct or indirect parent of Holdings, if applicable, to pay interest and/or principal on Indebtedness the proceeds of which have been contributed to Holdings or any Restricted Subsidiary and that has been guaranteed by, or is otherwise considered Indebtedness of, Holdings Incurred in accordance with the covenant described under "—Limitation on Incurrence of Indebtedness and Issuance of Disqualified Stock and Preferred Stock"; and

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(c): in amounts required for any direct or indirect parent of Holdings to pay fees and expenses related to any unsuccessful equity or debt offering of such parent;

(14): repurchases of Equity Interests deemed to occur upon exercise of stock options or warrants if such Equity Interests represent a portion of the exercise price of such options or warrants;
(15): purchases of receivables pursuant to a Receivables Repurchase Obligation in connection with a Qualified Receivables Financing and the payment or distribution of Receivables Fees;
(16): Restricted Payments by Holdings or any Restricted Subsidiary to allow the payment of cash in lieu of the issuance of fractional shares upon the exercise of options or warrants or upon the conversion or exchange of Capital Stock of any such Person;
(17): the repurchase, redemption or other acquisition or retirement for value of any Subordinated Indebtedness pursuant to the provisions similar to those described under the captions "—Change of Control" and "—Asset Sales";provided that all notes tendered by holders of the notes in connection with a Change of Control or Asset Sale Offer, as applicable, have been repurchased, redeemed or acquired for value;
(18): payments or distributions to dissenting stockholders pursuant to applicable law, pursuant to or in connection with a consolidation, amalgamation, merger or transfer of all or substantially all of the assets of Holdings and the Restricted Subsidiaries, taken as a whole, that complies with the covenant described under "—Merger, Amalgamation, Consolidation or Sale of All or Substantially All Assets";provided that as a result of such consolidation, amalgamation, merger or transfer of assets, Holdings shall have made a Change of Control Offer (if required by the indenture) and that all notes tendered by holders in connection with such Change of Control Offer have been repurchased, redeemed or acquired for value; and
(19): any Restricted Payment used to fund the Transactions and the payment of fees and expenses Incurred in connection with the Transactions or owed by Holdings or any direct or indirect parent of Holdings or Restricted Subsidiaries of Holdings to Affiliates, and any other payments made, including any such payments made to any direct or indirect parent of Holdings to enable it to make payments in connection with the consummation of the Transactions, whether payable on the Issue Date or thereafter, in each case to the extent permitted by the covenant described under "—Transactions with Affiliates";

provided,however, that at the time of, and after giving effect to, any Restricted Payment permitted under clauses (6)(b), (7), (10), (11) and (13)(b), no Default shall have occurred and be continuing or would occur as a consequence thereof;provided,further that any Restricted Payments made with property other than cash shall be calculated using the Fair Market Value (as determined in good faith by Holdings) of such property.

As of the Issue Date, all of the Subsidiaries of Holdings will be Restricted Subsidiaries. Holdings will not permit any Unrestricted Subsidiary to become a Restricted Subsidiary except pursuant to the definition of "Unrestricted Subsidiary." For purposes of designating any Restricted Subsidiary as an Unrestricted Subsidiary, all outstanding Investments by Holdings and the Restricted Subsidiaries (except to the extent repaid) in the Subsidiary so designated will be deemed to be Restricted Payments in an amount determined as set forth in the last sentence of the definition of "Investments." Such designation will only be permitted if a Restricted Payment or Permitted Investment in such amount would be permitted at such time and if such Subsidiary otherwise meets the definition of an Unrestricted Subsidiary.

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Dividend and Other Payment Restrictions Affecting Subsidiaries

The indenture provides that Holdings will not, and will not permit any of the Restricted Subsidiaries to, directly or indirectly, create or otherwise cause or suffer to exist or become effective any consensual encumbrance or consensual restriction on the ability of any Issuer or Restricted Subsidiary to:

(a): (i) pay dividends or make any other distributions to Holdings or any Restricted Subsidiary (1) on its Capital Stock; or (2) with respect to any other interest or participation in, or measured by, its profits; or (ii) pay any Indebtedness owed to Holdings or any Restricted Subsidiary;
(b): make loans or advances to Holdings or any Restricted Subsidiary; or
(c): sell, lease or transfer any of its properties or assets to Holdings or any Restricted Subsidiary;

except in each case for such encumbrances or restrictions existing under or by reason of:

(1): (i) contractual encumbrances or restrictions in effect on the Issue Date, including pursuant to the Existing Senior Notes (including any guarantee thereof), the Secured Notes (including any guarantee thereof) and the Term Loan Facility (including any guarantee thereof) and (ii) contractual encumbrances or restrictions pursuant to the Credit Agreement and the other Credit Agreement Documents and, in each case, any similar contractual encumbrances effected by any amendments, modifications, restatements, renewals, supplements, refundings, replacements or refinancings of such agreements or instruments;
(2): the indenture, the notes (and any exchange notes) or the Guarantees;
(3): applicable law or any applicable rule, regulation or order;
(4): any agreement or other instrument of a Person acquired by Holdings or any Restricted Subsidiary which was in existence at the time of such acquisition (but not created in contemplation thereof or to provide all or any portion of the funds or credit support utilized to consummate such acquisition), which encumbrance or restriction is not applicable to any Person, or the properties or assets of any Person, other than the Person and its Subsidiaries, or the property or assets of the Person and its Subsidiaries, so acquired;
(5): contracts or agreements for the sale of assets, including any restriction with respect to a Restricted Subsidiary imposed pursuant to an agreement entered into for the sale or disposition of the Capital Stock or assets of such Restricted Subsidiary;
(6): Secured Indebtedness otherwise permitted to be Incurred pursuant to the covenants described under "—Limitation on Incurrence of Indebtedness and Issuance of Disqualified Stock and Preferred Stock" and "—Liens" that limit the right of the debtor to dispose of the assets securing such Indebtedness;
(7): restrictions on cash or other deposits or net worth imposed by customers under contracts entered into in the ordinary course of business;
(8): customary provisions in joint venture agreements and other similar agreements entered into in the ordinary course of business;
(9): purchase money obligations for property acquired and Capitalized Lease Obligations in the ordinary course of business that impose restrictions of the nature discussed in clause (c) above on the property so acquired;
(10): customary provisions contained in leases, licenses and other similar agreements entered into in the ordinary course of business;

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(11): in the case of clause (c) of the first paragraph of this covenant, any encumbrance or restriction that restricts in a customary manner the subletting, assignment or transfer of any property or asset that is subject to a lease (including leases governing leasehold interests or Farm-In Agreements or Farm-Out Agreements relating to leasehold interests in Oil and Gas Properties), license or similar contract, or the assignment or transfer of any such lease (including leases governing leasehold interests or Farm-In Agreements or Farm-Out Agreements relating to leasehold interests in Oil and Gas Properties), license (including, without limitation, licenses of intellectual property) or other contracts;
(12): any encumbrance or restriction of a Receivables Subsidiary effected in connection with a Qualified Receivables Financing;provided,however, that such restrictions apply only to such Receivables Subsidiary;
(13): other Indebtedness, Disqualified Stock or Preferred Stock (a) of Holdings or any Restricted Subsidiary that is a Subsidiary Guarantor or a Foreign Subsidiary or (b) of any Restricted Subsidiary that is not a Subsidiary Guarantor or a Foreign Subsidiary so long as such encumbrances and restrictions contained in any agreement or instrument will not materially affect the Issuers' ability to make anticipated principal or interest payments on the notes (as determined in good faith by Holdings),provided that in the case of each of clauses (a) and (b), such Indebtedness, Disqualified Stock or Preferred Stock is permitted to be Incurred subsequent to the Issue Date by the covenant described under "—Limitation on Incurrence of Indebtedness and Issuance of Disqualified Stock and Preferred Stock";
(14): any Restricted Investment not prohibited by the covenant described under "—Limitation on Restricted Payments" and any Permitted Investment;
(15): any customary encumbrances or restrictions imposed pursuant to any agreement of the type described in the definition of "Permitted Business Investment"; or
(16): any encumbrances or restrictions of the type referred to in clauses (a), (b) or (c) above imposed by any amendments, modifications, restatements, renewals, increases, supplements, refundings, replacements or refinancings of the contracts, instruments or obligations referred to in clauses (1) through (15) above;provided that such amendments, modifications, restatements, renewals, increases, supplements, refundings, replacements or refinancings are, in the good faith judgment of Holdings, no more restrictive with respect to such dividend and other payment restrictions than those contained in the dividend or other payment restrictions prior to such amendment, modification, restatement, renewal, increase, supplement, refunding, replacement or refinancing.

For purposes of determining compliance with this covenant, (1) the priority of any Preferred Stock in receiving dividends or liquidating distributions prior to dividends or liquidating distributions being paid on common stock shall not be deemed a restriction on the ability to make distributions on Capital Stock and (2) the subordination of loans or advances made to Holdings or a Restricted Subsidiary to other Indebtedness Incurred by Holdings or any such Restricted Subsidiary shall not be deemed a restriction on the ability to make loans or advances.

Asset Sales

The indenture provides that Holdings will not, and will not permit any of the Restricted Subsidiaries to, cause or make an Asset Sale, unless (x) Holdings or any Restricted Subsidiary, as the case may be, receives consideration at the time of such Asset Sale at least equal to the Fair Market Value (as determined in good faith by Holdings) of the assets sold or otherwise disposed of, and (y) at

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least 75% of the consideration therefor received by Holdings or such Restricted Subsidiary, as the case may be, is in the form of Cash Equivalents or Additional Assets;provided that the amount of:

(a): any liabilities (as shown on Holdings' or a Restricted Subsidiary's most recent balance sheet or in the notes thereto) of Holdings or a Restricted Subsidiary (other than liabilities that are by their terms subordinated to the notes or any Subsidiary Guarantee) that are assumed by the transferee of any such assets or that are otherwise cancelled or terminated in connection with the transaction with such transferee,
(b): any notes or other obligations or other securities or assets received by Holdings or such Restricted Subsidiary from such transferee that are converted by Holdings or such Restricted Subsidiary into cash within 180 days of the receipt thereof (to the extent of the cash received),
(c): with respect to any Asset Sale of Oil and Gas Properties by Holdings or any Restricted Subsidiary, the costs and expenses related to the exploration, development, completion or production of such Oil and Gas Properties and activities related thereto agreed to be assumed by the transferee (or an Affiliate thereof),
(d): Indebtedness of any Restricted Subsidiary that is no longer a Restricted Subsidiary as a result of such Asset Sale, to the extent that Holdings and each other Restricted Subsidiary are released from any guarantee of payment of such Indebtedness in connection with the Asset Sale (without duplication of clause (a) hereto),
(e): consideration consisting of Indebtedness of Holdings or any Restricted Subsidiary (other than Subordinated Indebtedness) received after the Issue Date from Persons who are not Holdings or any Restricted Subsidiary in connection with the Asset Sale and that is cancelled, and
(f): any Designated Non-cash Consideration received by Holdings or any Restricted Subsidiary in such Asset Sale having an aggregate Fair Market Value (as determined in good faith by Holdings), taken together with all other Designated Non-cash Consideration received pursuant to this clause (c) that is at that time outstanding, not to exceed the greater of 4% of Adjusted Consolidated Net Tangible Assets and $300.0 million at the time of the receipt of such Designated Non-cash Consideration (with the Fair Market Value of each item of Designated Non-cash Consideration being measured at the time received and without giving effect to subsequent changes in value),

shall be deemed to be Cash Equivalents for the purposes of this provision.

Within 365 days after Holdings' or any Restricted Subsidiary's receipt of the Net Proceeds of any Asset Sale, Holdings or such Restricted Subsidiary may apply the Net Proceeds from such Asset Sale, at its option:

(1): to repay (a) Indebtedness constituting Bank Indebtedness and other Pari Passu Indebtedness that is secured by a Lien permitted under the indenture (and, if the Indebtedness repaid is revolving credit Indebtedness, to correspondingly reduce commitments with respect thereto), (b) Indebtedness of a Restricted Subsidiary that is not a Subsidiary Guarantor, (c) Obligations under the notes or (d) other Pari Passu Indebtedness (provided that if an Issuer or any Subsidiary Guarantor shall so reduce Obligations under unsecured Pari Passu Indebtedness, the Issuers will equally and ratably reduce Obligations under the notes as provided under "Optional Redemption," through open-market purchases (provided that such purchases are at or above 100% of the principal amount thereof or, in the event that the notes were issued with significant original issue discount, 100% of the accreted value thereof) or by making an offer (in accordance with the procedures set forth below for an Asset Sale Offer) to all holders to purchase at a purchase price equal to 100% of the principal amount thereof or, in the event that the notes were issued with significant original issue discount, 100% of the

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accreted value thereof), plus accrued and unpaid interest and additional interest, if any, the pro rata principal amount of notes), in each case other than Indebtedness owed to Holdings or an Affiliate of Holdings);

(2): to make an Investment in any one or more businesses (provided that if such Investment is in the form of the acquisition of Capital Stock of a Person, such acquisition results in such Person becoming a Restricted Subsidiary of Holdings), assets, or property or capital expenditures, in each case (a) used or useful in a Similar Business or (b) that replace the properties and assets that are the subject of such Asset Sale or to reimburse the cost of any of the foregoing incurred on or after the date on which the Asset Sale giving rise to such Net Proceeds was contractually committed; or
(3): to invest in Additional Assets.

In the case of clause (2) above, a binding commitment shall be treated as a permitted application of the Net Proceeds from the date of such commitment until the 18-month anniversary of the date of the receipt of such Net Proceeds;provided that in the event such binding commitment is later canceled or terminated for any reason before such Net Proceeds are so applied, then such Net Proceeds shall constitute Excess Proceeds unless Holdings or such Restricted Subsidiary enters into another binding commitment (a "Second Commitment") within six months of such cancellation or termination of the prior binding commitment;provided,further, that Holdings or such Restricted Subsidiary may only enter into a Second Commitment under the foregoing provision one time with respect to each Asset Sale and to the extent such Second Commitment is later cancelled or terminated for any reason before such Net Proceeds are applied or are not applied within 180 days of such Second Commitment, then such Net Proceeds shall constitute Excess Proceeds.

Pending the final application of any such Net Proceeds, Holdings or such Restricted Subsidiary may temporarily reduce Indebtedness under a revolving credit facility, if any, or otherwise invest such Net Proceeds in any manner not prohibited by the indenture. Any Net Proceeds from any Asset Sale that are not applied as provided and within the time period set forth in the second paragraph of this covenant (it being understood that any portion of such Net Proceeds used to make an offer to purchase notes, as described in clause (1) above, shall be deemed to have been invested whether or not such offer is accepted) will be deemed to constitute "Excess Proceeds." When the aggregate amount of Excess Proceeds exceeds $50.0 million, the Issuers shall make an offer to all holders of notes (and, at the option of the Issuers, to holders of any Pari Passu Indebtedness) (an "Asset Sale Offer") to purchase the maximum principal amount of notes (and such Pari Passu Indebtedness), that is at least $2,000 and an integral multiple of $1,000 in excess thereof that may be purchased out of the Excess Proceeds at an offer price in cash in an amount equal to 100% of the principal amount thereof (or, in the event the notes or such Pari Passu Indebtedness was issued with significant original issue discount, 100% of the accreted value thereof), plus accrued and unpaid interest and additional interest, if any (or, in respect of such Pari Passu Indebtedness, such lesser price, if any, as may be provided for by the terms of such Pari Passu Indebtedness), to the date fixed for the closing of such offer, in accordance with the procedures set forth in the indenture. The Issuers will commence an Asset Sale Offer with respect to Excess Proceeds within ten (10) Business Days after the date that Excess Proceeds exceeds $50.0 million by mailing, or delivering electronically if held by DTC, the notice required pursuant to the terms of the indenture, with a copy to the Trustee. To the extent that the aggregate amount of notes (and such Pari Passu Indebtedness) tendered pursuant to an Asset Sale Offer is less than the Excess Proceeds, Holdings may use any remaining Excess Proceeds for any purpose that is not prohibited by the indenture. If the aggregate principal amount of notes (and such Pari Passu Indebtedness) surrendered by holders thereof exceeds the amount of Excess Proceeds, the Trustee, upon receipt of written notice from the Issuers of the aggregate principal amount of notes to be selected, shall select the notes to be purchased in the manner described below. Upon completion of any such Asset Sale Offer, the amount of Excess Proceeds shall be reset at zero.

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The Issuers will comply with the requirements of Rule 14e-1 under the Exchange Act and any other securities laws and regulations to the extent such laws or regulations are applicable in connection with the repurchase of the notes pursuant to an Asset Sale Offer. To the extent that the provisions of any securities laws or regulations conflict with the provisions of the indenture, the Issuers will comply with the applicable securities laws and regulations and shall not be deemed to have breached its obligations described in the indenture by virtue thereof.

If more notes (and such Pari Passu Indebtedness) are tendered pursuant to an Asset Sale Offer than the Issuers are required to purchase, selection of such notes for purchase will be made by the Trustee in compliance with the requirements of the principal national securities exchange, if any, on which such notes are listed (and the Issuer shall notify the Trustee of any such listing), or if such notes are not so listed, on a pro rata basis to the extent practicable, by lot or by such other method as the Trustee shall deem fair and appropriate (and in such manner as complies with the procedures of DTC, if applicable);provided that no notes of $2,000 or less shall be purchased in part. Selection of such Pari Passu Indebtedness will be made pursuant to the terms of such Pari Passu Indebtedness.

Notices of an Asset Sale Offer shall be mailed by first class mail, postage prepaid, or delivered electronically if held by DTC, at least 30 but not more than 60 days before the purchase date to each holder of notes at such holder's registered address. If any note is to be purchased in part only, any notice of purchase that relates to such note shall state the portion of the principal amount thereof that has been or is to be purchased.

Transactions with Affiliates

The indenture provides that Holdings will not, and will not permit any of the Restricted Subsidiaries to, directly or indirectly, make any payment to, or sell, lease, transfer or otherwise dispose of any of its properties or assets to, or purchase any property or assets from, or enter into or make or amend any transaction or series of transactions, contract, agreement, understanding, loan, advance or guarantee with, or for the benefit of, any Affiliate of Holdings (each of the foregoing, an "Affiliate Transaction") involving aggregate consideration in excess of $20.0 million, unless:

(a): such Affiliate Transaction is on terms that are not materially less favorable to Holdings or the relevant Restricted Subsidiary than those that could have been obtained in a comparable transaction by Holdings or such Restricted Subsidiary with an unrelated Person; and
(b): with respect to any Affiliate Transaction or series of related Affiliate Transactions involving aggregate consideration in excess of $40.0 million, Holdings delivers to the Trustee a resolution adopted in good faith by the majority of the Board of Directors of Holdings, approving such Affiliate Transaction and set forth in an Officers' Certificate certifying that such Affiliate Transaction complies with clause (a) above.

The foregoing provisions will not apply to the following:

(1): transactions between or among Holdings and/or any of the Restricted Subsidiaries (or an entity that becomes a Restricted Subsidiary as a result of such transaction) and any merger, consolidation or amalgamation of Holdings and any direct parent of Holdings;provided that such parent shall have no material liabilities and no material assets other than cash, Cash Equivalents and the Capital Stock of Holdings and such merger, consolidation or amalgamation is otherwise in compliance with the terms of the indenture and effected for a bona fide business purpose;
(2): Restricted Payments permitted by the provisions of the indenture described above under the covenant "—Limitation on Restricted Payments" and Permitted Investments;

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(3): the payment of customary fees and reimbursement of expenses paid to, and indemnity provided on behalf of, officers, directors, managers, employees or consultants of Holdings, any Restricted Subsidiary, or any direct or indirect parent of Holdings;
(4): transactions in which Holdings or any Restricted Subsidiary, as the case may be, delivers to the Trustee a letter from an Independent Financial Advisor stating that such transaction is fair to Holdings or such Restricted Subsidiary from a financial point of view or meets the requirements of clause (a) of the preceding paragraph;
(5): payments or loans (or cancellation of loans) to officers, directors, employees or consultants which are approved by a majority of the Board of Directors of Holdings in good faith;
(6): any agreement as in effect as of the Issue Date or any amendment thereto or replacement (so long as any such agreement together with all amendments thereto or replacements, taken as a whole, are not more disadvantageous to Holdings and its Restricted Subsidiaries in any material respect than the original agreement as in effect on the Issue Date) or any transaction contemplated thereby, in each case as determined in good faith by Holdings;
(7): the existence of, or the performance by Holdings or any Restricted Subsidiary of its obligations under the terms of any stockholders or limited liability company agreement (including any registration rights agreement or purchase agreement related thereto) to which it is a party as of the Issue Date, and any transaction, agreement or arrangement described in the offering memorandum related to the initial notes dated May 28, 2015 and, in each case, any amendment thereto or similar transactions, agreements or arrangements which it may enter into thereafter;provided,however, that the existence of, or the performance by Holdings or any Restricted Subsidiary of its obligations under, any future amendment to any such existing transaction, agreement or arrangement or under any similar transaction, agreement or arrangement entered into after the Issue Date shall only be permitted by this clause (7) to the extent that the terms of any such existing transaction, agreement or arrangement together with all amendments thereto, taken as a whole, or new transaction, agreement or arrangement are not otherwise more disadvantageous to Holdings and its Restricted Subsidiaries in any material respect than the original transaction, agreement or arrangement as in effect on the Issue Date, as determined in good faith by Holdings;
(8): the execution of the Transactions, and the payment of all fees and expenses related to the Transactions, including fees to the Sponsors;
(9): (a) transactions with customers, clients, suppliers or purchasers or sellers of goods or services, or transactions otherwise relating to the purchase or sale of goods or services, in each case in the ordinary course of business and otherwise in compliance with the terms of the indenture, which are fair to Holdings and the Restricted Subsidiaries in the reasonable determination of the Board of Directors or the senior management of Holdings, or are on terms at least as favorable as might reasonably have been obtained at such time from an unaffiliated party or (b) transactions with joint ventures or Unrestricted Subsidiaries entered into in the ordinary course of business and consistent with past practice or industry custom;
(10): any transaction effected as part of a Qualified Receivables Financing;
(11): the issuance of Equity Interests (other than Disqualified Stock) of Holdings to any Person;
(12): the issuances of securities or other payments, awards or grants in cash, securities or otherwise pursuant to, or the funding of, employment arrangements, stock option and stock ownership plans or similar employee benefit plans approved by the Board of Directors of Holdings or any direct or indirect parent of Holdings or of a Restricted Subsidiary, as appropriate, in good faith;

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(13): the entering into of any tax sharing agreement or arrangement that complies with clause (12) of the second paragraph of the covenant described under "—Limitation on Restricted Payments" and the performance under any such agreement or arrangement;
(14): any contribution to the capital of Holdings;
(15): transactions permitted by, and complying with, the provisions of the covenant described under "—Merger, Amalgamation, Consolidation or Sale of All or Substantially All Assets";
(16): transactions between Holdings or any Restricted Subsidiary and any Person, a director of which is also a director or manager of Holdings or any direct or indirect parent of Holdings;provided,however, that such director or manager abstains from voting as a director or manager of Holdings or such direct or indirect parent, as the case may be, on any matter involving such other Person;
(17): pledges of Equity Interests of Unrestricted Subsidiaries;
(18): the formation and maintenance of any consolidated group or subgroup for tax, accounting or cash pooling or management purposes in the ordinary course of business;
(19): any employment agreements entered into by Holdings or any Restricted Subsidiary in the ordinary course of business;
(20): the payment of management, consulting, monitoring, transaction, advisory or similar fees and related expenses (including indemnification and other similar amounts) to the Sponsors pursuant to the Sponsor Management Agreement (plus any unpaid management, consulting, monitoring, advisory and other fees and related expenses (including indemnification and other similar amounts) accrued in any prior year) and the termination fees pursuant to the Sponsor Management Agreement, in each case as in effect on the Issue Date or any amendment or modification thereto (so long as, in the good faith judgment of the Board of Directors of Holdings, any such amendment or modification is not more disadvantageous, taken as a whole, to the Issuer and its Restricted Subsidiaries in any material respect as compared to the Sponsor Management Agreement in effect on the Issue Date);
(21): payments by Holdings or any of its Restricted Subsidiaries to any of the Sponsors made for any financial advisory, financing, underwriting or placement services or in respect of other investment banking activities, including in connection with acquisitions or divestitures, which payments are approved by a majority of the Board of Directors of Holdings in good faith;
(22): transactions undertaken in good faith (as certified by a responsible financial or accounting officer of Holdings in an Officers' Certificate) for the purpose of improving the consolidated tax efficiency of Holdings and its Subsidiaries and not for the purpose of circumventing any covenant set forth in the indenture;
(23): investments by the Sponsors in securities of Holdings or any Restricted Subsidiary (and payment of reasonable out-of-pocket expenses incurred by the Sponsors in connection therewith) so long as (i) the investment is being generally offered to other investors on the same or more favorable terms and (ii) the investment constitutes less than 5% of the proposed or outstanding issue amount of such class of securities; and
(24): customary agreements and arrangements with oil and gas royalty trusts and master limited partnership agreements that comply with the affiliate transaction provisions of such royalty trust or master limited partnership agreement.

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Liens

The indenture provides that Holdings will not, and will not permit any of its Restricted Subsidiaries to, directly or indirectly, create, Incur or suffer to exist any Lien (except Permitted Liens) on any asset or property of Holdings or such Restricted Subsidiary securing Indebtedness of Holdings or a Restricted Subsidiary unless the notes are equally and ratably secured with (or on a senior basis to, in the case of obligations subordinated in right of payment to the notes) the obligations so secured until such time as such obligations are no longer secured by a Lien.

Any Lien that is granted to secure the notes or any Subsidiary Guarantee under the preceding paragraph shall be automatically released and discharged at the same time as the release of the Lien that gave rise to the obligation to secure the notes or such Subsidiary Guarantee.

For purposes of determining compliance with this covenant, (A) a Lien securing an item of Indebtedness need not be permitted solely by reference to one category of permitted Liens (or any portion thereof) described in the definition of "Permitted Liens" or pursuant to the first paragraph of this covenant but may be permitted in part under any combination thereof and (B) in the event that a Lien securing an item of Indebtedness, Disqualified Stock or Preferred Stock (or any portion thereof) meets the criteria of one or more of the categories of permitted Liens (or any portion thereof) described in the definition of "Permitted Liens" or pursuant to the first paragraph of this covenant, Holdings shall, in its sole discretion, classify or reclassify, or later divide, classify or reclassify (as if Incurred at such later time), such Lien securing such item of Indebtedness (or any portion thereof) in any manner that complies with this covenant and will be entitled to include the amount and type of such Lien or such item of Indebtedness secured by such Lien (or portion thereof) in one of the categories of permitted Liens (or any portion thereof) described in the definition of "Permitted Liens" or pursuant to the first paragraph of this covenant and, in such event, such Lien securing such item of Indebtedness (or any portion thereof) will be treated as being Incurred or existing pursuant to only such clause or clauses (or any portion thereof) or pursuant to the first paragraph hereof.

With respect to any Lien securing Indebtedness that was permitted to secure such Indebtedness at the time of the Incurrence of such Indebtedness, such Lien shall also be permitted to secure any Increased Amount of such Indebtedness. The "Increased Amount" of any Indebtedness shall mean any increase in the amount of such Indebtedness in connection with any accrual of interest, the accretion of accreted value, the amortization of original issue discount, the payment of interest in the form of additional Indebtedness with the same terms or in the form of common stock of Holdings, the payment of dividends on Preferred Stock in the form of additional shares of Preferred Stock of the same class, accretion of original issue discount or liquidation preference and increases in the amount of Indebtedness outstanding solely as a result of fluctuations in the exchange rate of currencies or increases in the value of property securing Indebtedness described in clause (3) of the definition of "Indebtedness."

Reports and Other Information

The indenture provides that notwithstanding that Holdings may not be subject to the reporting requirements of Section 13 or 15(d) of the Exchange Act or otherwise report on an annual and quarterly basis on forms provided for such annual and quarterly reporting pursuant to rules and regulations promulgated by the SEC, Holdings will file with the SEC (and provide the Trustee and holders with copies thereof, without cost to each holder, within 15 days after it files them with the SEC),

(1): within the time period specified in the SEC's rules and regulations for non-accelerated filers, annual reports on Form 10-K (or any successor or comparable form) containing the information required to be contained therein (or required in such successor or comparable form), except to the extent permitted to be excluded by the SEC;

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(2): within the time period specified in the SEC's rules and regulations for non-accelerated filers, reports on Form 10-Q (or any successor or comparable form) containing the information required to be contained therein (or required in such successor or comparable form), except to the extent permitted to be excluded by the SEC;
(3): promptly from time to time after the occurrence of an event required to be therein reported (and in any event within the time period specified in the SEC's rules and regulations), such other reports on Form 8-K (or any successor or comparable form); and
(4): subject to the foregoing, any other information, documents and other reports which Holdings would be required to file with the SEC if it were subject to Section 13 or 15(d) of the Exchange Act;

provided,however, that Holdings shall not be so obligated to file such reports with the SEC if the SEC does not permit such filing, in which event Holdings will make available such information to prospective purchasers of notes in addition to providing such information to the Trustee and the holders, in each case within 15 days after the time Holdings would be required to file such information with the SEC if it were subject to Section 13 or 15(d) of the Exchange Act, subject, in the case of any such information, certificates or reports provided prior to the effectiveness of the exchange offer registration statement or shelf registration statement, to exceptions and exclusions consistent with the presentation of financial and other information in the offering memorandum related to the initial notes dated May 28, 2015 (including with respect to any periodic reports provided prior to effectiveness of the exchange offer registration statement or shelf registration statement, the omission of financial information required by Rule 3-10 under Regulation S-X promulgated by the SEC (or any successor provision)). In addition to providing such information to the Trustee, Holdings shall make available to the holders, prospective investors, market makers affiliated with any initial purchaser of the notes and securities analysts the information required to be provided pursuant to clauses (1), (2) or (3) of this paragraph, by posting such information to its website or on IntraLinks or any comparable online data system or website.

If Holdings has designated any of its Subsidiaries as an Unrestricted Subsidiary and if any such Unrestricted Subsidiary or group of Unrestricted Subsidiaries, if taken together as one Subsidiary, would constitute a Significant Subsidiary of Holdings, then the annual and quarterly information required by clauses (1) and (2) of the first paragraph of this covenant shall include a reasonably detailed presentation, either on the face of the financial statements or in the footnotes thereto, of the financial condition and results of operations of Holdings and its Restricted Subsidiaries separate from the financial condition and results of operations of such Unrestricted Subsidiaries.

Notwithstanding the foregoing, Holdings will not be required to furnish any information, certificates or reports required by Items 307 or 308 of Regulation S-K prior to the effectiveness of the exchange offer registration statement or shelf registration statement, as applicable.

In the event that:

(a): the rules and regulations of the SEC permit Holdings and any direct or indirect parent of Holdings to report at such parent entity's level on a consolidated basis and such parent entity is not engaged in any business in any material respect other than incidental to its ownership, directly or indirectly, of the capital stock of Holdings, or
(b): any direct or indirect parent of Holdings is or becomes a guarantor of the notes,

consolidating reporting at the parent entity's level in a manner consistent with that described in this covenant for Holdings will satisfy this covenant, and the indenture permits Holdings to satisfy its obligations in this covenant with respect to financial information relating Holdings by furnishing financial information relating to such direct or indirect parent;provided that such financial information

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is accompanied by consolidating information that explains in reasonable detail the differences between the information relating to such direct or indirect parent and any of its Subsidiaries other than Holdings and its Subsidiaries, on the one hand, and the information relating to Holdings, the Subsidiary Guarantors and the other Subsidiaries of Holdings on a standalone basis, on the other hand.

In addition, Holdings will make such information available to prospective investors upon request. In addition, Holdings has agreed that, for so long as any notes remain outstanding during any period when it is not subject to Section 13 or 15(d) of the Exchange Act, or otherwise permitted to furnish the SEC with certain information pursuant to Rule 12g3-2(b) of the Exchange Act, it will furnish to the holders of the notes and to prospective investors, upon their request, the information required to be delivered pursuant to Rule 144A(d)(4) under the Securities Act. Holdings will also hold quarterly conference calls for all holders and securities analysts to discuss such financial information no later than five Business Days after the distribution of such information required by this covenant and prior to the date of each such conference call, announcing the time and date of such conference call and either including all information necessary to access the call or informing holder of notes, prospective investors, market makers affiliated with any initial purchaser of the notes and securities analysts how they can obtain such information, including, without limitation, the applicable password or other login information.

Notwithstanding the foregoing, Holdings will be deemed to have furnished such reports referred to above to the Trustee and the holders if Holdings has filed such reports with the SEC via the EDGAR filing system and such reports are publicly available. In addition, the requirements of this covenant shall be deemed satisfied prior to the commencement of the exchange offer contemplated by the Registration Rights Agreement relating to the notes or the effectiveness of the shelf registration statement by (1) the filing with the SEC of the exchange offer registration statement and/or shelf registration statement in accordance with the provisions of such Registration Rights Agreement, and any amendments thereto, and such registration statement and/or amendments thereto are filed at times that otherwise satisfy the time requirements set forth in the first paragraph of this covenant and/or (2) the posting of reports that would be required to be provided to the Trustee and the holders on Holdings' website (or that of any of Holdings' parent companies).

Future Subsidiary Guarantors

The indenture provides that Holdings will cause each Wholly Owned Restricted Subsidiary that is not an Excluded Subsidiary and that guarantees any Indebtedness of an Issuer or any of the Subsidiary Guarantors to execute and deliver to the Trustee a supplemental indenture pursuant to which such Subsidiary will guarantee payment of the notes. Each Subsidiary Guarantee will be limited to an amount not to exceed the maximum amount that can be guaranteed by that Restricted Subsidiary without rendering the Subsidiary Guarantee, as it relates to such Restricted Subsidiary, voidable under applicable law relating to fraudulent conveyance or fraudulent transfer or similar laws affecting the rights of creditors generally.

Each Subsidiary Guarantee shall be released in accordance with the provisions of the indenture described under "—Subsidiary Guarantees."

Merger, Amalgamation, Consolidation or Sale of All or Substantially All Assets

The indenture provides that Holdings may not, directly or indirectly, consolidate, amalgamate or merge with or into or wind up or convert into (whether or not Holdings is the surviving Person), or sell, assign, transfer, lease, convey or otherwise dispose of all or substantially all of its properties or assets in one or more related transactions, to any Person unless:

(1): Holdings is the surviving person or the Person formed by or surviving any such consolidation, amalgamation, merger, winding up or conversion (if other than Holdings) or to which such

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sale, assignment, transfer, lease, conveyance or other disposition will have been made is a corporation, partnership, limited liability company or similar entity organized or existing under the laws of the United States, any state thereof, the District of Columbia, or any territory thereof (Holdings or such Person, as the case may be, being herein called the "Successor Holdco");provided that in the case where the surviving Person is not a corporation, a co-obligor of the notes is a corporation;

(2)

the Successor Holdco (if other than Holdings) expressly assumes all the obligations of Holdings under the indenture pursuant to supplemental indentures;

(3)

immediately after giving effect to such transaction (and treating any Indebtedness which becomes an obligation of the Successor Holdco, or any Restricted Subsidiary as a result of such transaction as having been Incurred by the Successor Holdco, or such Issuer or such Restricted Subsidiary at the time of such transaction) no Default shall have occurred and be continuing;

(4)

immediately after givingpro forma effect to such transaction, as if such transaction had occurred at the beginning of the applicable four-quarter period (and treating any Indebtedness which becomes an obligation of the Successor Holdco, or any Restricted Subsidiary as a result of such transaction as having been Incurred by the Successor Holdco, or such Restricted Subsidiary at the time of such transaction), either

(a): the Successor Holdco would be permitted to Incur at least $1.00 of additional Indebtedness pursuant to the Fixed Charge Coverage Ratio test set forth in the first sentence of the covenant described under "—Certain Covenants—Limitation on Incurrence of Indebtedness and Issuance of Disqualified Stock and Preferred Stock"; or
(b): the Fixed Charge Coverage Ratio would be no less than such ratio immediately prior to such transaction;

(5)

if Holdings is not the Successor Holdco, each Subsidiary Guarantor, unless it is the other party to the transactions described above, shall have by supplemental indenture confirmed that its Subsidiary Guarantee shall apply to such Person's obligations under the indenture and the notes; and

(6)

the Successor Holdco shall have delivered to the Trustee an Officers' Certificate and an Opinion of Counsel, each stating that such consolidation, merger, amalgamation or transfer and such supplemental indentures (if any) comply with the indenture.

The Successor Holdco (if other than Holdings) will succeed to, and be substituted for, Holdings under the indenture and the notes, and in such event Holdings will automatically be released and discharged from its obligations under the indenture and the notes. Notwithstanding the foregoing clauses (3) and (4), (a) Holdings or any Restricted Subsidiary may merge, consolidate or amalgamate with or transfer all or part of its properties and assets to or to a Restricted Subsidiary, and (b) Holdings may merge, consolidate or amalgamate with an Affiliate incorporated solely for the purpose of reincorporating Holdings in another state of the United States, the District of Columbia or any territory of the United States or may convert into a corporation, partnership, limited liability company or similar entity, so long as the amount of Indebtedness of Holdings and the Restricted Subsidiaries is not increased thereby. This "—Merger, Amalgamation, Consolidation or Sale of All or Substantially All Assets" will not apply to a sale, assignment, transfer, conveyance or other disposition of assets between or among Holdings and the Restricted Subsidiaries.

The indenture further provides that, subject to certain limitations in the indenture governing release of a Subsidiary Guarantee upon the sale or disposition of a Restricted Subsidiary of Holdings that is a Subsidiary Guarantor, no Subsidiary Guarantor will, and Holdings will not permit any

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Subsidiary Guarantor to, consolidate, amalgamate or merge with or into or wind up into (whether or not such Subsidiary Guarantor is the surviving Person), or sell, assign, transfer, lease, convey or otherwise dispose of all or substantially all of its properties or assets in one or more related transactions to, any Person unless:

(1): either (a) such Subsidiary Guarantor is the surviving Person or the Person formed by or surviving any such consolidation, amalgamation or merger (if other than such Subsidiary Guarantor) or to which such sale, assignment, transfer, lease, conveyance or other disposition will have been made is a company, corporation, partnership or limited liability company or similar entity organized or existing under the laws of the United States, any state thereof, the District of Columbia, or any territory thereof, (such Subsidiary Guarantor or such Person, as the case may be, being herein called the "Successor Subsidiary Guarantor") and the Successor Subsidiary Guarantor (if other than such Subsidiary Guarantor) expressly assumes all the obligations of such Subsidiary Guarantor under the indenture and the notes or the Subsidiary Guarantee, as applicable, pursuant to a supplemental indenture, or (b) such sale or disposition or consolidation, amalgamation or merger is not in violation of the covenant described above under the caption "—Certain Covenants—Asset Sales"; and
(2): the Successor Subsidiary Guarantor (if other than such Subsidiary Guarantor) shall have delivered or caused to be delivered to the Trustee an Officers' Certificate and an Opinion of Counsel, each stating that such consolidation, amalgamation, merger or transfer and such supplemental indenture (if any) comply with the indenture.

Subject to certain limitations described in the indenture, the Successor Subsidiary Guarantor (if other than such Subsidiary Guarantor) will succeed to, and be substituted for, such Subsidiary Guarantor under the indenture and the notes or the Subsidiary Guarantee, as applicable, and such Subsidiary Guarantor will automatically be released and discharged from its obligations under the indenture and its Subsidiary Guarantee. Notwithstanding the foregoing, (1) a Subsidiary Guarantor may merge, amalgamate or consolidate with an Affiliate incorporated solely for the purpose of reincorporating such Subsidiary Guarantor in another state of the United States, the District of Columbia or any territory thereof or may convert into a corporation, partnership, limited liability company, or similar entity, so long as the amount of Indebtedness of such Subsidiary Guarantor is not increased thereby and (2) a Subsidiary Guarantor may merge, amalgamate or consolidate with Holdings or another Subsidiary Guarantor.

In addition, notwithstanding the foregoing, a Subsidiary Guarantor may consolidate, amalgamate or merge with or into or wind up into, liquidate, dissolve, or sell, assign, transfer, lease, convey or otherwise dispose of all or substantially all of its properties or assets (collectively, a "Transfer") to Holdings or any Subsidiary Guarantor.

Defaults

An "Event of Default" is defined in the indenture as:

(1): a default in any payment of interest (including any additional interest) on any note when due, continued for 30 days;
(2): a default in the payment of principal or premium, if any, of any note when due at its Stated Maturity, upon optional redemption, upon required repurchase, upon declaration or otherwise;
(3): failure by Holdings for 120 days after receipt of written notice given by the Trustee or the holders of not less than 30% in aggregate principal amount of the notes then outstanding (with a copy to the Trustee) to comply with any of its obligations, covenants or agreements

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contained in the provisions of the indenture described in "Certain covenants—Reports and Other Information";

(4): the failure by Holdings or any Restricted Subsidiary for 60 days after written notice given by the Trustee or the holders of not less than 30% in principal amount of the notes then outstanding (with a copy to the Trustee) to comply with its other obligations, covenants or agreements (other than a default referred to in clauses (1), (2) and (3) above) contained in the notes or the indenture;
(5): the failure by Holdings or any Significant Subsidiary (or any group of Subsidiaries that together would constitute a Significant Subsidiary) to pay any Indebtedness (other than Indebtedness owing to Holdings or a Restricted Subsidiary) within any applicable grace period after final maturity or the acceleration of any such Indebtedness by the holders thereof because of a default, in each case, if the total amount of such Indebtedness unpaid or accelerated exceeds $125.0 million or its foreign currency equivalent (the "cross-acceleration provision");
(6): certain events of bankruptcy, insolvency or reorganization of Holdings or a Significant Subsidiary (or any group of Subsidiaries that together would constitute a Significant Subsidiary) (the "bankruptcy provisions");
(7): failure by Holdings or any Significant Subsidiary (or any group of Subsidiaries that together would constitute a Significant Subsidiary) to pay final judgments aggregating in excess of $125.0 million or its foreign currency equivalent (net of any amounts which are covered by enforceable insurance policies issued by solvent carriers), which judgments are not discharged, waived or stayed for a period of 60 days (the "judgment default provision"); or
(8): the Subsidiary Guarantee of a Significant Subsidiary (or any group of Subsidiaries that together would constitute a Significant Subsidiary) with respect to the notes ceases to be in full force and effect (except as contemplated by the terms thereof) or an Issuer or any Subsidiary Guarantor that qualifies as a Significant Subsidiary (or any group of Subsidiaries that together would constitute a Significant Subsidiary) denies or disaffirms its obligations under the indenture or any Subsidiary Guarantee with respect to the notes and such Default continues for 10 days.

The foregoing will constitute Events of Default whatever the reason for any such Event of Default and whether it is voluntary or involuntary or is effected by operation of law or pursuant to any judgment, decree or order of any court or any order, rule or regulation of any administrative or governmental body.

However, a default under clause (3) or (4) will not constitute an Event of Default until the Trustee or the holders of 30% in principal amount of outstanding notes notify the Issuers, with a copy to the Trustee, of the default and the Issuers do not cure such default within the time specified in clause (3) or (4) hereof after receipt of such notice.

If an Event of Default (other than an Event of Default relating to certain events of bankruptcy, insolvency or reorganization of Holdings) occurs with respect to the notes and is continuing, the Trustee by notice to the Issuers or the holders of at least 30% in principal amount of outstanding notes by notice to the Issuers, with a copy to the Trustee, may declare the principal of, premium, if any, and accrued but unpaid interest on all the notes to be due and payable. Upon such a declaration, such principal and interest will be due and payable immediately. If an Event of Default relating to certain events of bankruptcy, insolvency or reorganization of Holdings occurs, the principal of, premium, if any, and interest on all the notes will become immediately due and payable without any declaration or other act on the part of the Trustee or any holders. Under certain circumstances, the holders of a majority in

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principal amount of outstanding notes may rescind any such acceleration with respect to the notes and its consequences.

In the event of any Event of Default specified in clause (5) of the first paragraph above, such Event of Default and all consequences thereof (excluding, however, any resulting payment default) will be annulled, waived and rescinded, automatically and without any action by the Trustee or the holders of the notes, if within 20 days after such Event of Default arose the Issuers deliver an Officers' Certificate to the Trustee stating that (x) the Indebtedness or guarantee that is the basis for such Event of Default has been discharged or (y) the holders thereof have rescinded or waived the acceleration, notice or action (as the case may be) giving rise to such Event of Default or (z) the default that is the basis for such Event of Default has been cured, it being understood that in no event shall an acceleration of the principal amount of the notes as described above be annulled, waived or rescinded upon the happening of any such events.

In case an Event of Default occurs and is continuing, the Trustee will be under no obligation to exercise any of the rights or powers under the indenture at the request or direction of any of the holders unless such holders have offered to the Trustee indemnity or security satisfactory to it against any loss, liability or expense. Except to enforce the right to receive payment of principal, premium (if any) or interest when due, no holder may pursue any remedy with respect to the indenture or the notes unless:

(1): such holder has previously given the Trustee written notice that an Event of Default is continuing,
(2): holders of at least 30% in principal amount of the outstanding notes have requested the Trustee to pursue the remedy,
(3): such holders have offered the Trustee security or indemnity satisfactory to it against any loss, liability or expense,
(4): the Trustee has not complied with such request within 60 days after the receipt of the request and the offer of security or indemnity, and
(5): the holders of a majority in principal amount of the outstanding notes have not given the Trustee a direction inconsistent with such request within such 60-day period.

Subject to certain restrictions, the holders of a majority in principal amount of outstanding notes are given the right to direct the time, method and place of conducting any proceeding for any remedy available to the Trustee or of exercising any trust or power conferred on the Trustee. The Trustee, however, may refuse to follow any direction that conflicts with law or the indenture or that the Trustee determines is unduly prejudicial to the rights of any other holder or that would involve the Trustee in personal liability. Prior to taking any action under the indenture, the Trustee will be entitled to indemnification satisfactory to it in its sole discretion against all losses and expenses caused by taking or not taking such action.

The indenture provides that if a Default occurs and is continuing and is actually known to a Trust Officer of the Trustee, the Trustee must mail, or deliver electronically if held by DTC, to each holder of the notes notice of the Default within the earlier of 90 days after it occurs or 30 days after it is actually known to a Trust Officer or written notice of it is received by the Trustee. Except in the case of a Default in the payment of principal of, premium (if any) or interest on any note, the Trustee may withhold notice if and so long as the Trustee in good faith determines that withholding notice is in the interests of the noteholders. In addition, Holdings is required to deliver to the Trustee, annually, a certificate indicating whether the signers thereof know of any Default that occurred during the previous year. Holdings also is required to deliver to the Trustee, within 30 days after the occurrence thereof,

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written notice of any event which would constitute certain Defaults, their status and what action Holdings is taking or proposes to take in respect thereof.

Amendments and Waivers

Subject to certain exceptions, the indenture, the notes and the Subsidiary Guarantees may be amended with the consent of the holders of a majority in principal amount of the notes then outstanding and any past default or compliance with any provisions may be waived with the consent of the holders of a majority in principal amount of the notes then outstanding. However, without the consent of each holder of an outstanding note affected, no amendment may, among other things:

(1): reduce the amount of notes whose holders must consent to an amendment;
(2): reduce the rate of or extend the time for payment of interest on any note;
(3): reduce the principal of or change the Stated Maturity of any note;
(4): reduce the premium payable upon the redemption of any note or change the time at which any note may be redeemed as described under "—Optional Redemption" above;
(5): make any note payable in money other than that stated in such note;
(6): expressly subordinate the notes or any related Subsidiary Guarantee to any other Indebtedness of an Issuer or any Subsidiary Guarantor;
(7): impair the right of any holder to receive payment of principal of, premium, if any, and interest on such holder's notes on or after the due dates therefor or to institute suit for the enforcement of any payment on or with respect to such holder's notes; or
(8): make any change in the amendment provisions which require each holder's consent or in the waiver provisions.

Except as expressly provided by the indenture, without the consent of holders of at least 66.67% in principal amount of notes then outstanding, no amendment may modify or release the Subsidiary Guarantee of any Significant Subsidiary in any manner adverse to the holders of the notes.

Without the consent of any holder, the Issuers and the Trustee may amend the indenture, the notes or the Subsidiary Guarantees to cure any ambiguity, omission, mistake, defect or inconsistency, to provide for the assumption by a Successor Holdco (with respect to an Issuer) of the obligations of an Issuer under the indenture and the notes, to provide for the assumption by a Successor Subsidiary Guarantor (with respect to any Subsidiary Guarantor), as the case may be, of the obligations of a Subsidiary Guarantor under the indenture and its Subsidiary Guarantee, to provide for uncertificated notes in addition to or in place of certificated notes (provided that the uncertificated notes are issued in registered form for purposes of Section 163(f) of the Code, or in a manner such that the uncertificated notes are described in Section 163(f)(2)(B) of the Code) or to add a guarantee or obligor with respect to the notes, to secure the notes, to add to the covenants of the Issuers for the benefit of the holders or to surrender any right or power conferred upon the Issuers, to make any change that does not adversely affect the rights of any holder, to conform the text of the indenture, Subsidiary Guarantees or the notes, to any provision of this "Description of Exchange Notes" to the extent that such provision in this "Description of Exchange Notes" was intended by the Issuers to be a verbatim recitation of a provision of the indenture, Subsidiary Guarantees or the notes, to comply with any requirement of the SEC in connection with the qualification of the indenture under the TIA to effect any provision of the indenture or to make certain changes to the indenture to provide for the issuance of additional notes.

The consent of the noteholders is not necessary under the indenture to approve the particular form of any proposed amendment. It is sufficient if such consent approves the substance of the proposed amendment.

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No Personal Liability of Directors, Officers, Employees, Managers and Stockholders

No director, officer, employee, manager, incorporator or holder of any Equity Interests in Holdings or any direct or indirect parent companies, as such, will have any liability for any obligations of Holdings or any Subsidiary Guarantor under the notes, the indenture or the Subsidiary Guarantees, as applicable, or for any claim based on, in respect of, or by reason of, such obligations or their creation. Each holder of notes by accepting a note waives and releases all such liability. The waiver and release are part of the consideration for issuance of the notes. The waiver may not be effective to waive liabilities under the federal securities laws.

Transfer and Exchange

A noteholder may transfer or exchange notes in accordance with the indenture. Upon any transfer or exchange, the registrar and the Trustee may require a noteholder, among other things, to furnish appropriate endorsements and transfer documents and the Issuers may require a noteholder to pay any taxes required by law or permitted by the indenture. The Issuers are not required to transfer or exchange any notes selected for redemption or to transfer or exchange any notes for a period of 15 days prior to a selection of notes to be redeemed. The notes will be issued in registered form and the registered holder of a note will be treated as the owner of such note for all purposes.

Satisfaction and Discharge

The indenture will be discharged and will cease to be of further effect (except as to surviving rights and immunities of the Trustee and rights of registration or transfer or exchange of notes, as expressly provided for in the indenture) as to all outstanding notes when:

(1): either (a) all the notes theretofore authenticated and delivered (except lost, stolen or destroyed notes which have been replaced or paid and notes for whose payment money has theretofore been deposited in trust or segregated and held in trust by the Issuers and thereafter repaid to the Issuers or discharged from such trust) have been delivered to the Trustee for cancellation or (b) all of the notes (i) have become due and payable, (ii) will become due and payable at their stated maturity within one year or (iii) if redeemable at the option of the Issuers, are to be called for redemption within one year under arrangements satisfactory to the Trustee for the giving of notice of redemption by the Trustee in the name, and at the expense, of the Issuers, and the Issuers have irrevocably deposited or caused to be deposited with the Trustee funds in an amount sufficient to pay and discharge the entire Indebtedness on the notes not theretofore delivered to the Trustee for cancellation, for principal of, premium, if any, and interest on the notes to the date of deposit together with irrevocable instructions from the Issuers directing the Trustee to apply such funds to the payment thereof at maturity or redemption, as the case may be;provided that upon any redemption that requires the payment of the Applicable Premium, the amount deposited shall be sufficient for purposes of the indenture to the extent that an amount is deposited with the Trustee equal to the Applicable Premium calculated as of the date the notice of redemption is delivered, with any deficit as of the date of the redemption only required to be deposited with the Trustee on or prior to the date of the redemption;
(2): the Issuers and/or the Subsidiary Guarantors have paid all other sums payable under the indenture; and
(3): the Issuers have delivered to the Trustee an Officers' Certificate and an Opinion of Counsel stating that all conditions precedent under the indenture relating to the satisfaction and discharge of the indenture have been complied with.

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Defeasance

The Issuers at any time may terminate all of their obligations under the notes and the indenture with respect to the holders of the notes ("legal defeasance"), except for certain obligations, including those respecting the defeasance trust and obligations to register the transfer or exchange of the notes, to replace mutilated, destroyed, lost or stolen notes and to maintain a registrar and paying agent in respect of the notes. The Issuers at any time may terminate their obligations under the covenants described under "—Certain Covenants" for the benefit of the holders of the notes, the operation of the cross acceleration provision, the bankruptcy provisions with respect to Significant Subsidiaries, the judgment default provision described under "—Defaults" (but only to the extent that those provisions relate to the Defaults with respect to the notes) and the undertakings and covenants contained under "—Change of Control" and "—Certain Covenants—Merger, Amalgamation, Consolidation or Sale of All or Substantially All Assets" ("covenant defeasance") for the benefit of the holders of the notes. If the Issuers exercise their legal defeasance option or their covenant defeasance option, each Subsidiary Guarantor will be released from all of its obligations with respect to its Subsidiary Guarantee.

The Issuers may exercise their legal defeasance option notwithstanding its prior exercise of the covenant defeasance option. If the Issuers exercise their legal defeasance option, payment of the notes may not be accelerated because of an Event of Default with respect thereto. If the Issuers exercise their covenant defeasance option, payment of the notes may not be accelerated because of an Event of Default specified in clause (3), (4), (5) (with respect only to Significant Subsidiaries), (6), (7) or (8) under "—Defaults" or because of the failure of Holdings to comply with the first clause (4) under "—Certain Covenants—Merger, Amalgamation, Consolidation or Sale of All or Substantially All Assets."

In order to exercise their defeasance option, the Issuers must irrevocably deposit in trust (the "defeasance trust") with the Trustee money or U.S. Government Obligations for the payment of principal, premium (if any) and interest on the notes to redemption or maturity, as the case may be, and must comply with certain other conditions, including delivery to the Trustee of an Opinion of Counsel to the effect that holders of the notes will not recognize income, gain or loss for U.S. federal income tax purposes as a result of such deposit and defeasance and will be subject to U.S. federal income tax on the same amount and in the same manner and at the same times as would have been the case if such deposit and defeasance had not occurred (and, in the case of legal defeasance only, such Opinion of Counsel must be based on a ruling of the Internal Revenue Service or change in applicable U.S. federal income tax law). Notwithstanding the foregoing, the Opinion of Counsel required by the immediately preceding sentence with respect to a legal defeasance need not be delivered if all of the notes not theretofore delivered to the Trustee for cancellation (x) have become due and payable or (y) will become due and payable at their Stated Maturity within one year under arrangements satisfactory to the Trustee for the giving of notice of redemption by the Trustee in the name, and at the expense, of the Issuers.

Concerning the Trustee

The Wilmington Trust, National Association is the Trustee under the indenture and was appointed by the Issuers as registrar and a paying agent with regard to the notes.

Governing Law

The indenture provides that it and the notes are governed by, and construed in accordance with, the laws of the State of New York.

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Certain Definitions

"Acquired Indebtedness" means, with respect to any specified Person:

(1): Indebtedness of any other Person existing at the time such other Person is merged, consolidated or amalgamated with or into or became a Restricted Subsidiary of such specified Person, and
(2): Indebtedness secured by a Lien encumbering any asset acquired by such specified Person.

Acquired Indebtedness will be deemed to have been Incurred, with respect to clause (1) of the preceding sentence, on the date such Person becomes a Restricted Subsidiary and, with respect to clause (2) of the preceding sentence, on the date of consummation of such acquisition of such assets.

"Acquisition" means the purchase of EP Energy Corporation, EP Energy Holding Company and El Paso Brazil by EPE Acquisition LLC.

"Acquisition Documents" means the Purchase and Sale Agreement, dated as of February 24, 2012, by and among EP Energy Corporation, EP Energy Holding Company and El Paso Brazil, L.L.C., as sellers, and EPE Acquisition, LLC, as purchaser, and any other agreements or instruments contemplated thereby, in each case, as amended, restated, supplemented or otherwise modified from time to time.

"Additional Assets" means:

(1): any properties or assets used or useful in the Oil and Gas Business;
(2): capital expenditures by Holdings or a Restricted Subsidiary in the Oil and Gas Business;
(3): the Capital Stock of a Person that becomes a Restricted Subsidiary as a result of the acquisition of such Capital Stock by Holdings or another Restricted Subsidiary; or
(4): Capital Stock constituting a minority interest in any Person that at such time is a Restricted Subsidiary;

provided,however, that, in the case of clauses (3) and (4), such Restricted Subsidiary is primarily engaged in the Oil and Gas Business.

"Additional Refinancing Amount" means, in connection with the Incurrence of any Refinancing Indebtedness, the aggregate principal amount of additional Indebtedness, Disqualified Stock or Preferred Stock Incurred to pay premiums (including tender premiums), expenses, defeasance costs and fees in respect thereof.

"Adjusted Consolidated Net Tangible Assets" means (without duplication), as of the date of determination, the remainder of:

(a)

the sum of:

(i): estimated discounted future net revenues from proved oil and gas reserves of Holdings and its Restricted Subsidiaries calculated in accordance with SEC guidelines before any provincial, territorial, state, federal or foreign income taxes, as estimated by Holdings in a reserve report prepared as of the end of Holdings' most recently completed fiscal year for which audited financial statements are available, as increased by, as of the date of determination, the estimated discounted future net revenues from (A) estimated proved oil and gas reserves acquired since such year end, which reserves were not reflected in such year end reserve report, and (B) estimated oil and gas reserves attributable to upward revisions of estimates of proved oil and gas reserves (including the impact to discounted future net revenues related to development costs previously estimated in the last year end reserve report, but only to the extent such costs were actually incurred since

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the date of the last year end reserve report) since such year end due to exploration, development, exploitation or other activities, increased by the accretion of discount from the date of the last year end reserve report to the date of determination and decreased by, as of the date of determination, the estimated discounted future net revenues from (C) estimated proved oil and gas reserves included in the last year end reserve report that shall have been produced or disposed of since such year end, and (D) estimated oil and gas reserves included therein that are subsequently removed from the proved oil and gas reserves of Holdings and its Restricted Subsidiaries as so calculated due to downward revisions of estimates of proved oil and gas reserves since such year end due to changes in geological conditions or other factors which would, in accordance with standard industry practice, cause such revisions, provided, that (x) in the case of such year end reserve report and any adjustments since such year end pursuant to clauses (A), (B) and (D), the estimated discounted future net revenues from proved oil and gas reserves shall be determined in their entirety using oil, gas and other hydrocarbon prices and costs that are either (1) calculated in accordance with SEC guidelines and, with respect to such adjustments under clauses (A), (B) or (D), calculated with such prices and costs as if the end of the most recent fiscal quarter preceding the date of determination for which such information is available to Holdings were year end or (2) if Holdings so elects at any time, calculated in accordance with the foregoing clause (1), except that when pricing of future net revenues of proved oil and gas reserves under SEC guidelines is not based on a contract price and is instead based upon benchmark, market or posted pricing, the pricing for each month of estimated future production from such proved oil and gas reserves not subject to contract pricing shall be based upon NYMEX (or successor) published forward prices for the most comparable hydrocarbon commodity applicable to such production month (adjusted for energy content, quality and basis differentials, with such basis differentials determined as provided in the definition of "Borrowing Base" and giving application to the last sentence of such definition hereto), as such forward prices are published as of the year end date of such reserve report or, with respect to post-year end adjustments under clauses (A), (B) or (D), the last day of the most recent fiscal quarter preceding the date of determination, (y) the pricing of estimated proved reserves that have been produced or disposed since year end as set forth in clause (D) shall be based upon the applicable pricing elected for the prior year end reserve report as provided in clause (x), and (z) in each case as estimated by Holdings' petroleum engineers or any independent petroleum engineers engaged by Holdings for that purpose;

(ii): the capitalized costs that are attributable to Oil and Gas Properties of Holdings and its Restricted Subsidiaries to which no proved oil and gas reserves are attributable, based on Holdings' books and records as of a date no earlier than the date of Holdings' latest annual or quarterly consolidated financial statements;
(iii): the Net Working Capital on a date no earlier than the date of Holdings' latest annual or quarterly consolidated financial statements;
(iv): assets related to commodity risk management activitiesless liabilities related to commodity risk management activities, in each case to the extent that such assets and liabilities arise in the ordinary course of the Oil and Gas Business, provided that such net value shall not be less than zero; and
(v): the greater of (A) the net book value of other tangible assets (including, without limitation, investments in unconsolidated Restricted Subsidiaries and mineral rights held under lease or other contractual arrangement) of Holdings and its Restricted Subsidiaries, as of a date no earlier than the date of Holdings' latest annual or quarterly consolidated financial statements, and (B) the Fair Market Value, as estimated by Holdings, of other

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tangible assets (including, without limitation, investments in unconsolidated Restricted Subsidiaries and mineral rights held under lease or other contractual arrangement) of Holdings and its Restricted Subsidiaries, as of a date no earlier than the date of Holdings' latest audited consolidated financial statements (it being understood that Holdings shall not be required to obtain any appraisal of any assets); minus

(b)

the sum of:

(i): any amount included in (a)(i) through (a)(v) above that is attributable to minority interests;
(ii): any net gas balancing liabilities of Holdings and its Restricted Subsidiaries reflected in Holdings' latest audited consolidated financial statements;
(iii): to the extent included in (a)(i) above, the estimated discounted future net revenues, calculated in accordance with SEC guidelines (utilizing the prices and costs as provided in (a)(i)), attributable to reserves which are required to be delivered to third parties to fully satisfy the obligations of Holdings and its Restricted Subsidiaries with respect to Volumetric Production Payments (determined, if applicable, using the schedules specified with respect thereto); and
(iv): to the extent included in (a)(i) above, the estimated discounted future net revenues, calculated in accordance with SEC guidelines (utilizing prices and costs as provided in (a)(i)), attributable to reserves subject to Dollar-Denominated Production Payments which, based on the estimates of production and price assumptions included in determining the estimated discounted future net revenues specified in (a)(i) above, would be necessary to fully satisfy the payment obligations of Holdings and its Restricted Subsidiaries with respect to Dollar-Denominated Production Payments (determined, if applicable, using the schedules specified with respect thereto).

If Holdings changes its method of accounting from the full cost method of accounting to the successful efforts or a similar method, "Adjusted Consolidated Net Tangible Assets" will continue to be calculated as if Holdings were still using the full cost method of accounting.

"Affiliate" of any specified Person means any other Person directly or indirectly controlling or controlled by or under direct or indirect common control with such specified Person. For purposes of this definition, "control" (including, with correlative meanings, the terms "controlling," "controlled by" and "under common control with"), as used with respect to any Person, means the possession, directly or indirectly, of the power to direct or cause the direction of the management or policies of such Person, whether through the ownership of voting securities, by agreement or otherwise.

"Applicable Premium" means, with respect to any note on any applicable redemption date, as determined by the Issuers, the greater of:

(1)

1% of the then outstanding principal amount of the note; and

(2)

the excess of:

(a): the present value at such redemption date of (i) the redemption price of the note, at June 15, 2018 (such redemption price being set forth in the applicable table appearing above under "—Optional Redemption") plus (ii) all required interest payments due on the note through June 15, 2018 (excluding accrued but unpaid interest), computed using a discount rate equal to the Treasury Rate as of such redemption date plus 50 basis points; over
(b): the then outstanding principal amount of the note.

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"Asset Sale" means:

(1): the sale, conveyance, transfer or other disposition (whether in a single transaction or a series of related transactions) of property or assets (including by way of Production Payments and Reserve Sales and Sale/ Leaseback Transactions) (other than an operating lease entered into in the ordinary course of the Oil and Gas Business) outside the ordinary course of business of Holdings or any Restricted Subsidiary (each referred to in this definition as a "disposition"); or
(2): the issuance or sale of Equity Interests (other than directors' qualifying shares and shares issued to foreign nationals or other third parties to the extent required by applicable law) of any Restricted Subsidiary (other than to Holdings or another Restricted Subsidiary) (whether in a single transaction or a series of related transactions),

in each case other than:

(a): a disposition of Cash Equivalents or Investment Grade Securities or obsolete, damaged or worn out property or equipment in the ordinary course of business;
(b): the disposition of all or substantially all of the assets of Holdings in a manner permitted pursuant to the provisions described above under "—Certain Covenants—Merger, Amalgamation, Consolidation or Sale of All or Substantially All Assets" or any disposition that constitutes a Change of Control;
(c): any Restricted Payment or Permitted Investment that is permitted to be made, and is made, under the covenant described above under "—Certain Covenants—Limitation on Restricted Payments";
(d): any disposition of assets of Holdings or any Restricted Subsidiary or issuance or sale of Equity Interests of Holdings or any Restricted Subsidiary, which assets or Equity Interests so disposed or issued have an aggregate Fair Market Value (as determined in good faith by Holdings) of less than $50.0 million;
(e): any disposition of property or assets, or the issuance of securities, by a Restricted Subsidiary to Holdings or by Holdings or a Restricted Subsidiary to a Restricted Subsidiary;
(f): any exchange of assets (including a combination of assets and Cash Equivalents) for assets related to a Similar Business of comparable or greater market value or usefulness to the business of Holdings and the Restricted Subsidiaries as a whole, as determined in good faith by Holdings;
(g): foreclosure or any similar action with respect to any property or other asset of Holdings or any of the Restricted Subsidiaries;
(h): any sale of Equity Interests in, or Indebtedness or other securities of, an Unrestricted Subsidiary;
(i): the lease, assignment or sublease of, or any transfer related to a "reverse build to suit" or similar transaction in respect of, any real or personal property in the ordinary course of business;
(j): any sale of inventory or other assets in the ordinary course of business;
(k): any grant in the ordinary course of business of any license of patents, trademarks, know-how or any other intellectual property;
(l): in the ordinary course of business, any swap of assets, or lease, assignment or sublease of any real or personal property, in exchange for services (including in connection with any

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outsourcing arrangements) of comparable or greater value or usefulness to the business of Holdings and the Restricted Subsidiaries as a whole, as determined in good faith by Holdings;

(m): a transfer of accounts receivable and related assets of the type specified in the definition of "Receivables Financing" (or a fractional undivided interest therein), including by a Receivables Subsidiary in a Qualified Receivables Financing;
(n): any financing transaction with respect to property built or acquired by Holdings or any Restricted Subsidiary after the Issue Date, including any Sale/Leaseback Transaction or asset securitization permitted by the indenture;
(o): dispositions in connection with Permitted Liens;
(p): any disposition of Capital Stock of a Restricted Subsidiary pursuant to an agreement or other obligation with or to a Person (other than Holdings or a Restricted Subsidiary) from whom such Restricted Subsidiary was acquired or from whom such Restricted Subsidiary acquired its business and assets (having been newly formed in connection with such acquisition), made as part of such acquisition and in each case comprising all or a portion of the consideration in respect of such sale or acquisition;
(q): the sale of any property in a Sale/Leaseback Transaction within twelve months of the acquisition of such property;
(r): dispositions of receivables in connection with the compromise, settlement or collection thereof in the ordinary course of business or in bankruptcy or similar proceedings and exclusive of factoring or similar arrangements;
(s): any surrender, expiration or waiver of contract rights or oil and gas leases or the settlement, release, recovery on or surrender of contract, tort or other claims of any kind;
(t): a disposition of Hydrocarbons or mineral products inventory in the ordinary course of business;
(u): any Production Payments and Reserve Sales; provided that any such Production Payments and Reserve Sales, other than incentive compensation programs on terms that are reasonably customary in the Oil and Gas Business for geologists, geophysicists and other providers of technical services to the Issuer or a Restricted Subsidiary, shall have been created, incurred, issued, assumed or Guaranteed in connection with the financing of, and within 60 days after the acquisition of, the property that is subject thereto;
(v): the abandonment, farm-out pursuant to a Farm-Out Agreement, lease or sublease of developed or underdeveloped Oil and Gas Properties owned or held by the Issuer or any Restricted Subsidiary in the ordinary course of business or which are usual and customary in the Oil and Gas Business generally or in the geographic region in which such activities occur; and
(w): a disposition (whether or not in the ordinary course of business) of any Oil and Gas Property or interest therein to which no proved reserves are attributable at the time of such disposition.

"Bank Indebtedness" means any and all amounts payable under or in respect of (a) the Credit Agreement and the other Credit Agreement Documents, as amended, restated, supplemented, waived, replaced (whether or not upon termination, and whether with the original lenders or otherwise), restructured, repaid, refunded, refinanced or otherwise modified from time to time (including after termination of the Credit Agreement), including any agreement or indenture extending the maturity thereof, refinancing, replacing or otherwise restructuring all or any portion of the Indebtedness under such agreement or agreements or indenture or indentures or any successor or replacement agreement or agreements or indenture or indentures or increasing the amount loaned or issued thereunder or

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altering the maturity thereof, including principal, premium (if any), interest (including interest accruing on or after the filing of any petition in bankruptcy or for reorganization relating to Holdings whether or not a claim for post-filing interest is allowed in such proceedings), fees, charges, expenses, reimbursement obligations, guarantees and all other amounts payable thereunder or in respect thereof and (b) whether or not the Indebtedness referred to in clause (a) remains outstanding, if designated by Holdings to be included in this definition, one or more (A) debt facilities or commercial paper facilities, providing for revolving credit loans, term loans, reserve-based loans, receivables financing (including through the sale of receivables to lenders or to special purpose entities formed to borrow from lenders against such receivables) or letters of credit, (B) debt securities, indentures or other forms of debt financing (including convertible or exchangeable debt instruments or bank guarantees or bankers' acceptances), or (C) instruments or agreements evidencing any other Indebtedness, in each case, with the same or different borrowers or issuers and, in each case, as amended, supplemented, modified, extended, restructured, renewed, refinanced, restated, replaced or refunded in whole or in part from time to time.

"Board of Directors" means, as to any Person, the board of directors or managers, as applicable, of such Person or any direct or indirect parent of such Person (or, if such Person is a partnership, the board of directors or other governing body of the general partner of such Person) or any duly authorized committee thereof. In the case of Holdings, the Board of Directors of Holdings shall be deemed to include the Board of Directors of Holdings or any direct or indirect parent, as appropriate.

"Borrowing Base" means, at any date of determination, an amount equal to the amount of (a) 65% of the net present value discounted at 9% of proved developed producing (PDP) reserves, plus (b) 35% of the net present value discounted at 9% of proved developed non-producing (PDNP) reserves, plus (c) 25% of the net present value discounted at 9% of proven undeveloped (PUD) reserves, plus or minus (d) 65% of the net present value discounted at 9% of the future receipts expected to be paid to or by Holdings and its Restricted Subsidiaries under commodity hedging agreements (other than basis differential commodity hedging agreements), netted against the price described below, plus or minus (e) 65% of the net present value discounted at 9% of the future receipts expected to be paid to or by Holdings and its Restricted subsidiaries under basis differential commodity hedging agreements, in each case for Holdings and its Restricted Subsidiaries, and (i) for purposes of clauses (a) through (d) above, as estimated by Holdings in a reserve report prepared by Holdings' petroleum engineers applying the relevant NYMEX (or successor) published forward prices for the most comparable hydrocarbon commodity adjusted for relevant energy content, quality and basis differentials (before any state or federal or other income tax) and (ii) for purposes of clauses (d) and (e) above, as estimated by Holdings applying, if available, the relevant NYMEX (or successor) published forward basis differential or, if such NYMEX (or successor) forward basis differential is unavailable, in good faith based on historical basis differential (before any state or federal or other income tax). For any months beyond the term included in published NYMEX (or successor) forward pricing, the price used will be equal to the last published contract escalated at 1.5% per annum.

"Business Day" means a day other than a Saturday, Sunday or other day on which banking institutions are authorized or required by law to close in New York City or the place of payment.

"Capital Stock" means:

(1): in the case of a corporation, corporate stock or shares;
(2): in the case of an association or business entity, any and all shares, interests, participations, rights or other equivalents (however designated) of corporate stock;
(3): in the case of a partnership or limited liability company, partnership or membership interests (whether general or limited); and
(4): any other interest or participation that confers on a Person the right to receive a share of the profits and losses of, or distributions of assets of, the issuing Person.

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"Capitalized Lease Obligation" means, at the time any determination thereof is to be made, the amount of the liability in respect of a capital lease that would at such time be required to be capitalized and reflected as a liability on a balance sheet (excluding the footnotes thereto) in accordance with GAAP; provided that any obligations of Holdings or its Restricted Subsidiaries, or of a special purpose or other entity not consolidated with Holdings and its Restricted Subsidiaries, either existing on the Issue Date or created prior to any recharacterization described below (or any refinancings thereof) (i) that were not included on the consolidated balance sheet of Holdings as capital lease obligations and (ii) that are subsequently recharacterized as capital lease obligations or, in the case of such a special purpose or other entity becoming consolidated with Holdings and its Restricted Subsidiaries, due to a change in accounting treatment or otherwise, shall for all purposes not be treated as Capitalized Lease Obligations or Indebtedness.

"Capitalized Software Expenditures" shall mean, for any period, the aggregate of all expenditures (whether paid in cash or accrued as liabilities) by a Person and its Restricted Subsidiaries during such period in respect of licensed or purchased software or internally developed software and software enhancements that, in conformity with GAAP, are or are required to be reflected as capitalized costs on the consolidated balance sheet of such Person and such Restricted Subsidiaries.

"Cash Equivalents" means:

(1): U.S. dollars, pounds sterling, euros, the national currency of any member state in the European Union or such local currencies held by an entity from time to time in the ordinary course of business;
(2): securities issued or directly and fully guaranteed or insured by the U.S. government or any country that is a member of the European Union or any agency or instrumentality thereof in each case maturing not more than two years from the date of acquisition;
(3): certificates of deposit, time deposits and eurodollar time deposits with maturities of one year or less from the date of acquisition, bankers' acceptances, in each case with maturities not exceeding one year and overnight bank deposits, in each case with any commercial bank having capital and surplus in excess of $250.0 million and whose long-term debt is rated "A" or the equivalent thereof by Moody's or S&P (or reasonably equivalent ratings of another internationally recognized ratings agency);
(4): repurchase obligations for underlying securities of the types described in clauses (2) and (3) above entered into with any financial institution meeting the qualifications specified in clause (3) above;
(5): commercial paper issued by a corporation (other than an Affiliate of Holdings) rated at least "A-1" or the equivalent thereof by Moody's or S&P (or reasonably equivalent ratings of another internationally recognized ratings agency) and in each case maturing within one year after the date of acquisition;
(6): readily marketable direct obligations issued by any state of the United States of America or any political subdivision thereof having one of the two highest rating categories obtainable from either Moody's or S&P (or reasonably equivalent ratings of another internationally recognized ratings agency) in each case with maturities not exceeding two years from the date of acquisition;
(7): Indebtedness issued by Persons (other than the Sponsors or any of their Affiliates) with a rating of "A" or higher from S&P or "A-2" or higher from Moody's (or reasonably equivalent ratings of another internationally recognized ratings agency) in each case with maturities not exceeding two years from the date of acquisition; and

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(8): investment funds investing at least 95% of their assets in securities of the types described in clauses (1) through (7) above.

"Change of Control" means the occurrence of either of the following:

(1): the sale, lease or transfer, in one or a series of related transactions, of all or substantially all the assets of Holdings and its Subsidiaries, taken as a whole, to a Person other than any of the Permitted Holders; or
(2): Holdings becomes aware (by way of a report or any other filing pursuant to Section 13(d) of the Exchange Act, proxy, vote, written notice or otherwise) of the acquisition by any Person or group (within the meaning of Section 13(d)(3) or Section 14(d)(2) of the Exchange Act, or any successor provision), including any group acting for the purpose of acquiring, holding or disposing of securities (within the meaning of Rule 13d-5(b)(1) under the Exchange Act), other than any of the Permitted Holders, in a single transaction or in a related series of transactions, by way of merger, consolidation, amalgamation or other business combination or purchase of beneficial ownership (within the meaning of Rule 13d-3 under the Exchange Act, or any successor provision), of more than 50% of the total voting power of the Voting Stock of Holdings.

"Code" means the Internal Revenue Code of 1986, as amended.

"Consolidated Depreciation, Depletion and Amortization Expense" means, with respect to any Person for any period, the total amount of depreciation, depletion and amortization expense, including the amortization of intangible assets, deferred financing fees and Capitalized Software Expenditures and amortization of unrecognized prior service costs and actuarial gains and losses related to pensions and other post-employment benefits, of such Person and its Restricted Subsidiaries for such period on a consolidated basis and otherwise determined in accordance with GAAP.

"Consolidated Interest Expense" means, with respect to any Person for any period, the sum, without duplication, of:

(1): consolidated interest expense of such Person and its Restricted Subsidiaries for such period, to the extent such expense was deducted in computing Consolidated Net Income (including amortization of original issue discount, the interest component of Capitalized Lease Obligations, and net payments and receipts (if any) pursuant to interest rate Hedging Obligations and excluding additional interest in respect of the notes, amortization of deferred financing fees, any interest attributable to Dollar-Denominated Production Payments, debt issuance costs, commissions, fees and expenses, expensing of any bridge, commitment or other financing fees and non-cash interest expense attributable to movement in mark to market valuation of Hedging Obligations or other derivatives (in each case permitted hereunder) under GAAP);plus
(2): consolidated capitalized interest of such Person and its Restricted Subsidiaries for such period, whether paid or accrued;plus
(3): commissions, discounts, yield and other fees and charges Incurred in connection with any Receivables Financing which are payable to Persons other than Holdings and the Restricted Subsidiaries;minus
(4): interest income for such period.

For purposes of this definition, interest on a Capitalized Lease Obligation shall be deemed to accrue at an interest rate reasonably determined by Holdings to be the rate of interest implicit in such Capitalized Lease Obligation in accordance with GAAP.

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"Consolidated Net Income" means, with respect to any Person for any period, the aggregate of the Net Income of such Person and its Restricted Subsidiaries for such period, on a consolidated basis;provided,however, that:

(1): any net after-tax extraordinary, nonrecurring or unusual gains or losses (less all fees and expenses relating thereto) or expenses or charges, any severance expenses, relocation expenses, curtailments or modifications to pension and post-retirement employee benefit plans, any expenses related to any reconstruction, decommissioning, recommissioning or reconfiguration of fixed assets for alternate uses and fees, expenses or charges relating to facilities closing costs, acquisition integration costs, facilities opening costs, project start-up costs, business optimization costs, signing, retention or completion bonuses, expenses or charges related to any issuance of Equity Interests, Investment, acquisition, disposition, recapitalization or issuance, repayment, refinancing, amendment or modification of Indebtedness (in each case, whether or not successful), and any fees, expenses, charges or change in control payments related to the Transactions, in each case, shall be excluded;
(2): effects of purchase accounting adjustments (including the effects of such adjustments pushed down to such Person and such Subsidiaries) in amounts required or permitted by GAAP, resulting from the application of purchase accounting or the amortization or write-off of any amounts thereof, net of taxes, shall be excluded;
(3): the Net Income for such period shall not include the cumulative effect of a change in accounting principles during such period;
(4): any net after-tax income or loss from disposed, abandoned, transferred, closed or discontinued operations or fixed assets and any net after-tax gains or losses on disposal of disposed, abandoned, transferred, closed or discontinued operations or fixed assets shall be excluded;
(5): any net after-tax gains or losses (less all fees and expenses or charges relating thereto) attributable to business dispositions or asset dispositions other than in the ordinary course of business (as determined in good faith by management of Holdings) shall be excluded;
(6): any net after-tax gains or losses (less all fees and expenses or charges relating thereto) attributable to the early extinguishment of indebtedness, Hedging Obligations or other derivative instruments shall be excluded;
(7): the Net Income for such period of any Person that is not a Subsidiary of such Person, or is an Unrestricted Subsidiary, or that is accounted for by the equity method of accounting, shall be included only to the extent of the amount of dividends or distributions or other payments paid in cash (or to the extent converted into cash) to the referent Person or a Restricted Subsidiary thereof in respect of such period;
(8): solely for the purpose of determining the amount available for Restricted Payments under clause (1) of the definition of Cumulative Credit contained in "—Certain Covenants—Limitation on Restricted Payments," the Net Income for such period of any Restricted Subsidiary (other than any Subsidiary Guarantor) shall be excluded to the extent that the declaration or payment of dividends or similar distributions by such Restricted Subsidiary of its Net Income is not at the date of determination permitted without any prior governmental approval (which has not been obtained) or, directly or indirectly, by the operation of the terms of its charter or any agreement, instrument, judgment, decree, order, statute, rule or governmental regulation applicable to that Restricted Subsidiary or its stockholders, unless such restrictions with respect to the payment of dividends or similar distributions have been legally waived;provided that the Consolidated Net Income of such Person shall be increased by the amount of dividends or other distributions or other payments actually paid in cash (or

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converted into cash) by any such Restricted Subsidiary to such Person, to the extent not already included therein;

(9): an amount equal to the amount of Tax Distributions actually made to any parent or equity holder of such Person in respect of such period in accordance with clause (12) of the second paragraph under "—Certain Covenants—Limitation on Restricted Payments" shall be included as though such amounts had been paid as income taxes directly by such Person for such period;
(10): any impairment charges or asset write-offs, in each case pursuant to GAAP, the amortization of intangibles and other fair value adjustments arising pursuant to GAAP, and any impairment charges, asset write-offs or write-down, including ceiling test write-downs, on Oil and Gas Properties under GAAP or SEC guidelines shall be excluded;
(11): any non-cash expense realized or resulting from stock option plans, employee benefit plans or post-employment benefit plans, or grants or sales of stock, stock appreciation or similar rights, stock options, restricted stock, preferred stock or other rights shall be excluded;
(12): any (a) non-cash compensation charges, (b) costs and expenses after the Issue Date related to employment of terminated employees, or (c) costs or expenses realized in connection with or resulting from stock appreciation or similar rights, stock options or other rights existing on the Issue Date of officers, directors, managers and employees, in each case of such Person or any Restricted Subsidiary, shall be excluded;
(13): accruals and reserves that are established or adjusted within 12 months after the Issue Date and that are so required to be established or adjusted in accordance with GAAP or as a result of adoption or modification of accounting policies shall be excluded;
(14): (a) the Net Income of any Person and its Restricted Subsidiaries shall be calculated without deducting the income attributable to, or adding the losses attributable to, the minority equity interests of third parties in any non-Wholly Owned Restricted Subsidiary except to the extent of dividends declared or paid in respect of such period or any prior period on the shares of Capital Stock of such Restricted Subsidiary held by such third parties and (b) any ordinary course dividend, distribution or other payment paid in cash and received from any Person in excess of amounts included in clause (7) above shall be included;
(15): (a)(i) the non-cash portion of "straight-line" rent expense shall be excluded and (ii) the cash portion of "straight-line" rent expense which exceeds the amount expensed in respect of such rent expense shall be included and (b) non-cash gains, losses, income and expenses resulting from fair value accounting required by the applicable standard under GAAP and related interpretations shall be excluded;
(16): any currency translation gains and losses related to currency remeasurements of Indebtedness, and any net loss or gain resulting from hedging transactions for currency exchange risk, shall be excluded;
(17): (a) to the extent covered by insurance and actually reimbursed, or, so long as such Person has made a determination that there exists reasonable evidence that such amount will in fact be reimbursed by the insurer and only to the extent that such amount is (a) not denied by the applicable carrier in writing within 180 days and (b) in fact reimbursed within 365 days of the date of such evidence (with a deduction for any amount so added back to the extent not so reimbursed within 365 days), expenses with respect to liability or casualty events or business interruption shall be excluded and (b) amounts estimated in good faith to be received from insurance in respect of lost revenues or earnings in respect of liability or casualty events or

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business interruption shall be included (with a deduction for amounts actually received up to such estimated amount to the extent included in Net Income in a future period);

(18): Capitalized Software Expenditures shall be excluded; and
(19): Non-cash charges for deferred tax asset valuation allowances shall be excluded (except to the extent reversing a previously recognized increase to net income).

Notwithstanding the foregoing, for the purpose of the covenant described under "—Certain Covenants—Limitation on Restricted Payments" only, there shall be excluded from Consolidated Net Income any dividends, repayments of loans or advances or other transfers of assets from Unrestricted Subsidiaries or Restricted Subsidiaries to the extent such dividends, repayments or transfers increase the amount of Restricted Payments permitted under such covenant pursuant to clauses (4) and (5) of the definition of Cumulative Credit contained therein.

"Consolidated Non-Cash Charges" means, with respect to any Person for any period, the non-cash expenses (other than Consolidated Depreciation, Depletion and Amortization Expense) of such Person and its Restricted Subsidiaries reducing Consolidated Net Income of such Person for such period on a consolidated basis and otherwise determined in accordance with GAAP,provided that if any such non-cash expenses represent an accrual or reserve for potential cash items in any future period, the cash payment in respect thereof in such future period shall be subtracted from EBITDA in such future period to the extent paid, but excluding from this proviso, for the avoidance of doubt, amortization of a prepaid cash item that was paid in a prior period.

"Consolidated Taxes" means, with respect to any Person for any period, the provision for taxes based on income, profits or capital, including, without limitation, state, franchise, property and similar taxes, foreign withholding taxes (including penalties and interest related to such taxes or arising from tax examinations) and any Tax Distributions taken into account in calculating Consolidated Net Income.

"Consolidated Total Indebtedness" means, as of any date of determination, an amount equal to the sum (without duplication) of (1) the aggregate principal amount of all outstanding Indebtedness of Holdings and the Restricted Subsidiaries (excluding any undrawn letters of credit) consisting of Capitalized Lease Obligations, bankers' acceptances and Indebtedness for borrowed money, plus (2) the aggregate amount of all outstanding Disqualified Stock of Holdings and the Restricted Subsidiaries and all Preferred Stock of Restricted Subsidiaries, with the amount of such Disqualified Stock and Preferred Stock equal to the greater of their respective voluntary or involuntary liquidation preferences, in each case determined on a consolidated basis in accordance with GAAP.

"Contingent Obligations" means, with respect to any Person, any obligation of such Person guaranteeing any leases, dividends or other obligations that do not constitute Indebtedness ("primary obligations") of any other Person (the "primary obligor") in any manner, whether directly or indirectly, including, without limitation, any obligation of such Person, whether or not contingent:

(1)

to purchase any such primary obligation or any property constituting direct or indirect security therefor,

(2)

to advance or supply funds:

(a): for the purchase or payment of any such primary obligation; or
(b): to maintain working capital or equity capital of the primary obligor or otherwise to maintain the net worth or solvency of the primary obligor; or

(3)

to purchase property, securities or services primarily for the purpose of assuring the owner of any such primary obligation of the ability of the primary obligor to make payment of such primary obligation against loss in respect thereof.

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"Credit Agreement" means (i) the Credit Agreement dated as of May 24, 2012 by and among Holdings, the guarantors named therein, the financial institutions named therein, and JPMorgan Chase Bank, N.A., as administrative agent, as amended, restated, supplemented, waived, replaced (whether or not upon termination, and whether with the original lenders or otherwise), restructured, repaid, refunded, refinanced or otherwise modified from time to time, including any agreement or indenture extending the maturity thereof, refinancing, replacing or otherwise restructuring all or any portion of the Indebtedness under such agreement or agreements or indenture or indentures or any successor or replacement agreement or agreements or indenture or indentures or increasing the amount loaned or issued thereunder or altering the maturity thereof (except to the extent any such refinancing, replacement or restructuring is designated by Holdings to not be included in the definition of "Credit Agreement") and (ii) whether or not the credit agreement referred to in clause (i) remains outstanding, if designated by Holdings to be included in the definition of "Credit Agreement," one or more (A) debt facilities or commercial paper facilities, providing for revolving credit loans, term loans, reserve-based loans, securitization or receivables financing (including through the sale of receivables to lenders or to special purpose entities formed to borrow from lenders against such receivables) or letters of credit, (B) debt securities, indentures or other forms of debt financing (including convertible or exchangeable debt instruments or bank guarantees or bankers' acceptances), or (C) instruments or agreements evidencing any other Indebtedness, in each case, with the same or different borrowers or issuers and, in each case, as amended, supplemented, modified, extended, restructured, renewed, refinanced, restated, replaced or refunded in whole or in part from time to time.

"Credit Agreement Documents" means the collective reference to any Credit Agreement, any notes issued pursuant thereto and the guarantees thereof, and the collateral documents relating thereto, as amended, supplemented, restated, renewed, refunded, replaced, restructured, repaid, refinanced or otherwise modified, in whole or in part, from time to time.

"Default" means any event which is, or after notice or passage of time or both would be, an Event of Default.

"Designated Non-cash Consideration" means the Fair Market Value (as determined in good faith by Holdings) of non-cash consideration received by Holdings or a Restricted Subsidiary in connection with an Asset Sale that is so designated as Designated Non-cash Consideration pursuant to an Officers' Certificate, setting forth the basis of such valuation, less the amount of Cash Equivalents received in connection with a subsequent sale of such Designated Non-cash Consideration.

"Designated Preferred Stock" means Preferred Stock of Holdings or any direct or indirect parent of Holdings (other than Disqualified Stock), that is issued for cash (other than to Holdings or any of its Subsidiaries or an employee stock ownership plan or trust established by Holdings or any of its Subsidiaries) and is so designated as Designated Preferred Stock, pursuant to an Officers' Certificate, on the issuance date thereof.

"Disqualified Stock" means, with respect to any Person, any Capital Stock of such Person which, by its terms (or by the terms of any security into which it is convertible or for which it is redeemable or exchangeable), or upon the happening of any event:

(1): matures or is mandatorily redeemable, pursuant to a sinking fund obligation or otherwise (other than as a result of a change of control or asset sale),
(2): is convertible or exchangeable for Indebtedness or Disqualified Stock of such Person, or
(3): is redeemable at the option of the holder thereof, in whole or in part (other than solely as a result of a change of control or asset sale),

in each case prior to 91 days after the earlier of the maturity date of the notes or the date the notes are no longer outstanding;provided,however, that only the portion of Capital Stock which so matures

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or is mandatorily redeemable, is so convertible or exchangeable or is so redeemable at the option of the holder thereof prior to such date shall be deemed to be Disqualified Stock;provided,further,however, that if such Capital Stock is issued to any employee or to any plan for the benefit of employees of Holdings or its Subsidiaries or by any such plan to such employees, such Capital Stock shall not constitute Disqualified Stock solely because it may be required to be repurchased by such Person in order to satisfy applicable statutory or regulatory obligations or as a result of such employee's termination, death or disability;provided,further, that any class of Capital Stock of such Person that by its terms authorizes such Person to satisfy its obligations thereunder by delivery of Capital Stock that is not Disqualified Stock shall not be deemed to be Disqualified Stock.

"Dollar-Denominated Production Payments" means production payment obligations recorded as liabilities in accordance with GAAP, together with all undertakings and obligations in connection therewith.

"Domestic Subsidiary" means a Restricted Subsidiary that is not a Foreign Subsidiary.

"EBITDA" means, with respect to any Person for any period, the Consolidated Net Income of such Person and its Restricted Subsidiaries for such period plus, without duplication, to the extent the same was deducted in calculating Consolidated Net Income:

(1): Consolidated Taxes;plus
(2): Fixed Charges;plus
(3): Consolidated Depreciation, Depletion and Amortization Expense;plus
(4): Consolidated Non-Cash Charges;plus
(5): any expenses or charges (other than Consolidated Depreciation, Depletion and Amortization Expense) related to any issuance of Equity Interests, Investment, acquisition, disposition, recapitalization or the incurrence, modification or repayment of Indebtedness permitted to be incurred by the indenture (including a refinancing thereof) (whether or not successful), including (i) such fees, expenses or charges related to the Transactions, the notes or any other Indebtedness, (ii) any amendment or other modification of the notes or other Indebtedness, (iii) any additional interest in respect of the notes and (iv) commissions, discounts, yield and other fees and charges (including any interest expense) related to any Qualified Receivables Financing;plus
(6): business optimization expenses and other restructuring charges, reserves or expenses (which, for the avoidance of doubt, shall include, without limitation, the effect of inventory optimization programs, facility closures, facility consolidations, retention, systems establishment costs, contract termination costs, future lease commitments and excess pension charges);plus
(7): the amount of loss on sale of receivables and related assets to a Receivables Subsidiary in connection with a Qualified Receivables Financing;plus
(8): any costs or expense incurred pursuant to any management equity plan or stock option plan or any other management or employee benefit plan or agreement or any stock subscription or shareholder agreement, to the extent that such cost or expenses are funded with cash proceeds contributed to the capital of Holdings or a Subsidiary Guarantor or net cash proceeds of an issuance of Equity Interests of Holdings (other than Disqualified Stock) solely to the extent that such net cash proceeds are excluded from the calculation of the Cumulative Credit;plus
(9): the amount of any management, monitoring, consulting, transaction and advisory fees and related expenses paid to the Sponsors (or any accruals relating to such fees and related expenses) during such period to the extent otherwise permitted by the covenant described

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under "—Certain Covenants—Transactions with Affiliates", including, if applicable, the amount of termination fees paid pursuant to clause (20) thereof; plus

(10): all adjustments of the nature used in connection with the calculation of "Adjusted EBITDAX" as set forth in "Summary Historical and Consolidated Financial Data" under "Summary" in the offering memorandum related to the initial notes dated May 28, 2015 to the extent such adjustments, without duplication, continue to be applicable to such period; plus
(11): the amount of any loss attributable to a new plant or facility until the date that is 12 months after completing construction of or acquiring such plant or facility, as the case may be; provided that (A) such losses are reasonably identifiable and factually supportable and certified by a responsible officer of Holdings and (B) losses attributable to such plant or facility after 12 months from the date of completing construction of or acquisition of such plant or facility, as the case may be, shall not be included in this clause (11), plus
(12): exploration expenses or costs (to the extent Holdings adopts the "successful efforts" method), and

less, without duplication, to the extent the same increased Consolidated Net Income,

(13): the sum of (x) the amount of deferred revenues that are amortized during such period and are attributable to reserves that are subject to Volumetric Production Payments and (y) amounts recorded in accordance with GAAP as repayments of principal and interest pursuant to Dollar-Denominated Production Payments;
(14): non-cash items increasing Consolidated Net Income for such period (excluding the recognition of deferred revenue or any items which represent the reversal of any accrual of, or cash reserve for, anticipated cash charges that reduced EBITDA in any prior period and any items for which cash was received in a prior period).

"Equity Interests" means Capital Stock and all warrants, options or other rights to acquire Capital Stock (but excluding any debt security that is convertible into, or exchangeable for, Capital Stock).

"Equity Offering" means any public or private sale after the Issue Date of common Capital Stock or Preferred Stock of Holdings or any direct or indirect parent of Holdings, as applicable (other than Disqualified Stock), other than:

(1): public offerings with respect to Holdings' or such direct or indirect parent's common stock registered on Form S-4 or Form S-8;
(2): issuances to any Subsidiary of Holdings; and
(3): any such public or private sale that constitutes an Excluded Contribution.

"Exchange Act" means the Securities Exchange Act of 1934, as amended, and the rules and regulations of the SEC promulgated thereunder.

"Excluded Contributions" means the Cash Equivalents or other assets (valued at their Fair Market Value as determined in good faith by senior management or the Board of Directors of Holdings) received by Holdings after the Issue Date from:

(1): contributions to its common equity capital, and
(2): the sale (other than to a Subsidiary of Holdings or to any Subsidiary management equity plan or stock option plan or any other management or employee benefit plan or agreement) of Capital Stock (other than Disqualified Stock and Designated Preferred Stock) of Holdings,

in each case designated as Excluded Contributions pursuant to an Officers' Certificate on or promptly after the date such capital contributions are made or the date such Capital Stock is sold, as the case

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may be;provided, that $3,200 million of Cash Equivalents received by Holdings from the Equity Investors on or prior to May 24, 2012 to fund the Acquisition shall not be permitted to be designated an Excluded Contribution.

"Excluded Subsidiary" means (a) any Unrestricted Subsidiary, (b) any Subsidiary that is not a Wholly Owned Subsidiary, (c) any Foreign Subsidiary, (d) any Domestic Subsidiary (i) that owns no material assets (directly or through its Subsidiaries) other than equity interests of one or more Foreign Subsidiaries that are "controlled foreign corporations" within the meaning of Section 957 of the Code ("CFCs") or (ii) that is a direct or indirect Subsidiary of a Foreign Subsidiary, (e) any Receivables Subsidiary and (f) any Subsidiary (other than a Significant Subsidiary) that (i) did not, as of the last day of the fiscal quarter of Holdings most recently ended, have assets with a value in excess of 5.0% of the Total Assets or revenues representing in excess of 5.0% of total revenues of Holdings and the Restricted Subsidiaries on a consolidated basis as of such date and (ii) taken together with all other such Subsidiaries as of the last day of the fiscal quarter of Holdings most recently ended, did not have assets with a value in excess of 10.0% of the Total Assets or revenues representing in excess of 10.0% of total revenues of Holdings and the Restricted Subsidiaries on a consolidated basis as of such date.

"Existing Senior Notes" means (i) the Issuers' 9.375% Senior Notes due 2020 issued on April 24, 2012 (including exchange notes issued in exchange therefor pursuant to a registration rights agreement dated April 24, 2012) pursuant to the Indenture dated as of April 24, 2012 by and among the Issuers, the Subsidiary Guarantors party thereto, Wilmington Trust, National Association, as trustee, as it may be amended, restated, supplemented or otherwise modified from time to time in accordance with the terms thereof and (ii) the Issuers' 7.750% Senior Notes due 2022 issued on August 13, 2012 (including exchange notes issued in exchange therefor pursuant to a registration rights agreement dated August 13, 2012) pursuant to the Indenture dated as of August 13, 2012 by and among the Issuers, the Subsidiary Guarantors party thereto, Wilmington Trust, National Association, as trustee, as it may be amended, restated, supplemented or otherwise modified from time to time in accordance with the terms thereof.

"Fair Market Value" means, with respect to any asset or property, the price which could be negotiated in an arm's-length transaction, for cash, between a willing seller and a willing and able buyer, neither of whom is under undue pressure or compulsion to complete the transaction.

"Farm-In Agreement" means an agreement whereby a Person agrees to pay all or a share of the drilling, completion or other expenses of one or more exploratory or development wells (which agreement may be subject to a maximum payment obligation, after which expenses are shared in accordance with the working or participation interests therein or in accordance with the agreement of the parties) or perform the drilling, completion or other operation on such well or wells as all or a part of the consideration provided in exchange for an ownership interest in an Oil and Gas Property.

"Farm-Out Agreement" means a Farm-In Agreement, viewed from the standpoint of the party that transfers an ownership interest to another.

"Fixed Charge Coverage Ratio" means, with respect to any Person for any period, the ratio of EBITDA of such Person for such period to the Fixed Charges of such Person for such period. In the event that Holdings or any of its Restricted Subsidiaries Incurs, repays, repurchases or redeems any Indebtedness (other than in the case of any Qualified Receivables Financing, in which case interest expense shall be computed based upon the average daily balance of such Indebtedness during the applicable period) or issues, repurchases or redeems Disqualified Stock or Preferred Stock subsequent to the commencement of the period for which the Fixed Charge Coverage Ratio is being calculated but prior to the event for which the calculation of the Fixed Charge Coverage Ratio is made (the "Calculation Date"), then the Fixed Charge Coverage Ratio shall be calculated giving pro forma effect to such Incurrence, repayment, repurchase or redemption of Indebtedness, or such issuance, repurchase or redemption of Disqualified Stock or Preferred Stock, as if the same had occurred at the beginning

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of the applicable four-quarter period; provided that Holdings may elect pursuant to an Officers' Certificate delivered to the Trustee to treat all or any portion of the commitment under any Indebtedness as being Incurred at such time, in which case any subsequent Incurrence of Indebtedness under such commitment shall not be deemed, for purposes of this calculation, to be an Incurrence at such subsequent time.

For purposes of making the computation referred to above, Investments, acquisitions, dispositions, mergers, amalgamations, consolidations and discontinued operations (as determined in accordance with GAAP), in each case with respect to an operating unit of a business, and any operational changes that Holdings or any Restricted Subsidiary has determined to make and/or made during the four-quarter reference period or subsequent to such reference period and on or prior to or simultaneously with the Calculation Date shall be calculated on a pro forma basis assuming that all such Investments, acquisitions, dispositions, mergers, amalgamations, consolidations, discontinued operations and other operational changes (and the change of any associated fixed charge obligations and the change in EBITDA resulting therefrom) had occurred on the first day of the four-quarter reference period. If since the beginning of such period any Person that subsequently became a Restricted Subsidiary or was merged with or into Holdings or any Restricted Subsidiary since the beginning of such period shall have made any Investment, acquisition, disposition, merger, consolidation, amalgamation, discontinued operation or operational change, in each case with respect to an operating unit of a business, that would have required adjustment pursuant to this definition, then the Fixed Charge Coverage Ratio shall be calculated giving pro forma effect thereto for such period as if such Investment, acquisition, disposition, discontinued operation, merger, amalgamation, consolidation or operational change had occurred at the beginning of the applicable four-quarter period. If since the beginning of such period any Restricted Subsidiary is designated an Unrestricted Subsidiary or any Unrestricted Subsidiary is designated a Restricted Subsidiary, then the Fixed Charge Coverage Ratio shall be calculated giving pro forma effect thereto for such period as if such designation had occurred at the beginning of the applicable four-quarter period.

For purposes of this definition, whenever pro forma effect is to be given to any event, the pro forma calculations shall be made in good faith by a responsible financial or accounting officer of Holdings. Any such pro forma calculation may include adjustments appropriate, in the reasonable good faith determination of Holdings as set forth in an Officers' Certificate, to reflect (1) operating expense reductions and other operating improvements or synergies reasonably expected to result from the applicable event, and (2) all adjustments of the nature used in connection with the calculation of "Adjusted EBITDAX" as set forth in "Summary Historical and Consolidated Financial Data" under "Summary" in the offering memorandum related to the initial notes dated May 28, 2015 to the extent such adjustments, without duplication, continue to be applicable to such four-quarter period.

If any Indebtedness bears a floating rate of interest and is being given pro forma effect, the interest on such Indebtedness shall be calculated as if the rate in effect on the Calculation Date had been the applicable rate for the entire period (taking into account any Hedging Obligations applicable to such Indebtedness if such Hedging Obligation has a remaining term in excess of 12 months). Interest on a Capitalized Lease Obligation shall be deemed to accrue at an interest rate reasonably determined by a responsible financial or accounting officer of Holdings to be the rate of interest implicit in such Capitalized Lease Obligation in accordance with GAAP. For purposes of making the computation referred to above, interest on any Indebtedness under a revolving credit facility computed on a pro forma basis shall be computed based upon the average daily balance of such Indebtedness during the applicable period. Interest on Indebtedness that may optionally be determined at an interest rate based upon a factor of a prime or similar rate, a Eurocurrency interbank offered rate, or other rate, shall be deemed to have been based upon the rate actually chosen, or, if none, then based upon such optional rate chosen as Holdings may designate.

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For purposes of this definition, any amount in a currency other than U.S. dollars will be converted to U.S. dollars based on the average exchange rate for such currency for the most recent twelve month period immediately prior to the date of determination in a manner consistent with that used in calculating EBITDA for the applicable period.

"Fixed Charges" means, with respect to any Person for any period, the sum, without duplication, of: (1) Consolidated Interest Expense (excluding amortization or write-off of deferred financing costs) of such Person for such period, and (2) all cash dividend payments (excluding items eliminated in consolidation) on any series of Preferred Stock or Disqualified Stock of such Person and its Restricted Subsidiaries.

"Foreign Subsidiary" means a Restricted Subsidiary not organized or existing under the laws of the United States of America or any state thereof or the District of Columbia.

"GAAP" means generally accepted accounting principles in the United States set forth in the opinions and pronouncements of the Accounting Principles Board of the American Institute of Certified Public Accountants and statements and pronouncements of the Financial Accounting Standards Board or in such other statements by such other entity as have been approved by a significant segment of the accounting profession, which are in effect on the Issue Date. For the purposes of the indenture, the term "consolidated" with respect to any Person shall mean such Person consolidated with its Restricted Subsidiaries, and shall not include any Unrestricted Subsidiary, but the interest of such Person in an Unrestricted Subsidiary will be accounted for as an Investment.

"guarantee" means a guarantee (other than by endorsement of negotiable instruments for collection in the ordinary course of business), direct or indirect, in any manner (including, without limitation, letters of credit and reimbursement agreements in respect thereof), of all or any part of any Indebtedness or other obligations.

"Hedging Obligations" means, with respect to any Person, the obligations of such Person under:

(1): currency exchange, interest rate or commodity swap agreements (including commodity swaps, commodity options, forward commodity contracts, basis differential swaps, spot contracts, fixed-price physical delivery contracts or other similar agreements or arrangements in respect of Hydrocarbons), currency exchange, interest rate or commodity cap agreements and currency exchange, interest rate or commodity collar agreements; and
(2): other agreements or arrangements designed to protect such Person against fluctuations in currency exchange, interest rates or commodity prices.

Notwithstanding the foregoing, agreements or obligations to physically sell any commodity at any index-based price shall not be considered Hedging Obligations.

"holder" or "noteholder" means the Person in whose name a note is registered on the registrar's books.

"Holdings" means EP Energy LLC, together with its successors or assigns.

"Hydrocarbons" means oil, natural gas, casinghead gas, drip gasoline, natural gasoline, condensate, distillate, liquid hydrocarbons, gaseous hydrocarbons and all constituents, elements or compounds thereof and products refined or processed therefrom.

"Incur" means issue, assume, guarantee, incur or otherwise become liable for;provided,however, that any Indebtedness or Capital Stock of a Person existing at the time such person becomes a Subsidiary (whether by merger, amalgamation, consolidation, acquisition or otherwise) shall be deemed to be Incurred by such Person at the time it becomes a Subsidiary.

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"Indebtedness" means, with respect to any Person:

(1): the principal and premium (if any) of any indebtedness of such Person, whether or not contingent, (a) in respect of borrowed money, (b) evidenced by bonds, notes, debentures or similar instruments or letters of credit or bankers' acceptances (or, without duplication, reimbursement agreements in respect thereof), (c) representing the deferred and unpaid purchase price of any property (except any such balance that constitutes (i) a trade payable or similar obligation to a trade creditor Incurred in the ordinary course of business, (ii) any earn-out obligations until such obligation becomes a liability on the balance sheet of such Person in accordance with GAAP and (iii) liabilities accrued in the ordinary course of business), which purchase price is due more than twelve months after the date of placing the property in service or taking delivery and title thereto, (d) in respect of Capitalized Lease Obligations, or (e) representing any Hedging Obligations, if and to the extent that any of the foregoing indebtedness would appear as a liability on a balance sheet (excluding the footnotes thereto) of such Person prepared in accordance with GAAP;
(2): to the extent not otherwise included, any obligation of such Person to be liable for, or to pay, as obligor, guarantor or otherwise, the obligations referred to in clause (1) of another Person (other than by endorsement of negotiable instruments for collection in the ordinary course of business); and
(3): to the extent not otherwise included, Indebtedness of another Person secured by a Lien on any asset owned by such Person (whether or not such Indebtedness is assumed by such Person);provided,however, that the amount of such Indebtedness will be the lesser of: (a) the Fair Market Value (as determined in good faith by Holdings) of such asset at such date of determination, and (b) the amount of such Indebtedness of such other Person;

provided,however, that notwithstanding the foregoing, Indebtedness shall be deemed not to include (1) Contingent Obligations incurred in the ordinary course of business and not in respect of borrowed money; (2) deferred or prepaid revenues; (3) purchase price holdbacks in respect of a portion of the purchase price of an asset to satisfy warranty or other unperformed obligations of the respective seller; (4) Obligations under or in respect of Qualified Receivables Financing; (5) obligations under the Acquisition Documents; (6) Production Payments and Reserve Sales; (7) any obligation of a Person in respect of a Farm-In Agreement or similar arrangement whereby such Person agrees to pay all or a share of the drilling, completion or other expenses of an exploratory or development well (which agreement may be subject to a maximum payment obligation, after which expenses are shared in accordance with the working or participation interest therein or in accordance with the agreement of the parties) or perform the drilling, completion or other operation on such well in exchange for an ownership interest in an oil or gas property; (8) any obligations under Hedging Obligations;provided that such agreements are entered into for bona fide hedging purposes of Holdings or its Restricted Subsidiaries (as determined in good faith by the board of directors or senior management of Holdings, whether or not accounted for as a hedge in accordance with GAAP) and, in the case of any foreign exchange contract, currency swap agreement, futures contract, option contract or other similar agreement, such agreements are related to business transactions of Holdings or its Restricted Subsidiaries entered into in the ordinary course of business and, in the case of any interest rate protection agreement, interest rate future agreement, interest rate option agreement, interest rate swap agreement, interest rate cap agreement, interest rate collar agreement, interest rate hedge agreement or other similar agreement or arrangement, such agreements substantially correspond in terms of notional amount, duration and interest rates, as applicable, to Indebtedness of Holdings or its Restricted Subsidiaries Incurred without violation of the indenture; and (9) in-kind obligations relating to net oil, natural gas liquids or natural gas balancing positions arising in the ordinary course of business.

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Notwithstanding anything in the indenture to the contrary, Indebtedness shall not include, and shall be calculated without giving effect to, the effects of Statement of Financial Accounting Standards No. 133 and related interpretations to the extent such effects would otherwise increase or decrease an amount of Indebtedness for any purpose under the indenture as a result of accounting for any embedded derivatives created by the terms of such Indebtedness; and any such amounts that would have constituted Indebtedness under the indenture but for the application of this sentence shall not be deemed an Incurrence of Indebtedness under the indenture.

"Independent Financial Advisor" means an accounting, appraisal or investment banking firm or consultant, in each case of nationally recognized standing, that is, in the good faith determination of Holdings, qualified to perform the task for which it has been engaged.

"Investment Grade Rating" means a rating equal to or higher than Baa3 (or the equivalent) by Moody's and BBB– (or the equivalent) by S&P, or an equivalent rating by any other Rating Agency.

"Investment Grade Securities" means:

(1): securities issued or directly and fully guaranteed or insured by the U.S. government or any agency or instrumentality thereof (other than Cash Equivalents),
(2): securities that have a rating equal to or higher than Baa3 (or equivalent) by Moody's and BBB– (or equivalent) by S&P, but excluding any debt securities or loans or advances between and among Holdings and its Subsidiaries,
(3): investments in any fund that invests exclusively in investments of the type described in clauses (1) and (2) which fund may also hold immaterial amounts of cash pending investment and/or distribution, and
(4): corresponding instruments in countries other than the United States customarily utilized for high quality investments and in each case with maturities not exceeding two years from the date of acquisition.

"Investments" means, with respect to any Person, all investments by such Person in other Persons (including Affiliates) in the form of loans (including guarantees), advances or capital contributions (excluding accounts receivable, trade credit and advances to customers and commission, travel and similar advances to officers, employees and consultants made in the ordinary course of business and any assets or securities received in satisfaction or partial satisfaction thereof from financially troubled account debtors to the extent reasonably necessary in order to prevent or limit loss and any prepayments and other credits to suppliers made in the ordinary course of business), purchases or other acquisitions for consideration of Indebtedness, Equity Interests or other securities issued by any other Person and investments that are required by GAAP to be classified on the balance sheet of such Person in the same manner as the other investments included in this definition to the extent such transactions involve the transfer of cash or other property. For purposes of the definition of "Unrestricted Subsidiary" and the covenant described under "—Certain Covenants—Limitation on Restricted Payments":

(1)

"Investments" shall include the portion (proportionate to Holdings' equity interest in such Subsidiary) of the Fair Market Value (as determined in good faith by Holdings) of the net assets of a Subsidiary of Holdings at the time that such Subsidiary is designated an Unrestricted Subsidiary;provided,however, that upon a redesignation of such Subsidiary as a Restricted Subsidiary, Holdings shall be deemed to continue to have a permanent "Investment" in an Unrestricted Subsidiary equal to an amount (if positive) equal to:

(a): Holdings' "Investment" in such Subsidiary at the time of such redesignation less

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(b): the portion (proportionate to Holdings' equity interest in such Subsidiary) of the Fair Market Value (as determined in good faith by Holdings) of the net assets of such Subsidiary at the time of such redesignation; and

(2): any property transferred to or from an Unrestricted Subsidiary shall be valued at its Fair Market Value (as determined in good faith by Holdings) at the time of such transfer, in each case as determined in good faith by the Board of Directors of Holdings.

"Issue Date" means the date on which the notes are originally issued.

"Lien" means, with respect to any asset, any mortgage, lien, pledge, charge, security interest or similar encumbrance of any kind in respect of such asset, whether or not filed, recorded or otherwise perfected under applicable law (including any conditional sale or other title retention agreement, any lease in the nature thereof, any option or other agreement to sell or give a security interest in and any filing of or agreement to give any financing statement under the Uniform Commercial Code (or equivalent statutes) of any jurisdiction);provided that in no event shall an operating lease or an agreement to sell be deemed to constitute a Lien.

"Management Group" means the group consisting of the directors, managers, executive officers and other management personnel of Holdings or any direct or indirect parent of Holdings, as the case may be, on the Issue Date together with (1) any new directors or managers whose election by such boards of directors or managers or whose nomination for election by the shareholders of Holdings or any direct or indirect parent of Holdings, as applicable, was approved by a vote of a majority of the directors or managers of Holdings or any direct or indirect parent of Holdings, as applicable, then still in office who were either directors or managers on the Issue Date or whose election or nomination was previously so approved and (2) executive officers and other management personnel of Holdings or any direct or indirect parent of Holdings, as applicable, hired at a time when the directors or managers on the Issue Date together with the directors or managers so approved constituted a majority of the directors or managers of Holdings or any direct or indirect parent of Holdings, as applicable.

"Moody's" means Moody's Investors Service, Inc. or any successor to the rating agency business thereof.

"Net Income" means, with respect to any Person, the net income (loss) of such Person and its Restricted Subsidiaries, determined in accordance with GAAP and before any reduction in respect of Preferred Stock dividends.

"Net Proceeds" means the aggregate cash proceeds received by Holdings or any Restricted Subsidiary in respect of any Asset Sale (including, without limitation, any cash received in respect of or upon the sale or other disposition of any Designated Non-cash Consideration received in any Asset Sale and any cash payments received by way of deferred payment of principal pursuant to a note or installment receivable or otherwise, but only as and when received, but excluding the assumption by the acquiring person of Indebtedness relating to the disposed assets or other consideration received in any other non-cash form), net of the direct costs relating to such Asset Sale and the sale or disposition of such Designated Non-cash Consideration (including, without limitation, legal, accounting and investment banking fees, and brokerage and sales commissions), and any relocation expenses Incurred as a result thereof, taxes paid or payable as a result thereof (including Tax Distributions and after taking into account any available tax credits or deductions and any tax sharing arrangements related solely to such disposition), amounts required to be applied to the repayment of principal, premium (if any) and interest on Indebtedness required (other than pursuant to the second paragraph of the covenant described under "—Certain Covenants—Asset Sales") to be paid as a result of such transaction, amounts paid in connection with the termination of Hedging Obligations related to Indebtedness repaid with such proceeds or hedging oil, natural gas and natural gas liquid production in notional volumes corresponding to the Oil and Gas Properties subject to such Asset Sale, and any

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deduction of appropriate amounts to be provided by Holdings as a reserve in accordance with GAAP against any liabilities associated with the asset disposed of in such transaction and retained by Holdings after such sale or other disposition thereof, including, without limitation, pension and other post-employment benefit liabilities and liabilities related to environmental matters or against any indemnification obligations associated with such transaction.

"Net Working Capital" means (a) all current assets of the Company and its Restricted Subsidiaries, except current assets from commodity price risk management activities arising in the ordinary course of the Oil and Gas Business less (b) all current liabilities of the Company and its Restricted Subsidiaries, except current liabilities (i) associated with asset retirement obligations relating to Oil and Gas Properties, (ii) included in Indebtedness and (iii) any current liabilities from commodity price risk management activities arising in the ordinary course of the Oil and Gas Business, in each case as set forth in the consolidated financial statements of the Company prepared in accordance with GAAP.

"Notes Obligations" means Obligations in respect of the notes and the indenture, including, for the avoidance of doubt, Obligations in respect of exchange notes and guarantees thereof.

"Obligations" means any principal, interest, penalties, fees, indemnifications, reimbursements (including, without limitation, reimbursement obligations with respect to letters of credit and bankers' acceptances), damages and other liabilities payable under the documentation governing any Indebtedness;provided that Obligations with respect to the notes shall not include fees or indemnifications in favor of third parties other than the Trustee and the holders of the notes.

"Officer" means the Chairman of the Board, Chief Executive Officer, Chief Financial Officer, President, any Executive Vice President, Senior Vice President or Vice President, the Treasurer or the Secretary of Holdings.

"Officers' Certificate" means a certificate signed on behalf of Holdings by two Officers of Holdings, one of whom must be the principal executive officer, the principal financial officer, the treasurer or the principal accounting officer of Holdings, which meets the requirements set forth in the indenture.

"Oil and Gas Business" means:

(1): the business of acquiring, exploring, exploiting, developing, producing, operating and disposing of interests in oil, natural gas, natural gas liquids, liquefied natural gas and other Hydrocarbons and mineral properties or products produced in association with any of the foregoing;
(2): the business of gathering, marketing, distributing, treating, processing, storing, refining, selling and transporting of any production from such interests or properties and products produced in association therewith and the marketing of oil, natural gas, other Hydrocarbons and minerals obtained from unrelated Persons;
(3): any other related energy business, including power generation and electrical transmission business, directly or indirectly, from oil, natural gas and other Hydrocarbons and minerals produced substantially from properties in which Holdings or its Restricted Subsidiaries, directly or indirectly, participate;
(4): any business relating to oil field sales and service; and
(5): any business or activity relating to, arising from, or necessary, appropriate, incidental or ancillary to the activities described in the foregoing clauses (1) through (4) of this definition.

"Oil and Gas Properties" means all properties, including equity or other ownership interests therein, owned by a Person which contain or are believed to contain oil and gas reserves or other reserves of Hydrocarbons.

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"Opinion of Counsel" means a written opinion from legal counsel who is acceptable to the Trustee. The counsel may be an employee of or counsel to Holdings.

"Pari Passu Indebtedness" means: (a) with respect to an Issuer, the notes and any Indebtedness which ranks pari passu in right of payment to the notes; and (b) with respect to any Subsidiary Guarantor, its Subsidiary Guarantee and any Indebtedness which ranks pari passu in right of payment to such Subsidiary Guarantor's Subsidiary Guarantee.

"Permitted Business Investment" means any Investment and/or expenditure of a nature that is or shall have become customary in the Oil and Gas Business generally or in the geographic region in which such activities occur, including investments or expenditures for actively exploiting, exploring for, acquiring, developing, producing, processing, gathering, marketing, distributing, storing, or transporting oil, natural gas or other Hydrocarbons and minerals (including with respect to plugging and abandonment) through agreements, transactions, interests or arrangements which permit one to share risks or costs, comply with regulatory requirements regarding local ownership or satisfy other objectives customarily achieved through the conduct of the Oil and Gas Business jointly with third parties, including:

(1): Investments in ownership interests (including equity or other ownership interests) in oil, natural gas, other Hydrocarbons and minerals properties, liquefied natural gas facilities, processing facilities, gathering systems, pipelines, storage facilities or related systems or ancillary real property interests;
(2): Investments in the form of or pursuant to operating agreements, working interests, royalty interests, mineral leases, processing agreements, Farm-In Agreements, Farm-Out Agreements, contracts for the sale, transportation or exchange of oil, natural gas, other Hydrocarbons and minerals, production sharing agreements, participation agreements, development agreements, area of mutual interest agreements, unitization agreements, pooling agreements, joint bidding agreements, service contracts, joint venture agreements, partnership agreements (whether general or limited), subscription agreements, stock purchase agreements, stockholder agreements and other similar agreements (including for limited liability companies) with third parties; and
(3): Investments in direct or indirect ownership interests in drilling rigs and related equipment, including, without limitation, transportation equipment.

"Permitted Holders" means, at any time, each of (i) the Sponsors, (ii) the Management Group, (iii) any Person that has no material assets other than the Capital Stock of Holdings and, directly or indirectly, holds or acquires 100% of the total voting power of the Voting Stock of Holdings, and of which no other Person or group (within the meaning of Section 13(d)(3) or Section 14(d)(2) of the Exchange Act, or any successor provision), other than any of the other Permitted Holders specified in clauses (i) and (ii) above, holds more than 50% of the total voting power of the Voting Stock thereof and (iv) any group (within the meaning of Section 13(d)(3) or Section 14(d)(2) of the Exchange Act, or any successor provision) the members of which include any of the Permitted Holders specified in clauses (i) and (ii) above and that, directly or indirectly, hold or acquire beneficial ownership of the Voting Stock of Holdings (a "Permitted Holder Group"), so long as (1) each member of the Permitted Holder Group has voting rights proportional to the percentage of ownership interests held or acquired by such member and (2) no Person or other "group" (other than Permitted Holders specified in clauses (i) and (ii) above) beneficially owns more than 50% on a fully diluted basis of the Voting Stock held by the Permitted Holder Group. Any Person or group whose acquisition of beneficial ownership constitutes a Change of Control in respect of which a Change of Control Offer is made in accordance with the requirements of the indenture will thereafter, together with its Affiliates, constitute an additional Permitted Holder.

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"Permitted Investments" means:

(1): any Investment in Holdings or any Restricted Subsidiary;
(2): any Investment in Cash Equivalents or Investment Grade Securities;
(3): any Investment by Holdings or any Restricted Subsidiary in a Person if as a result of such Investment (a) such Person becomes a Restricted Subsidiary, or (b) such Person, in one transaction or a series of related transactions, is merged, consolidated or amalgamated with or into, or transfers or conveys all or substantially all of its assets to, or is liquidated into, Holdings or a Restricted Subsidiary;
(4): any Investment in securities or other assets not constituting Cash Equivalents and received in connection with an Asset Sale made pursuant to the provisions of "—Certain Covenants—Asset Sales" or any other disposition of assets not constituting an Asset Sale;
(5): any Investment existing on, or made pursuant to binding commitments existing on, the Issue Date or an Investment consisting of any extension, modification or renewal of any Investment existing on the Issue Date;provided that the amount of any such Investment may be increased (x) as required by the terms of such Investment as in existence on the Issue Date or (y) as otherwise permitted under the indenture;
(6): loans and advances to officers, directors, managers, employees or consultants of Holdings or any Restricted Subsidiary, taken together with all other advances made pursuant to this clause (6), not to exceed $25.0 million at any one time outstanding;
(7): any Investment acquired by Holdings or any Restricted Subsidiary (a) in exchange for any other Investment or accounts receivable held by Holdings or such Restricted Subsidiary in connection with or as a result of a bankruptcy, workout, reorganization or recapitalization of Holdings of such other Investment or accounts receivable, or (b) as a result of a foreclosure by Holdings or any Restricted Subsidiary with respect to any secured Investment or other transfer of title with respect to any secured Investment in default;
(8): Hedging Obligations permitted under clause (j) of the second paragraph of the covenant described under "—Certain Covenants—Limitation on Incurrence of Indebtedness and Issuance of Disqualified Stock and Preferred Stock";
(9): any Investment by Holdings or any Restricted Subsidiary in a Similar Business having an aggregate Fair Market Value (as determined in good faith by Holdings), taken together with all other Investments made pursuant to this clause (9) that are at that time outstanding, not to exceed the greater of (x) $350.0 million and (y) 5% of Adjusted Consolidated Net Tangible Assets at the time of such Investment,plus an amount equal to any returns (including dividends, interest, distributions, returns of principal, profits on sale, repayments, income and similar amounts) actually received in respect of any such Investment made pursuant to this clause (9) (with the Fair Market Value of each Investment being measured at the time made and without giving effect to subsequent changes in value);provided,however, that if any Investment pursuant to this clause (9) is made in any Person that is not Holdings or a Restricted Subsidiary at the date of the making of such Investment and such Person becomes Holdings or a Restricted Subsidiary after such date, such Investment shall thereafter be deemed to have been made pursuant to clause (1) above and shall cease to have been made pursuant to this clause (9) for so long as such Person continues to be Holdings or a Restricted Subsidiary;
(10): additional Investments by Holdings or any Restricted Subsidiary having an aggregate Fair Market Value (as determined in good faith by Holdings), taken together with all other Investments made pursuant to this clause (10) that are at that time outstanding, not to exceed

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the greater of (x) $350.0 million and (y) 5% of Adjusted Consolidated Net Tangible Assets at the time of such Investment,plus an amount equal to any returns (including dividends, interest, distributions, returns of principal, profits on sale, repayments, income and similar amounts) actually received in respect of any such Investment made pursuant to this clause (10) (with the Fair Market Value of each Investment being measured at the time made and without giving effect to subsequent changes in value);provided,however, that if any Investment pursuant to this clause (10) is made in any Person that is not Holdings or a Restricted Subsidiary at the date of the making of such Investment and such Person becomes Holdings or a Restricted Subsidiary after such date, such Investment shall thereafter be deemed to have been made pursuant to clause (1) above and shall cease to have been made pursuant to this clause (10) for so long as such Person continues to be Holdings or a Restricted Subsidiary;

(11): loans and advances to officers, directors, managers or employees for business-related travel expenses, moving expenses, payroll payments and expenses and other similar expenses, in each case Incurred in the ordinary course of business or consistent with past practice or to fund such person's purchase of Equity Interests of Holdings or any direct or indirect parent of Holdings;
(12): Investments the payment for which consists of Equity Interests of Holdings (other than Disqualified Stock) or any direct or indirect parent of Holdings, as applicable;provided,however, that such Equity Interests will not increase the amount available for Restricted Payments under clause (3) of the definition of Cumulative Credit contained in "—Certain Covenants—Limitation on Restricted Payments";
(13): any transaction to the extent it constitutes an Investment that is permitted by and made in accordance with the provisions of the second paragraph of the covenant described under "—Certain Covenants—Transactions with Affiliates" (except transactions described in clauses (2), (4), (6), (9)(b) and (16) of such paragraph);
(14): Investments consisting of the licensing or contribution of intellectual property pursuant to joint marketing arrangements with other Persons;
(15): (x) guarantees issued in accordance with the covenants described under "—Certain Covenants—Limitation on Incurrence of Indebtedness and Issuance of Disqualified Stock and Preferred Stock" and "—Certain Covenants—Future Subsidiary Guarantors," including, without limitation, any guarantee or other obligation issued or incurred under the Credit Agreement in connection with any letter of credit issued for the account of Holdings or any of its Subsidiaries (including with respect to the issuance of, or payments in respect of drawings under, such letters of credit) and (y) guarantees of performance or other obligations (other than Indebtedness) arising in the ordinary course in the Oil and Gas Business, including obligations under Hydrocarbon exploration, development, joint operating and related agreements and licenses, concessions or operating leases related to the Oil and Gas Business;
(16): Investments consisting of or to finance purchases and acquisitions of inventory, supplies, materials, services or equipment or purchases of contract rights or licenses or leases of intellectual property;
(17): any Investment in a Receivables Subsidiary or any Investment by a Receivables Subsidiary in any other Person in connection with a Qualified Receivables Financing, including Investments of funds held in accounts permitted or required by the arrangements governing such Qualified Receivables Financing or any related Indebtedness;
(18): any Investment in an entity which is not a Restricted Subsidiary to which a Restricted Subsidiary sells accounts receivable pursuant to a Receivable Financing;

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(19): additional Investments in joint ventures not to exceed, at any one time in the aggregate outstanding under this clause (19), $100.0 million,plus an amount equal to any returns (including dividends, interest, distributions, returns of principal, profits on sale, repayments, income and similar amounts) actually received in respect of any such Investment made pursuant to this clause (19) (with the Fair Market Value of each Investment being measured at the time such Investment is made and without giving effect to subsequent changes in value);provided,however, that if any Investment pursuant to this clause (19) is made in any Person that is not Holdings or a Restricted Subsidiary at the date of the making of such Investment and such Person becomes Holdings or a Restricted Subsidiary after such date, such Investment shall thereafter be deemed to have been made pursuant to clause (1) above and shall cease to have been made pursuant to this clause (19) for so long as such Person continues to be Holdings or a Restricted Subsidiary;
(20): Investments of a Restricted Subsidiary acquired after the Issue Date or of an entity merged into, amalgamated with, or consolidated with Holdings or a Restricted Subsidiary in a transaction that is not prohibited by the covenant described under "—Merger, Amalgamation, Consolidation or Sale of All or Substantially All Assets" after the Issue Date to the extent that such Investments were not made in contemplation of such acquisition, merger, amalgamation or consolidation and were in existence on the date of such acquisition, merger, amalgamation or consolidation;
(21): any Investment in any Subsidiary of Holdings or any joint venture in connection with intercompany cash management arrangements or related activities arising in the ordinary course of business; and
(22): Permitted Business Investments.

"Permitted Liens" means, with respect to any Person:

(1): pledges or deposits and other Liens granted by such Person under workmen's compensation laws, unemployment insurance laws or similar legislation, or good faith deposits in connection with bids, tenders, contracts (other than for the payment of Indebtedness) or leases to which such Person is a party, or deposits to secure plugging and abandonment obligations or public or statutory obligations of such Person or deposits of cash or U.S. government bonds to secure surety or appeal bonds to which such Person is a party, or deposits as security for contested taxes or import duties or for the payment of rent, in each case Incurred in the ordinary course of business;
(2): Liens imposed by law, such as landlord's, carriers', warehousemen's, mechanics', materialmen's, repairmen's, construction or other like Liens securing obligations that are not overdue by more than 30 days or that are being contested in good faith by appropriate proceedings or other Liens arising out of judgments or awards against such Person with respect to which such Person shall then be proceeding with an appeal or other proceedings for review;
(3): Liens for taxes, assessments or other governmental charges not yet overdue by more than 30 days or, if overdue by more than 30 days, are being contested in good faith by appropriate proceedings;
(4): Liens in favor of issuers of performance and surety bonds or bid bonds or with respect to other regulatory requirements or letters of credit, bankers' acceptances or similar obligations issued pursuant to the request of and for the account of such Person in the ordinary course of its business;

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(5)

minor survey exceptions, minor encumbrances, easements or reservations of, or rights of others for, licenses, rights-of-way, sewers, electric lines, telegraph and telephone lines and other similar purposes, servicing agreements, development agreements, site plan agreements and other similar encumbrances incurred in the ordinary course of business or zoning or other restrictions as to the use of real properties or Liens incidental to the conduct of the business of such Person or to the ownership of its properties which were not Incurred in connection with Indebtedness and which do not in the aggregate materially adversely affect the value of said properties or materially impair their use in the operation of the business of such Person;

(6)

(A) Liens on assets of a Restricted Subsidiary that is not a Subsidiary Guarantor securing Indebtedness of such Restricted Subsidiary permitted to be Incurred pursuant to the covenant described under "—Certain Covenants—Limitation on Incurrence of Indebtedness and Issuance of Disqualified Stock and Preferred Stock";

(B): Liens securing Indebtedness incurred under the Credit Agreement, including any letter of credit facility relating thereto, that was permitted to be incurred pursuant to clause (a) of the second paragraph of the covenant described under "—Certain Covenants—Limitation on Incurrence of Indebtedness and Issuance of Disqualified Stock and Preferred Stock";
(C): Liens securing Indebtedness incurred under the RBL Facility in excess of $2,000 million (and solely to the extent of such excess), including any letter of credit facility relating thereto, that was permitted to be incurred under the covenant described under "—Certain Covenants—Limitation on Incurrence of Indebtedness and Issuance of Disqualified Stock and Preferred Stock"; and
(D): Liens securing Indebtedness permitted to be Incurred pursuant to clause (b)(2), (d), (l), (p) or (t) of the second paragraph of the covenant described under "—Certain Covenants—Limitation on Incurrence of Indebtedness and Issuance of Disqualified Stock and Preferred Stock" (provided that in the case of clause (t), such Lien does not extend to the property or assets of any Subsidiary of Holdings other than a Restricted Subsidiary that is not a Subsidiary Guarantor);

(7)

Liens existing on the Issue Date (other than Liens in favor of the lenders under the Credit Agreement, the holders of the Secured Notes or the lenders under the Term Loan Facility);

(8)

Liens on assets, property or shares of stock of a Person at the time such Person becomes a Subsidiary (and such other assets, property or shares of stock subject to after-acquired property clauses in effect with respect to such Lien at the time of acquisition on property of the type that would have been subject to such Lien notwithstanding the occurrence of such acquisition);provided,however, that such Liens are not created or Incurred in connection with, or in contemplation of, such other Person becoming such a Subsidiary;provided,further,however, that such Liens may not extend to any other property owned by Holdings or any Restricted Subsidiary (other than such Person or its Restricted Subsidiary);

(9)

Liens on assets or property at the time Holdings or a Restricted Subsidiary acquired the assets or property, including any acquisition by means of a merger, amalgamation or consolidation with or into Holdings or any Restricted Subsidiary;provided,however, that such Liens (other than Liens to secure Indebtedness Incurred pursuant to clause (p) of the second paragraph of the covenant described under "—Certain Covenants—Limitation on Incurrence of Indebtedness and Issuance of Disqualified Stock and Preferred Stock") are not created or Incurred in connection with, or in contemplation of, such acquisition;provided,further,however, that the Liens (other than Liens to secure Indebtedness Incurred pursuant to clause (p) of the second paragraph of the covenant described under "—Certain Covenants—Limitation on Incurrence of Indebtedness and Issuance of Disqualified Stock and Preferred

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Stock") may not extend to any other property owned by Holdings or any Restricted Subsidiary (other than pursuant to after-acquired property clauses in effect with respect to such Lien at the time of acquisition on property of the type that would have been subject to such Lien notwithstanding the occurrence of such acquisition);

(10): Liens securing Indebtedness or other obligations of Holdings or a Restricted Subsidiary owing to Holdings or another Restricted Subsidiary permitted to be Incurred in accordance with the covenant described under "—Certain Covenants—Limitation on Incurrence of Indebtedness and Issuance of Disqualified Stock and Preferred Stock";
(11): Liens securing Hedging Obligations not incurred in violation of the indenture;provided that with respect to Hedging Obligations relating to Indebtedness, such Lien extends only to the property securing such Indebtedness;
(12): Liens on specific items of inventory or other goods and proceeds of any Person securing such Person's obligations in respect of documentary letters of credit, bank guarantees or bankers' acceptances issued or created for the account of such Person to facilitate the purchase, shipment or storage of such inventory or other goods;
(13): leases and subleases of real property which do not materially interfere with the ordinary conduct of the business of Holdings or any of the Restricted Subsidiaries;
(14): Liens arising from Uniform Commercial Code financing statement filings regarding operating leases or other obligations not constituting Indebtedness;
(15): Liens in favor of Holdings or any Subsidiary Guarantor;
(16): Liens on accounts receivable and related assets of the type specified in the definition of "Receivables Financing" Incurred in connection with a Qualified Receivables Financing;
(17): pledges and deposits and other Liens made in the ordinary course of business to secure liability to insurance carriers;
(18): Liens on the Equity Interests of Unrestricted Subsidiaries;
(19): leases or subleases, and licenses or sublicenses (including with respect to intellectual property) granted to others in the ordinary course of business;
(20): Liens to secure any refinancing, refunding, extension, renewal or replacement (or successive refinancings, refundings, extensions, renewals or replacements) as a whole, or in part, of any Indebtedness secured by any Lien referred to in the foregoing clauses (6), (7), (8), (9), (10), (11) and (15);provided,however, that (x) such new Lien shall be limited to all or part of the same property (including any after-acquired property to the extent it would have been subject to the original Lien) that secured the original Lien (plus improvements on and accessions to such property, proceeds and products thereof, customary security deposits and any other assets pursuant to the after-acquired property clauses to the extent such assets secured (or would have secured) the Indebtedness being refinanced, refunded, extended, renewed or replaced), and (y) the Indebtedness secured by such Lien at such time is not increased to any amount greater than the sum of (A) the outstanding principal amount (or accreted value, if applicable) or, if greater, committed amount of the Indebtedness described under clauses (6), (7), (8), (9), (10), (11) and (15) at the time the original Lien became a Permitted Lien under the indenture, and (B) unpaid accrued interest and premiums (including tender premiums) and (C) an amount necessary to pay any underwriting discounts, defeasance costs, commissions, fees and expenses related to such refinancing, refunding, extension, renewal or replacement;provided further, however, that in the case of any Liens to secure any refinancing, refunding, extension or renewal of Indebtedness secured by a Lien referred to in

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clause (6)(B), the principal amount of any Indebtedness Incurred for such refinancing, refunding, extension or renewal shall be deemed secured by a Lien under clause (6)(B) and not this clause (20) for purposes of determining the principal amount of Indebtedness outstanding under clause (6)(B);

(21): Liens on equipment of Holdings or any Restricted Subsidiary granted in the ordinary course of business to Holdings' or such Restricted Subsidiary's client at which such equipment is located;
(22): judgment and attachment Liens not giving rise to an Event of Default and notices of lis pendens and associated rights related to litigation being contested in good faith by appropriate proceedings and for which adequate reserves have been made;
(23): Liens arising out of conditional sale, title retention, consignment or similar arrangements for the sale or purchase of goods entered into in the ordinary course of business;
(24): Liens incurred to secure cash management services or to implement cash pooling arrangements in the ordinary course of business;
(25): other Liens securing obligations the outstanding principal amount of which does not, taken together with the principal amount of all other obligations secured by Liens incurred under this clause (25) that are at that time outstanding, exceed the greater of $350.0 million and 5% Adjusted Consolidated Net Tangible Assets at the time of Incurrence;
(26): any encumbrance or restriction (including put and call arrangements) with respect to Capital Stock of any joint venture or similar arrangement securing obligations of such joint venture or pursuant to any joint venture or similar agreement;
(27): any amounts held by a trustee in the funds and accounts under an indenture securing any revenue bonds issued for the benefit of Holdings or any Restricted Subsidiary, under any indenture issued in escrow pursuant to customary escrow arrangements pending the release thereof, or under any indenture pursuant to customary discharge, redemption or defeasance provisions;
(28): Liens (i) arising by virtue of any statutory or common law provisions relating to banker's Liens, rights of set-off or similar rights and remedies as to deposit accounts or other funds maintained with a depository or financial institution, (ii) attaching to commodity trading accounts or other commodity brokerage accounts incurred in the ordinary course of business or (iii) encumbering reasonable customary initial deposits and margin deposits and similar Liens attaching to brokerage accounts incurred in the ordinary course of business and not for speculative purposes;
(29): Liens arising out of judgments or awards against such Person with respect to which such Person shall then be proceeding with any appeal or other proceedings for review;
(30): Liens (i) in favor of credit card companies pursuant to agreements therewith and (ii) in favor of customers;
(31): Liens in respect of Production Payments and Reserve Sales;
(32): Liens arising under Farm-Out Agreements, Farm-In Agreements, division orders, contracts for the sale, purchase, exchange, transportation, gathering or processing of Hydrocarbons, unitizations and pooling designations, declarations, orders and agreements, development agreements, joint venture agreements, partnership agreements, operating agreements, royalties, royalty trusts, master limited partnerships, working interests, net profits interests, joint interest billing arrangements, participation agreements, production sales contracts, area of mutual interest agreements, gas balancing or deferred production agreements, injection, repressuring

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and recycling agreements, salt water or other disposal agreements, seismic or geophysical permits or agreements, and other agreements which are customary in the Oil and Gas Business; provided, however, in all instances that such Liens are limited to the assets that are the subject of the relevant agreement, program, order, trust, partnership or contract;

(33): Liens on pipelines or pipeline facilities that arise by operation of law; and
(34): any (a) interest or title of a lessor or sublessor under any lease, liens reserved in oil, gas or other Hydrocarbons, minerals, leases for bonus, royalty or rental payments and for compliance with the terms of such leases; (b) restriction or encumbrance that the interest or title of such lessor or sublessor may be subject to (including, without limitation, ground leases or other prior leases of the demised premises, mortgages, mechanics' liens, tax liens and easements); or (c) subordination of the interest of the lessee or sublessee under such lease to any restrictions or encumbrance referred to in the preceding clause (b).

"Person" means any individual, corporation, partnership, limited liability company, joint venture, association, joint-stock company, trust, unincorporated organization, government or any agency or political subdivision thereof or any other entity.

"Preferred Stock" means any Equity Interest with preferential right of payment of dividends or upon liquidation, dissolution, or winding up.

"Production Payments and Reserve Sales" means the grant or transfer by Holdings or a Restricted Subsidiary to any Person of a royalty, overriding royalty, net profits interest, production payment (whether volumetric or dollar-denominated), partnership or other interest in Oil and Gas Properties, reserves or the right to receive all or a portion of the production or the proceeds from the sale of production attributable to such properties where the holder of such interest has recourse solely to such production or proceeds of production, subject to the obligation of the grantor or transferor to operate and maintain, or cause the subject interests to be operated and maintained, in a reasonably prudent manner or other customary standard or subject to the obligation of the grantor or transferor to indemnify for environmental, title or other matters customary in the Oil and Gas Business, including any such grants or transfers.

"Qualified Receivables Financing" means any Receivables Financing of a Receivables Subsidiary that meets the following conditions:

(1): the Board of Directors of Holdings shall have determined in good faith that such Qualified Receivables Financing (including financing terms, covenants, termination events and other provisions) is in the aggregate economically fair and reasonable to Holdings and the Receivables Subsidiary;
(2): all sales of accounts receivable and related assets to the Receivables Subsidiary are made at Fair Market Value (as determined in good faith by Holdings); and
(3): the financing terms, covenants, termination events and other provisions thereof shall be market terms (as determined in good faith by Holdings) and may include Standard Securitization Undertakings.

The grant of a security interest in any accounts receivable of Holdings or any Restricted Subsidiary (other than a Receivables Subsidiary) to secure Bank Indebtedness, Indebtedness in respect of the notes or any Refinancing Indebtedness with respect to the notes shall not be deemed a Qualified Receivables Financing.

"Rating Agency" means (1) each of Moody's and S&P and (2) if Moody's or S&P ceases to rate the notes for reasons outside of Holdings' control, a "nationally recognized statistical rating organization" within the meaning of Rule 15cs-1(c)(2)(vi)(F) under the Exchange Act selected by Holdings or any direct or indirect parent of Holdings as a replacement agency for Moody's or S&P, as the case may be.

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"RBL Facility" means the credit agreement dated as of May 24, 2012 by and among Holdings, the guarantors named therein, the financial institutions named therein, and JPMorgan Chase Bank, N.A., as administrative agent, as amended, restated, supplemented, waived, replaced (whether or not upon termination, and whether with the original lenders or other lenders), restructured, repaid, refunded, refinanced or otherwise modified from time to time pursuant to any amendment thereto or pursuant to a new loan agreement with other lenders, governed by a borrowing base set by the lenders, extending the maturity thereof, refinancing, replacing or otherwise restructuring all or any portion of the Indebtedness under such agreement or under any successor or replacement agreement or increasing the amount loaned thereunder or altering the maturity thereof.

"Receivables Fees" means distributions or payments made directly or by means of discounts with respect to any participation interests issued or sold in connection with, and all other fees paid to a Person that is not a Restricted Subsidiary in connection with, any Receivables Financing.

"Receivables Financing" means any transaction or series of transactions that may be entered into by Holdings or any of its Subsidiaries pursuant to which Holdings or any of its Subsidiaries may sell, convey or otherwise transfer to (a) a Receivables Subsidiary (in the case of a transfer by Holdings or any of its Subsidiaries); and (b) any other Person (in the case of a transfer by a Receivables Subsidiary), or may grant a security interest in, any accounts receivable (whether now existing or arising in the future) of Holdings or any of its Subsidiaries, and any assets related thereto including, without limitation, all collateral securing such accounts receivable, all contracts and all guarantees or other obligations in respect of such accounts receivable, proceeds of such accounts receivable and other assets which are customarily transferred or in respect of which security interests are customarily granted in connection with asset securitization transactions involving accounts receivable and any Hedging Obligations entered into by Holdings or any such Subsidiary in connection with such accounts receivable.

"Receivables Repurchase Obligation" means any obligation of a seller of receivables in a Qualified Receivables Financing to repurchase receivables arising as a result of a breach of a representation, warranty or covenant or otherwise, including as a result of a receivable or portion thereof becoming subject to any asserted defense, dispute, off-set or counterclaim of any kind as a result of any action taken by, any failure to take action by or any other event relating to the seller.

"Receivables Subsidiary" means a Wholly Owned Restricted Subsidiary (or another Person formed for the purposes of engaging in Qualified Receivables Financing with Holdings in which Holdings or any Subsidiary of Holdings makes an Investment and to which Holdings or any such Subsidiary transfers accounts receivable and related assets) which engages in no activities other than in connection with the financing of accounts receivable of Holdings and its Subsidiaries, all proceeds thereof and all rights (contractual or other), collateral and other assets relating thereto, and any business or activities incidental or related to such business, and which is designated by the Board of Directors of Holdings (as provided below) as a Receivables Subsidiary and:

(a): no portion of the Indebtedness or any other obligations (contingent or otherwise) of which (i) is guaranteed by Holdings or any other Subsidiary of Holdings (excluding guarantees of obligations (other than the principal of and interest on, Indebtedness) pursuant to Standard Securitization Undertakings), (ii) is recourse to or obligates Holdings or any other Subsidiary in any way other than pursuant to Standard Securitization Undertakings, or (iii) subjects any property or asset of Holdings or any other Subsidiary, directly or indirectly, contingently or otherwise, to the satisfaction thereof, other than pursuant to Standard Securitization Undertakings;
(b): with which neither Holdings nor any Subsidiary has any material contract, agreement, arrangement or understanding other than on terms which Holdings reasonably believes to be

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no less favorable to Holdings or such Subsidiary than those that might be obtained at the time from Persons that are not Affiliates of Holdings; and

(c): to which neither Holdings nor any Subsidiary has any obligation to maintain or preserve such entity's financial condition or cause such entity to achieve certain levels of operating results.

Any such designation by the Board of Directors of Holdings shall be evidenced to the Trustee by filing with the Trustee a certified copy of the resolution of the Board of Directors of Holdings giving effect to such designation and an Officers' Certificate certifying that such designation complied with the foregoing conditions.

"Restricted Cash" means cash and Cash Equivalents held by Restricted Subsidiaries that is contractually restricted from being distributed to Holdings, except for such cash and Cash Equivalents subject only to such restrictions that are contained in agreements governing Indebtedness permitted under the indenture and that is secured by such cash or Cash Equivalents.

"Restricted Investment" means an Investment other than a Permitted Investment.

"Restricted Subsidiary" means, with respect to any Person, any Subsidiary of such Person other than an Unrestricted Subsidiary of such Person. Unless otherwise indicated in this "Description of Exchange Notes," all references to Restricted Subsidiaries shall mean Restricted Subsidiaries of Holdings.

"Sale/Leaseback Transaction" means an arrangement relating to property now owned or hereafter acquired by Holdings or a Restricted Subsidiary whereby Holdings or such Restricted Subsidiary transfers such property to a Person and Holdings or such Restricted Subsidiary leases it from such Person, other than leases between Holdings and a Restricted Subsidiary or between Restricted Subsidiaries.

"S&P" means Standard & Poor's Ratings Group or any successor to the rating agency business thereof.

"SEC" means the Securities and Exchange Commission.

"Secured Indebtedness" means any Consolidated Total Indebtedness secured by a Lien.

"Secured Notes" means the Issuers' 6.875% Senior Secured Notes due 2019 issued on April 24, 2012 (including exchange notes issued in exchange therefor pursuant to a registration rights agreement dated April 24, 2012) pursuant to the Indenture dated as of April 24, 2012 by and among the Issuers, the Subsidiary Guarantors party thereto, Wilmington Trust, National Association, as trustee, as it may be amended, restated, supplemented or otherwise modified from time to time in accordance with the terms thereof.

"Securities Act" means the Securities Act of 1933, as amended, and the rules and regulations of the SEC promulgated thereunder.

"Significant Subsidiary" means any Restricted Subsidiary that would be a "Significant Subsidiary" of Holdings within the meaning of Rule 1-02 under Regulation S-X promulgated by the SEC (or any successor provision).

"Similar Business" means any business, the majority of whose revenues are derived from (i) the business or activities of Holdings and its Subsidiaries anticipated to be conducted as of the Issue Date, (ii) any business that is a natural outgrowth or a reasonable extension, development or expansion of any such business or any business similar, reasonably related, incidental, complementary or ancillary to any of the foregoing or (iii) any business that in Holdings' good faith business judgment constitutes a reasonable diversification of business conducted by Holdings and its Subsidiaries.

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"Sponsor Management Agreement" means the management agreement between certain of the management companies associated with the Sponsors, EP Energy Corporation, EP Energy Global LLC and EPE Acquisition, LLC.

"Sponsors" means (i) affiliates of each of Apollo Global Management, LLC, Access Industries, Inc. and Riverstone Holdings, L.P. and other investors party to that certain Interim Investors Agreement dated as of February 24, 2012 (the "Interim Investors Agreement") and any other investors that may become party to the Interim Investors Agreement prior to or upon the consummation of the Acquisition and any of their respective Affiliates other than any portfolio companies (collectively, the "Equity Investor") and (ii) any Person that forms a group (within the meaning of Section 13(d)(3) or Section 14(d)(2) of the Exchange Act, or any successor provision) with the Equity Investor;provided that the Equity Investor (x) owns a majority of the voting power and (y) controls a majority of the Board of Directors of Holdings.

"Standard Securitization Undertakings" means representations, warranties, covenants, indemnities and guarantees of performance entered into by Holdings or any Subsidiary thereof which Holdings has determined in good faith to be customary in a Receivables Financing including, without limitation, those relating to the servicing of the assets of a Receivables Subsidiary, it being understood that any Receivables Repurchase Obligation shall be deemed to be a Standard Securitization Undertaking.

"Stated Maturity" means, with respect to any security, the date specified in such security as the fixed date on which the final payment of principal of such security is due and payable, including pursuant to any mandatory redemption provision (but excluding any provision providing for the repurchase of such security at the option of the holder thereof upon the happening of any contingency beyond the control of the issuer unless such contingency has occurred).

"Subordinated Indebtedness" means (a) with respect to an Issuer, any Indebtedness of the Issuer which is by its terms subordinated in right of payment to the notes, and (b) with respect to any Subsidiary Guarantor, any Indebtedness of such Subsidiary Guarantor which is by its terms subordinated in right of payment to its Subsidiary Guarantee.

"Subsidiary" means, with respect to any Person, (1) any corporation, association or other business entity (other than a partnership, joint venture or limited liability company) of which more than 50% of the total voting power of shares of Capital Stock entitled (without regard to the occurrence of any contingency) to vote in the election of directors, managers or trustees thereof is at the time of determination owned or controlled, directly or indirectly, by such Person or one or more of the other Subsidiaries of that Person or a combination thereof, and (2) any partnership, joint venture or limited liability company of which (x) more than 50% of the capital accounts, distribution rights, total equity and voting interests or general and limited partnership interests, as applicable, are owned or controlled, directly or indirectly, by such Person or one or more of the other Subsidiaries of that Person or a combination thereof, whether in the form of membership, general, special or limited partnership interests or otherwise, and (y) such Person or any Subsidiary of such Person is a controlling general partner or otherwise controls such entity.

"Subsidiary Guarantee" means any guarantee of the obligations of the Issuers under the indenture and the notes by any Subsidiary Guarantor in accordance with the provisions of the indenture.

"Subsidiary Guarantor" means any Subsidiary that Incurs a Subsidiary Guarantee;provided that upon the release or discharge of such Person from its Subsidiary Guarantee in accordance with the indenture, such Subsidiary ceases to be a Subsidiary Guarantor.

"Tax Distributions" means any distributions described in clause (12) of the covenant entitled "—Certain Covenants—Limitation on Restricted Payments."

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"Term Loan Facility" means the term loan agreement, dated as of April 24, 2012, by and among Holdings, as borrower, the lenders party thereto in their capacities as lenders thereunder and Citibank, N.A., as administrative agent and collateral agent, including any guarantees, instruments and agreements executed in connection therewith, and any amendments, supplements, modifications or restatements thereof.

"TIA" means the Trust indenture Act of 1939 (15 U.S.C. Sections 77aaa-77bbbb) as in effect on the date of the indenture.

"Total Assets" means the total consolidated assets of Holdings and the Restricted Subsidiaries, as shown on the most recent balance sheet of Holdings, without giving effect to any amortization of the amount of intangible assets since December 31, 2011, calculated on a pro forma basis after giving effect to any subsequent acquisition or disposition of a Person or business.

"Transactions" means the "Refinancing Transactions" as defined and described under "Summary—Recent Events—Refinancing Transactions."

"Treasury Rate" means, as of the applicable redemption date, as determined by the Issuers, the yield to maturity as of such redemption date of United States Treasury securities with a constant maturity (as compiled and published in the most recent Federal Reserve Statistical Release H.15 (519) that has become publicly available at least two Business Days prior to such redemption date (or, if such Statistical Release is no longer published, any publicly available source of similar market data)) most nearly equal to the period from such redemption date to June 15, 2018;provided,however, that if the period from such redemption date to June 15, 2018, is less than one year, the weekly average yield on actually traded United States Treasury securities adjusted to a constant maturity of one year will be used.

"Trust Officer" means:

(1): any officer within the corporate trust department of the Trustee, including any vice president, assistant vice president, assistant secretary, assistant treasurer, trust officer or any other officer of the Trustee who customarily performs functions similar to those performed by the Persons who at the time shall be such officers, respectively, or to whom any corporate trust matter is referred because of such person's knowledge of and familiarity with the particular subject, and
(2): who shall have direct responsibility for the administration of the indenture.

"Trustee" means the party named as such in the indenture until a successor replaces it and, thereafter, means the successor.

"Unrestricted Subsidiary" means:

(1): any Subsidiary of Holdings that at the time of determination shall be designated an Unrestricted Subsidiary by the Board of Directors of Holdings in the manner provided below; and
(2): any Subsidiary of an Unrestricted Subsidiary;

Holdings may designate any Subsidiary of Holdings (including any newly acquired or newly formed Subsidiary) to be an Unrestricted Subsidiary unless such Subsidiary or any of its Subsidiaries owns any Equity Interests or Indebtedness of, or owns or holds any Lien on any property of, Holdings or any other Subsidiary of Holdings that is not a Subsidiary of the Subsidiary to be so designated;provided,however, that the Subsidiary to be so designated and its Subsidiaries do not at the time of designation have and do not thereafter Incur any Indebtedness pursuant to which the lender has recourse to any of the assets of Holdings or any of the Restricted Subsidiaries (other than pursuant to customary Liens on related arrangements under any oil and gas royalty trust or master limited partnership), unless otherwise permitted as an Investment in such Unrestricted Subsidiary by Holdings or such Restricted

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Subsidiary under the covenant described under "—Certain Covenants—Limitation on Restricted Payments";provided,further,however, that either:

(a): the Subsidiary to be so designated has total consolidated assets of $1,000 or less; or
(b): if such Subsidiary has consolidated assets greater than $1,000, then such designation would be permitted under the covenant described under "—Certain Covenants—Limitation on Restricted Payments."

Holdings may designate any Unrestricted Subsidiary to be a Restricted Subsidiary;provided,however, that immediately after giving effect to such designation:

(x): (1) Holdings could Incur $1.00 of additional Indebtedness pursuant to the Fixed Charge Coverage Ratio test described under "—Certain Covenants—Limitation on Incurrence of Indebtedness and Issuance of Disqualified Stock and Preferred Stock," or (2) the Fixed Charge Coverage Ratio of Holdings and its Restricted Subsidiaries would be no less than such ratio immediately prior to such designation, in each case on apro forma basis taking into account such designation, and
(y): no Event of Default shall have occurred and be continuing.

Any such designation by Holdings shall be evidenced to the Trustee by promptly filing with the Trustee a copy of the resolution of the Board of Directors or any committee thereof of Holdings giving effect to such designation and an Officers' Certificate certifying that such designation complied with the foregoing provisions.

"U.S. Government Obligations" means securities that are:

(1): direct obligations of the United States of America for the timely payment of which its full faith and credit is pledged, or
(2): obligations of a Person controlled or supervised by and acting as an agency or instrumentality of the United States of America, the timely payment of which is unconditionally guaranteed as a full faith and credit obligation by the United States of America,

which, in each case, are not callable or redeemable at the option of the issuer thereof, and shall also include a depository receipt issued by a bank (as defined in Section 3(a)(2) of the Securities Act) as custodian with respect to any such U.S. Government Obligations or a specific payment of principal of or interest on any such U.S. Government Obligations held by such custodian for the account of the holder of such depository receipt;provided that (except as required by law) such custodian is not authorized to make any deduction from the amount payable to the holder of such depository receipt from any amount received by the custodian in respect of the U.S. Government Obligations or the specific payment of principal of or interest on the U.S. Government Obligations evidenced by such depository receipt.

"Volumetric Production Payments" means production payment obligations recorded as deferred revenue in accordance with GAAP, together with all undertaking and obligations in connection therewith.

"Voting Stock" of any Person as of any date means the Capital Stock of such Person that is at the time entitled to vote in the election of the Board of Directors of such Person.

"Weighted Average Life to Maturity" means, when applied to any Indebtedness or Disqualified Stock or Preferred Stock, as the case may be, at any date, the quotient obtained by dividing (1) the sum of the products of the number of years from the date of determination to the date of each successive scheduled principal payment of such Indebtedness or redemption or similar payment with respect to

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such Disqualified Stock or Preferred Stock multiplied by the amount of such payment, by (2) the sum of all such payments.

"Wholly Owned Restricted Subsidiary" is any Wholly Owned Subsidiary that is a Restricted Subsidiary.

"Wholly Owned Subsidiary" of any Person means a Subsidiary of such Person 100% of the outstanding Capital Stock or other ownership interests of which (other than directors' qualifying shares or shares required pursuant to applicable law) shall at the time be owned by such Person or by one or more Wholly Owned Subsidiaries of such Person.

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BOOK-ENTRY; DELIVERY AND FORM

Except as set forth below, the exchange notes will initially be issued in registered, global notes in global form without coupons ("Global Notes"). Each Global Note shall be deposited with the Trustee, as custodian for, and registered in the name of DTC or a nominee thereof. The initial notes to the extent validly tendered and accepted and directed by their holders in their letters of transmittal, will be exchanged through book-entry electronic transfer for the global note.

Except as set forth below, the Global Notes may be transferred, in whole but not in part, solely to another nominee of DTC or to a successor of DTC or its nominee. Beneficial interests in the Global Notes may not be exchanged for notes in certificated form except in the limited circumstances described below.

The Global Notes

The Issuers expect that, pursuant to procedures established by DTC, (i) upon the issuance of the Global Notes, DTC or its custodian will credit, on its internal system, the principal amount at maturity of the individual beneficial interests represented by such Global Notes to the respective accounts of persons who have accounts with such depositary ("participants") and (ii) ownership of beneficial interests in the Global Notes will be shown on, and the transfer of such ownership will be effected only through, records maintained by DTC or its nominee (with respect to interests of participants) and the records of participants (with respect to interests of persons other than participants). Such accounts initially will be designated by or on behalf of the initial purchasers and ownership of beneficial interests in the Global Notes will be limited to participants or persons who hold interests through participants. Holders may hold their interests in the Global Notes directly through DTC if they are participants in such system, or indirectly through organizations that are participants in such system.

So long as DTC or its nominee is the registered owner or holder of the notes, DTC or such nominee, as the case may be, will be considered the sole owner or holder of the notes represented by such Global Notes for all purposes under the indenture. No beneficial owner of an interest in the Global Notes will be able to transfer that interest except in accordance with DTC's procedures, in addition to those provided for under the indenture with respect to the notes.

Payments of the principal of, and premium (if any) and interest (including additional interest, if any) on, the Global Notes will be made to DTC or its nominee, as the case may be, as the registered owner thereof. None of the Issuers, the Trustee or any paying agent will have any responsibility or liability for any aspect of the records relating to or payments made on account of beneficial ownership interests in the Global Notes or for maintaining, supervising or reviewing any records relating to such beneficial ownership interest.

The Issuers expect that DTC or its nominee, upon receipt of any payment of principal of, and premium (if any) and interest (including additional interest, if any) on the Global Notes, will credit participants' accounts with payments in amounts proportionate to their respective beneficial interests in the principal amount of the Global Notes as shown on the records of DTC or its nominee. The Issuers also expect that payments by participants to owners of beneficial interests in the Global Notes held through such participants will be governed by standing instructions and customary practice, as is now the case with securities held for the accounts of customers registered in the names of nominees for such customers. Such payments will be the responsibility of such participants.

Transfers between participants in DTC will be effected in the ordinary way through DTC's same-day funds system in accordance with DTC rules and will be settled in same-day funds. If a holder requires physical delivery of a Certificated Security, such holder must transfer its interest in a Global Note, in accordance with the normal procedures of DTC and with the procedures set forth in the indenture.

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DTC has advised us that it will take any action permitted to be taken by a holder of notes (including the presentation of notes for exchange as described below) only at the direction of one or more participants to whose account the DTC interests in the Global Notes are credited and only in respect of such portion of the aggregate principal amount of notes as to which such participant or participants has or have given such direction. However, if there is an event of default under the indenture, DTC will exchange the Global Notes for Certificated Securities, which it will distribute to its participants.

DTC has advised the Issuers as follows: DTC is a limited-purpose trust company organized under New York banking law, a "banking organization" within the meaning of the New York banking law, a member of the Federal Reserve System, a "clearing corporation" within the meaning of the New York Uniform Commercial Code and a "clearing agency" registered pursuant to the provisions of Section 17A of the Exchange Act. DTC holds and provides asset servicing for issues of U.S. and non-U.S. equity, corporate and municipal debt issues that participants deposit with DTC. DTC also facilitates the post-trade settlement among participants of sales and other securities transactions in deposited securities through electronic computerized book-entry transfers and pledges between participants' accounts. This eliminates the need for physical movement of securities certificates. Participants include both U.S. and non-U.S. securities brokers and dealers, banks, trust companies, clearing corporations and certain other organizations. Access to the DTC system is also available to indirect participants such as both U.S. and non-U.S. securities brokers and dealers, banks, trust companies and clearing corporations that clear through or maintain a custodial relationship with a participant, either directly or indirectly.

Although DTC has agreed to the foregoing procedures in order to facilitate transfers of interests in the Global Notes among participants of DTC, it is under no obligation to perform such procedures, and such procedures may be discontinued at any time. None of the Issuers, the Trustee or any paying agent will have any responsibility for the performance by DTC or its participants or indirect participants of their respective obligations under the rules and procedures governing their operations.

Certificated Securities

A Global Note is exchangeable for certificated notes in fully registered form without interest coupons ("Certificated Securities") only in the following limited circumstances:

•: DTC notifies the Issuers that it is unwilling or unable to continue as depositary for the Global Note and we fail to appoint a successor depositary within 90 days of such notice, or
•: there shall have occurred and be continuing an event of default with respect to the notes under the indenture and DTC shall have requested the issuance of Certificated Securities.

Certificated Securities may not be exchanged for beneficial interests in any Global Note unless the transferor first delivers to the Trustee a written certificate (in the form provided in the indenture) to the effect that such transfer will comply with the appropriate transfer restrictions applicable to such notes.

The laws of some states require that certain persons take physical delivery in definitive form of securities that they own. Consequently, the ability to transfer the notes will be limited to such extent.

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CERTAIN U.S. FEDERAL INCOME TAX CONSIDERATIONS

Subject to the limitations and qualifications set forth herein (including Exhibit 8.1 hereto), this discussion, insofar as it expresses conclusions as to the application of the United States federal income tax law, is the opinion of Paul, Weiss, Rifkind, Wharton & Garrison LLP, our U.S. federal income tax counsel. The following is a discussion of the material U.S. federal income tax considerations relevant to the exchange of initial notes for exchange notes pursuant to the exchange offer and the ownership and disposition of exchange notes acquired by U.S. Holders and non-U.S. Holders (each as defined below and collectively referred to as "Holders") pursuant to the exchange offer, but does not purport to be a complete analysis of all the potential tax considerations. This summary is based on the Code, Treasury Regulations issued thereunder, and administrative and judicial interpretations thereof, all as of the date of this prospectus and all of which are subject to change (perhaps with retroactive effect).

This summary does not represent a detailed description of the U.S. federal income tax consequences to Holders in light of their particular circumstances. In addition, it does not represent a detailed description of the U.S. federal income tax consequences applicable to Holders that are subject to special treatment under the U.S. federal income tax laws, such as financial institutions, regulated investment companies, real estate investment trusts, individual retirement and other tax deferred accounts, dealers or traders in securities or currencies, life insurance companies, partnerships or other passthrough entities (or investors therein), tax-exempt entities, U.S. expatriates, non-U.S. trusts and estates that have U.S. beneficiaries, persons holding notes as a hedge or hedged against currency risk, in an integrated or conversion transaction, as a position in a constructive sale or straddle, or U.S. Holders whose "functional currency" is other than the U.S. dollar. This summary does not address U.S. federal tax consequences other than U.S. federal income tax consequences (such as estate or gift taxes), the Medicare tax on certain investment income, the alternative minimum tax or the consequences under the tax laws of any foreign, state or local jurisdiction. The discussion deals only with notes held as "capital assets" within the meaning of Section 1221 of the Code. We have not requested a ruling from the Internal Revenue Service (the "IRS") on the tax consequences of owning the notes. As a result, the IRS could disagree with portions of this discussion.

For purposes of this discussion, a "U.S. Holder" means a beneficial owner of a note that is, for U.S. federal income tax purposes:

•: a citizen or resident alien individual of the United States;
•: a corporation that is organized under the laws of the United States, any state thereof or the District of Columbia;
•: an estate the income of which is subject to U.S. federal income taxation regardless of its source; or
•: a trust (i) that is subject to the primary supervision of a court within the United States and under the control of one or more U.S. persons, or (ii) that has a valid election in effect under applicable U.S. Treasury Regulations to be treated as a U.S. person.

For purposes of this discussion, the term "non-U.S. Holder" means a beneficial owner of a note that is, for U.S. federal income tax purposes, an individual, corporation, trust, or estate and that is not a U.S. Holder.

If an entity treated as a partnership for U.S. federal income tax purposes holds notes, the tax treatment of a partner in such an entity will depend on the status of the partner and the activities of the entity. Partners in such entities that are considering exchanging initial notes for exchange notes pursuant to the exchange offer should consult their own tax advisors.

Prospective investors should consult their own tax advisors concerning the particular U.S. federal income tax consequences of exchanging initial notes for exchange notes pursuant to the exchange offer

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and owning and disposing exchange notes acquired pursuant to the exchange offer, as well as the consequences arising under other federal tax laws and the laws of any other taxing jurisdiction.

Possible Alternative Treatment

We may be obligated to pay amounts in excess of the stated interest or principal on the exchange notes, including as described under "Description of Exchange Notes—Optional Redemption" and "Description of Exchange Notes—Change of Control." These potential payments may implicate the provisions of Treasury Regulations relating to "contingent payment debt instruments." According to the applicable Treasury Regulations, certain contingencies will not cause a debt instrument to be treated as a contingent payment debt instrument if such contingencies, as of the date of issuance, are remote or incidental. We intend to take the position that the foregoing contingencies are remote or incidental, and, accordingly, we do not intend to treat the exchange notes as contingent payment debt instruments. Our position that such contingencies are remote or incidental is binding on a Holder, unless such Holder discloses its contrary position in the manner required by applicable Treasury Regulations. Our position is not, however, binding on the IRS, and if the IRS were to successfully challenge this position, a Holder might be required to accrue ordinary interest income on the exchange notes at a rate in excess of the stated interest rate, and to treat as ordinary interest income any gain realized on the taxable disposition of an exchange note. The remainder of this discussion assumes that the exchange notes will not be treated as contingent payment debt instruments. Holders should consult their own tax advisors regarding the possible application of the contingent payment debt instrument rules to the exchange notes.

Certain U.S. Federal Income Tax Considerations for U.S. Holders

Exchange Offer

Exchanging an initial note for an exchange note pursuant to the exchange offer will not be treated as a taxable exchange for U.S. federal income tax purposes. Consequently, U.S. Holders will not recognize gain or loss upon receipt of an exchange note. The holding period for an exchange note will include the holding period for the initial note, and the initial basis in an exchange note will be the same as the adjusted basis in the initial note.

Stated Interest

Absent an election to the contrary (see "—Election to Treat All Interest as Original Issue Discount (Constant Yield Method)," below), any stated interest payments on an exchange note to a U.S. Holder will be taxable as ordinary interest income at the time they accrue or are received, in accordance with the U.S. Holder's regular method of tax accounting for U.S. federal income tax purposes.

Market Discount and Bond Premium

Market Discount. If a U.S. Holder purchased an initial note (which will be exchanged for an exchange note pursuant to the exchange offer) for an amount that is less than its "revised issue price," the amount of the difference should be treated as market discount for U.S. federal income tax purposes. Any market discount applicable to an initial note should carry over to the exchange note received in exchange therefor. The amount of any market discount will be treated asde minimis and disregarded if it is less than one-quarter of one percent of the revised issue price of the initial note, multiplied by the number of complete years to maturity. For this purpose, the "revised issue price" of an initial note equals the issue price of the initial note. The "issue price" of a note is the first price at which a substantial amount of the notes is sold for cash to investors other than to bond houses, brokers or similar persons or organizations acting in the capacity of underwriters, placement agents or

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wholesalers. The rules described below do not apply to a U.S. Holder if such holder purchased an initial note that hasde minimis market discount.

Under the market discount rules, a U.S. Holder is required to treat any principal payment on, or any gain on the sale, exchange, redemption or other disposition of, an exchange note as ordinary income to the extent of any accrued market discount (on the initial note or the exchange note) that has not previously been included in income. If a U.S. Holder disposes of an exchange note in an otherwise nontaxable transaction (other than certain specified nonrecognition transactions), such holder will be required to include any accrued market discount as ordinary income as if such holder had sold the exchange note at its then fair market value. In addition, such holder may be required to defer, until the maturity of the exchange note or its earlier disposition in a taxable transaction, the deduction of a portion of the interest expense on any indebtedness incurred or continued to purchase or carry the initial note or the exchange note received in exchange therefor.

Market discount accrues ratably during the period from the date on which such holder acquired the initial note through the maturity date of the exchange note (for which the initial note was exchanged), unless such holder makes an irrevocable election to accrue market discount under a constant yield method. Such holder may elect to include market discount in income currently as it accrues (either ratably or under the constant yield method), in which case the rule described above regarding deferral of interest deductions will not apply. If such holder elects to include market discount in income currently, such holder's adjusted basis in an exchange note will be increased by any market discount included in income. An election to include market discount currently will apply to all market discount obligations acquired during or after the first taxable year in which the election is made, and the election may not be revoked without the consent of the IRS. If a U.S. Holder makes the election described below in "—Election to Treat All Interest as Original Issue Discount (Constant Yield Method)" for a market discount note, such holder would be treated as having made an election to include market discount in income currently under a constant yield method, as discussed in this paragraph.

Bond Premium. If a U.S. Holder purchased an initial note (which will be exchanged for an exchange note pursuant to the exchange offer) for an amount in excess of the principal amount of the initial note, the excess will be treated as bond premium. Any bond premium applicable to an initial note should carry over to the exchange note received in exchange therefor. A U.S. Holder may elect to reduce the amount required to be included in income each year with respect to interest on its note by the amount of amortizable bond premium allocable to that year, based on the exchange note's yield to maturity. However, because the exchange notes may be redeemed by us prior to maturity at a premium, special rules apply that may reduce or eliminate the amount of premium that a U.S. Holder may amortize with respect to an exchange note. U.S. Holders should consult their tax advisors about these special rules, including whether it would be advisable to elect to treat all interest on the exchange notes as original issue discount (see "—Election to Treat All Interest as Original Issue Discount (Constant Yield Method)," below), which would result in a U.S. Holder not being subject to these special rules. If a U.S. Holder makes the election to amortize bond premium, it will apply to all debt instruments (other than debt instruments the interest on which is excludible from gross income) that the U.S. Holder holds at the beginning of the first taxable year to which the election applies or thereafter acquires, and the election may not be revoked without the consent of the IRS. See also "—Election to Treat All Interest as Original Issue Discount (Constant Yield Method)," below.

Election to Treat All Interest as Original Issue Discount (Constant Yield Method)

A U.S. Holder may elect to include in gross income all "interest" (as defined below) that accrues on its exchange note using the constant-yield method described below. For purposes of this election, "interest" will include stated interest, market discount andde minimis market discount, as reduced by any amortizable bond premium (described in "—Bond Premium," above). A U.S. Holder that makes

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this election will be required to include interest in gross income for U.S. federal income tax purposes as it accrues (regardless of its method of tax accounting), which may be in advance of receipt of the cash attributable to that income.

Although this election applies only to the exchange note for which a U.S. Holder makes it, an electing U.S. Holder will be deemed to have made the election described in "—Bond Premium," above, to apply amortizable bond premium against interest for all debt instruments with amortizable bond premium (other than debt instruments the interest on which is excludible from gross income) that it holds at the beginning of the taxable year to which the election applies or any taxable year thereafter. Additionally, if a U.S. Holders makes this election for a market discount note, such holder will be treated as having made the election discussed above under "—Market Discount and Bond Premium—Market Discount" to include market discount in income currently over the life of all debt instruments that the U.S. holder hold at the time of the election or acquire thereafter. A U.S. Holder may not revoke an election to apply the constant-yield method to all interest on an exchange note without the consent of the IRS.

If a U.S. Holder makes this election for its exchange note, then no payments on the exchange note will be treated as payments of QSI, and the annual amounts of interest includible in income by the U.S. Holder will equal the sum of the "daily portions" of the interest with respect to the exchange note for each day on which the U.S. Holder owns the exchange note during the taxable year. The U.S. Holder determines the daily portions of interest by allocating to each day in an "accrual period" a pro rata portion of the interest that is allocable to that accrual period. The term "accrual period" means an interval of time with respect to which the accrual of interest is measured and which may vary in length over the term of an exchange note provided that each accrual period is no longer than one year and each scheduled payment of principal or interest occurs on either the first or last day of an accrual period. For purposes of this election, the "issue date" of the exchange note is the date the U.S. Holder purchases the exchange note.

The amount of interest allocable to an accrual period will equal the product of the "adjusted issue price" of the exchange note at the beginning of the accrual period and its "yield to maturity." The adjusted issue price of an exchange note at the beginning of the first accrual period is the purchase price, and, on any day thereafter, it is the sum of the issue price and the amount of interest previously included in gross income, reduced by the amount of any payment previously made on the exchange note. If all accrual periods are of equal length except for a shorter initial or final accrual period, the U.S. Holder can compute the amount of interest allocable to the initial period using any reasonable method; however, the interest allocable to the final accrual period will always be the difference between the amount payable at maturity and the adjusted issue price at the beginning of the final accrual period.

Dispositions

A sale, exchange, redemption, retirement or other taxable disposition of an exchange note will result in taxable gain or loss to a U.S. Holder equal to the difference, if any, between the amount realized on the disposition (excluding amounts attributable to any accrued and unpaid stated interest, which will be taxed as ordinary income to the extent not previously so taxed) and the U.S. Holder's adjusted tax basis in the exchange note. The amount realized will equal the sum of any cash and the fair market value of any other property received on the disposition (excluding amounts attributable to any accrued and upaid stated interest). A U.S. Holder's adjusted tax basis in an exchange note should equal the cost of such exchange note to such Holder, increased by any market discount previously included in gross income and reduced (but not below zero) by the amount of any amortizable bond premium taken into account with respect to the exchange note. Such gain or loss will be capital gain or loss and will be long-term capital gain or loss if the exchange note (or the initial note exchanged therefor) is held for more than one year. Certain non-corporate U.S. Holders may be eligible for

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preferential rates of U.S. federal income tax in respect of long-term capital gains. The deductibility of capital losses is subject to limitations.

Certain U.S. Federal Tax Considerations for Non-U.S. Holders

Exchange Offer

Non-U.S. Holders will not recognize gain or loss upon receipt of an exchange note in exchange for an initial note pursuant to the exchange offer.

Interest

Subject to the discussion below of backup withholding and of FATCA, U.S. federal income or withholding tax will not apply to a non-U.S. Holder in respect of any payment of interest on the exchange notes, provided that such payment is not effectively connected with such non-U.S. Holder's conduct of a U.S. trade or business and such non-U.S. Holder:

•: does not own actually or constructively own 10% or more of the capital or profits interest in Parent;
•: is not a controlled foreign corporation that is related to Parent under the applicable provisions of the Code; and
•: is not a bank whose receipt of interest on the exchange notes is described in section 881(c)(3)(A) of the Code; and

either (a) such non-U.S. Holder provides identifying information (i.e., name and address) to us on IRS Form W-8BEN or W-8BEN-E (or successor form), and certifies, under penalty of perjury, that such non-U.S. Holder is not a U.S. person or (b) a financial institution holding the exchange notes on behalf of such non-U.S. Holder certifies, under penalty of perjury, that it has received such a certification from the beneficial owner and, when required, provides us with a copy.

If a non-U.S. Holder cannot satisfy the requirements described above, payments of interest made to such non-U.S. Holder will be subject to a 30% U.S. federal withholding tax, unless such Holder provides us with a properly executed (1) applicable IRS Form W-8BEN or W-8BEN-E (or successor form) claiming an exemption from or reduction in withholding under an applicable income tax treaty or (2) IRS Form W-8ECI (or successor form) stating that interest paid on the exchange note is not subject to withholding tax because it is effectively connected with such Holder's conduct of a trade or business in the United States (in which case such interest will be subject to tax as discussed below).

Dispositions

Subject to the discussion below of backup withholding and of FATCA, any gain realized on the sale, exchange, retirement, redemption or other taxable disposition of an exchange note by a non-U.S. Holder will not be subject to U.S. federal income or withholding tax (except to the extent attributable to accrued and unpaid interest, which will be taxable as described above) unless (1) such gain is effectively connected with the conduct of a trade or business in the United States by such non-U.S. Holder (in which case such gain will be subject to regular graduated U.S. tax rates as described below) or (2) such non-U.S. Holder is an individual who is present in the United States for 183 days or more in the taxable year of that disposition and certain other conditions are met (in which case such gain, net of certain U.S.-source losses, if any, will be subject to U.S. federal income tax at a flat rate of 30% (or at a reduced rate under an applicable income tax treaty)).

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Effectively Connected Interest or Gain

If a non-U.S. Holder is engaged in a trade or business in the United States and interest on the exchange notes or gain from the disposition of the exchange notes is effectively connected with the conduct of that trade or business, such non-U.S. Holder will, subject to an applicable income tax treaty providing otherwise, be subject to U.S. federal income tax on such interest or gain on a net income basis in the same manner as if such non-U.S. Holder were a U.S. Holder. In addition, if such non-U.S. Holder is a foreign corporation, it may be subject to a branch profits tax equal to 30% (or a lower applicable treaty rate) of its effectively connected earnings and profits for the taxable year, subject to certain adjustments.

Information Reporting and Backup Withholding

U.S. Holders

A U.S. Holder may be subject to information reporting and backup withholding (currently at the rate of 28%) with respect to payments of stated interest and payments of the gross proceeds from the sale or other disposition (including a retirement or redemption) of an exchange note. Certain U.S. Holders (including corporations) are not subject to information reporting and backup withholding. A U.S. Holder will be subject to backup withholding if such U.S. Holder is not otherwise exempt and such U.S. Holder:

•: fails to furnish its correct taxpayer identification number ("TIN"), which, for an individual, is ordinarily his or her social security number;
•: is notified by the IRS that it is subject to backup withholding because it has previously failed to properly report payments of interest or dividends;
•: fails to certify, under penalties of perjury, that it has furnished a correct TIN and that the IRS has not notified the U.S. Holder that it is subject to backup withholding; or
•: otherwise fails to comply with applicable requirements of the backup withholding rules.

Non-U.S. Holders

A non-U.S. Holder will not be subject to backup withholding (currently at the rate of 28%) with respect to payments of interest to such non-U.S. Holder if we have received from such non-U.S. Holder the statement described above under "—Certain U.S. Federal Tax Considerations to Non-U.S. Holders—Interest" or the non-U.S. Holder otherwise establishes an exemption, provided that we do not have actual knowledge or reason to know that such non-U.S. Holder is a U.S. person. A non-U.S. Holder may, however, be subject to information reporting requirements with respect to payments of interest on the exchange notes.

Proceeds from the sale, exchange, retirement, redemption or other taxable disposition of the exchange notes made to or through a foreign office of a foreign broker without certain specified connections to the United States will not be subject to information reporting or backup withholding. A non-U.S. Holder may be subject to backup withholding and/or information reporting with respect to the proceeds of the sale, exchange, retirement, redemption or other taxable disposition of an exchange note within the United States or conducted through certain U.S.-related financial intermediaries, unless the payer receives the statement described above under "—Certain U.S. Federal Tax Considerations to Non-U.S. Holders—Interest" and does not have actual knowledge or reason to know that such non-U.S. Holder is a U.S. person, as defined under the Code, or such non-U.S. Holder otherwise establishes an exemption.

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U.S. Holders and non-U.S. Holders

Backup withholding is not an additional tax. Any amounts withheld under the backup withholding rules will be allowed as a credit against a Holder's U.S. federal income tax liability, and may entitle a Holder to a refund, provided the required information is timely furnished to the IRS.

FATCA Withholding

Pursuant to Sections 1471 through 1474 of the Code, or "FATCA," foreign financial institutions (which include most foreign hedge funds, private equity funds, mutual funds, securitization vehicles and any other investment vehicles) and certain other foreign entities must comply with information reporting rules with respect to their U.S. account holders and investors or confront a U.S. federal withholding tax on U.S. source payments made to them (whether received as a beneficial owner or as an intermediary for another party). More specifically, a foreign financial institution or other foreign entity that does not comply with the FATCA reporting requirements will generally be subject to a 30% U.S. federal withholding tax with respect to any "withholdable payments" on, or with respect to, the notes. For this purpose, withholdable payments generally include payments of interest made on the notes and also, for dispositions occurring on or after January 1, 2017, include the entire gross proceeds from the sale or other disposition of the notes. Holders should consult their own tax advisors concerning the applicable FATCA to the notes.

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PLAN OF DISTRIBUTION

Each broker-dealer that receives exchange notes for its own account pursuant to the exchange offer in exchange for initial notes acquired as a result of market making or other trading activities may be deemed to be an "underwriter" within the meaning of the Securities Act and, therefore, must deliver a prospectus meeting the requirements of the Securities Act in connection with any resales, offers to resell or other transfers of the exchange notes received by it in connection with the exchange offer. Accordingly, each such broker-dealer must acknowledge in the letter of transmittal that it will deliver a prospectus meeting the requirements of the Securities Act in connection with any resale of such exchange notes. The letter of transmittal states that by acknowledging that it will deliver, and by delivering a prospectus, a broker-dealer will not be deemed to admit that it is an "underwriter" within the meaning of the Securities Act.

This prospectus, as it may be amended or supplemented from time to time, may be used by a broker-dealer in connection with resales of exchange notes received in exchange for initial notes where such initial notes were acquired as a result of market-making activities or other trading activities. We have agreed that, for a period of 180 days after the expiration of this exchange offer, we will make this prospectus, as amended or supplemented, available to any broker-dealer for use in connection with any such resale or to any broker-dealer that requests such documents in the letter of transmittal.

We will not receive any proceeds from any sale of exchange notes by broker-dealers. Exchange Notes received by broker-dealers for their own account pursuant to the exchange offer may be sold from time to time in one or more transactions in the over-the-counter market, in negotiated transactions, through the writing of options on the exchange notes or a combination of such methods of resale, at market prices prevailing at the time of resale, at prices related to such prevailing market prices or negotiated prices. Any such resale may be made directly to purchasers or to or through brokers or dealers who may receive compensation in the form of commissions or concessions from any such broker-dealer and/or the purchasers of any such exchange notes. Any broker-dealer that resells exchange notes that were received by it for its own account pursuant to the exchange offer and any broker or dealer that participates in a distribution of such exchange notes may be deemed to be an "underwriter" within the meaning of the Securities Act and any profit on any such resale of exchange notes and any commissions or concessions received by any such persons may be deemed to be underwriting compensation under the Securities Act.

We have agreed to pay all expenses incident to the exchange offer (including the expenses of one counsel for the holders of the notes) other than commissions or concessions of any brokers or dealers.

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LEGAL MATTERS

Paul, Weiss, Rifkind, Wharton & Garrison LLP, New York, New York, will pass on the validity of the exchange notes and guarantees offered hereby.

EXPERTS

Independent Registered Public Accounting Firm

The consolidated financial statements of EP Energy LLC as of December 31, 2014 and 2013, for each of two years in the period ended December 31, 2014 (Successor), the period from March 23, 2012 to December 31, 2012 (Successor), and the period from January 1, 2012 to May 24, 2012 (Predecessor) appearing in this prospectus and registration statement, have been audited by Ernst & Young LLP, independent registered public accounting firm, as set forth in their report thereon appearing elsewhere herein, and are included in reliance upon such report given on the authority of such firm as experts in accounting and auditing.

Independent Petroleum Engineers

Estimates of our oil, NGLs and natural gas reserves, related future net cash flows and the present values thereof as of December 31, 2014, included in this prospectus were based in part upon reserve information that was audited by independent petroleum engineering consultants, Ryder Scott Company, L.P. We have included these estimates in reliance on the authority of Ryder Scott Company, L.P. as experts in such matters.

WHERE YOU CAN FIND MORE INFORMATION

We are subject to the informational requirements of the Exchange Act and file annual and quarterly reports and other information with the SEC. We have also filed with SEC a registration statement on Form S-4 to register the exchange notes. This prospectus, which forms part of the registration statement, does not contain all of the information included in that registration statement. You should note that where we summarize in this prospectus the material terms of any contract, agreement or other document filed as an exhibit to the registration statement, the summary information provided in the prospectus is less complete than the actual contract, agreement or document. You should refer to the exhibits filed to the registration statement for copies of the actual contract, agreement or document.

For further information about us and the exchange notes offered in this prospectus, you should refer to the registration statement and its exhibits. You may read and copy any document we file with the SEC at the SEC's Public Reference Room, 100 F Street, N.E., Washington, D.C. 20549. Copies of these reports, proxy statements and information that we file with the SEC may be obtained at prescribed rates from the Public Reference Section of the Commission at 100 F Street, N.E., Washington, D.C. 20549. Please call the SEC at 1-800-SEC-0330 for further information on the operation of the Public Reference Room. Our filings will also be available to the public through our internet website atwww.epenergy.com or on the SEC's website atwww.sec.gov. Information on our website does not constitute part of this prospectus and should not be relied upon in connection with making any decision with respect to the exchange offer. Our reports and other information that we have filed, or may in the future file, with the SEC are not incorporated by reference into and do not constitute part of this prospectus.

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GLOSSARY OF OIL AND NATURAL GAS TERMS

The terms defined in this section are used throughout this prospectus:

"/d." per day.

"Basin." A large natural depression on the earth's surface in which sediments generally brought by water accumulate.

"Bbl." One stock tank barrel, or 42 U.S. gallons liquid volume, used herein in reference to crude oil, condensate or natural gas liquids.

"Bcf." One billion cubic feet of natural gas.

"Bcfe." One billion cubic feet of natural gas equivalent, determined by using a ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas.

"Boe." Barrel of oil equivalent, a standard convention used to express oil and gas volumes on a comparable oil equivalent basis. Gas equivalents are determined under the relative energy content method by using the ratio of 6.0 Mcf of gas to 1.0 Bbl of oil or NGLs.

"Btu." British Thermal units, a measure of heating value.

"CBM." Coal bed methane.

"Completion." The process of treating a drilled well followed by the installation of permanent equipment for the production of natural gas or oil, or in the case of a dry hole, the reporting of abandonment to the appropriate agency.

"Developed acreage." The number of acres that are allocated or assignable to productive wells or wells capable of production.

"Development well." A well drilled within the proved area of an oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.

"Drilling locations." Future locations specifically identified by management as an estimation of our multi-year drilling activities based on evaluation of applicable geologic, seismic, engineering, production and reserves data on contiguous acreage and geologic formations. Unless otherwise indicated in this prospectus, references to drilling locations are gross for operated properties and net for non-operated properties.

"Dry hole." Exploratory or development well that does not produce oil or natural gas in economically producible quantities.

"Estimated ultimate recovery (EUR)." The sum of reserves remaining as of a given date and cumulative production as of that date.

"Exploratory well." A well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or natural gas in another reservoir.

"Farm-in or farm-out." An agreement under which the owner of a working interest in an oil or natural gas lease assigns the working interest or a portion of the working interest to another party who desires to drill on the leased acreage. Generally, the assignee is required to drill one or more wells in order to earn its working interest in the acreage. The assignor usually retains a royalty or reversionary interest in the lease. The working interest received by an assignee is a "farm-in" while the working interest transferred by the assignor is a "farm-out."

"Field." An area consisting of a single reservoir or multiple reservoirs all grouped on, or related to, the same individual geological structural feature and/or stratigraphic condition. The field name refers to the surface area, although it may refer to both the surface and the underground productive formations.

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"Formation." A layer of rock which has distinct characteristics that differ from nearby rock.

"Gross acreage or gross wells." The total acres or wells, as the case may be, in which a working interest is owned.

"Horizontal drilling." A drilling technique used in certain formations where a well is drilled vertically to a certain depth and then drilled at a right angle within a specified interval.

"MBbl." One thousand barrels of crude oil, condensate or NGLs.

"MBoe." One thousand Boes.

"Mcf." One thousand cubic feet of natural gas.

"Mcfe." One thousand cubic feet equivalent, determined by using a ratio of six Mcf of natural gas to one bbl of crude oil, condensate or NGLs.

"MMBbl." One million barrels of crude oil, condensate or NGLs.

"MMBtu." One million British thermal units.

"MMcfe." One million cubic feet of natural gas equivalent, determined by using a ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or NGLs.

"Net Revenue Interest." The interest in and to all hydrocarbons produced, saved and sold from or allocated to an oil and/or gas property after giving effect to all royalties, overriding royalties, production payments, carried interests, net profits interests, reversionary interests and other burdens upon, measured by or payable out of such hydrocarbon production.

"NGLs." Natural gas liquids. Hydrocarbons found in natural gas that may be extracted as liquefied petroleum gas and natural gasoline.

"NYMEX." The New York Mercantile Exchange.

"Net acres." The percentage of total acres an owner has out of a particular number of acres, or a specified tract. An owner who has 50% interest in 100 acres has 50 net acres.

"Productive well." A well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of the production exceed production expenses and taxes.

"Proved developed reserves." Reserves that can be expected to be recovered through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well and through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

"Proved reserves." The estimated quantities of oil, natural gas and NGLs which geoscience and engineering data demonstrate with reasonable certainty to be commercially recoverable in future years from known reservoirs under existing economic and operating conditions.

"Proved undeveloped ("PUD") reserves." Proved reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion.

"Recompletion." The process of re-entering an existing wellbore that is either producing or not producing and completing new reservoirs in an attempt to establish or increase existing production.

"Reservoir." A porous and permeable underground formation containing a natural accumulation of producible oil and/or natural gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.

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"Spacing." The distance between wells producing from the same reservoir. Spacing is often expressed in terms of acres, e.g., 40-acre spacing, and is often established by regulatory agencies.

"Standardized measure." Discounted future net cash inflows estimated by applying the first day 12-month average U.S. price to the estimated future production of year-end proved reserves. Future cash inflows are reduced by estimated future production and development costs based on period-end costs to determine pre-tax cash inflows. Future income taxes, if applicable, are computed by applying the statutory tax rate to the excess of pre-tax cash inflows over our tax basis in the oil and natural gas properties. Future net cash inflows after income taxes are discounted using a 10% annual discount rate.

"Undeveloped acreage." Acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas, regardless of whether such acreage contains proved reserves.

"Unit." The joining of all or substantially all property interests in a particular spacing or development area tract or section, to provide for development and operation of all such separate property interests. Also, the area covered by a unitization agreement or pooling order.

"Wellbore." The hole drilled by the bit that is equipped for natural gas production on a completed well. Also called well or borehole.

"Well cost." The cost of drilling, completing and equipping a well.

"Working interest." The right granted to the lessee of a property to explore for and to produce and own oil, natural gas or other minerals. The working interest owners bear the exploration, development and operating costs on either a cash, penalty or carried basis.

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Unaudited Condensed Consolidated Financial Statements
Condensed Consolidated Statements of Income for the three months ended March 31, 2015 and 2014			F-2
Condensed Consolidated Balance Sheets as of March 31, 2015 and December 31, 2014			F-3
Condensed Consolidated Statements of Cash Flows for the three months ended March 31, 2015 and 2014			F-4
Condensed Consolidated Statements of Changes in Equity for the period from December 31, 2014 to March 31, 2015			F-5
Notes to the Condensed Consolidated Financial Statements			F-6
Audited Consolidated Financial Statements
Report of Independent Registered Public Accounting Firm			F-17
Consolidated Statements of Income for (i) the Years Ended December 31, 2014 and 2013 and for the successor period from March 23, 2012 (inception) to December 31, 2012 and (ii) the predecessor period from January 1, 2012 to May 24, 2012			F-18
Consolidated Statements of Comprehensive Income for (i) the Years Ended December 31, 2014 and 2013 and for the successor period from March 23, 2012 (inception) to December 31, 2012 and (ii) the predecessor period from January 1, 2012 to May 24, 2012			F-19
Consolidated Balance Sheets as of December 31, 2014 and December 31, 2013			F-20
Consolidated Statements of Cash Flows for (i) the Years Ended December 31, 2014 and 2013 and for the successor period from March 23, 2012 (inception) to December 31, 2012 and (ii) the predecessor period from January 1, 2012 to May 24, 2012			F-21
Consolidated Statements of Changes in Equity for (i) the Years Ended December 31, 2014 and 2013 and for the successor period from March 23, 2012 (inception) to December 31, 2012 and (ii) the predecessor period from January 1, 2012 to May 24, 2012			F-22
Notes to the Consolidated Financial Statements			F-23
Supplemental Selected Quarterly Financial Information (Unaudited)			F-51
Supplemental Oil and Natural Gas Operations (Unaudited)			F-51

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EP ENERGY LLC

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

(In millions)

(Unaudited)

	Quarters ended March 31,

	2015			2014
Operating revenues
Oil	$	229		$	406
Natural gas		48			78
NGLs		13			27
Financial derivatives		203			(135	)

Total operating revenues		493			376

Operating expenses
Natural gas purchases		7			3
Transportation costs		27			23
Lease operating expense		47			44
General and administrative		47			49
Depreciation, depletion and amortization		224			192
Exploration and other expense		6			8
Taxes, other than income taxes		22			33

Total operating expenses		380			352

Operating income		113			24
Interest expense		(84	)		(77	)

Income (loss) from continuing operations before income taxes		29			(53	)
Income tax expense		10			—

Income (loss) from continuing operations		19			(53	)
Income from discontinued operations, net of tax		—			17

Net income (loss)	$	19		$	(36	)

See accompanying notes.

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EP ENERGY LLC

CONDENSED CONSOLIDATED BALANCE SHEETS

(In millions)

(Unaudited)

	March 31, 2015		December 31, 2014

ASSETS
Current assets
Cash and cash equivalents	$	7	$	21
Accounts receivable
Customer, net of allowance of less than $1 in 2015 and 2014		206		234
Other, net of allowance of $1 in 2015 and 2014		28		38
Materials and supplies		24		25
Derivative instruments		746		752
Prepaid assets		7		7

Total current assets		1,018		1,077

Property, plant and equipment, at cost
Oil and natural gas properties		10,645		10,241
Other property, plant and equipment		79		76

		10,724		10,317
Less accumulated depreciation, depletion and amortization		1,809		1,589

Total property, plant and equipment, net		8,915		8,728

Other assets
Derivative instruments		289		297
Unamortized debt issue costs		85		90
Other		2		2

		376		389

Total assets	$	10,309	$	10,194



LIABILITIES AND EQUITY
Current liabilities
Accounts payable
Trade	$	106	$	142
Other		328		402
Income tax payable due to parent		5		—
Deferred income taxes		248		251
Derivative instruments		1		1
Accrued interest		106		53
Asset retirement obligations		2		2
Other accrued liabilities		35		47

Total current liabilities		831		898

Long-term debt		4,726		4,598
Other long-term liabilities
Deferred income taxes		878		869
Asset retirement obligations		41		40
Other		7		7

Total non-current liabilities		5,652		5,514

Commitments and contingencies (Note 7)
Member's equity		3,826		3,782

Total liabilities and equity	$	10,309	$	10,194

See accompanying notes.

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EP ENERGY LLC

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(In millions)

(Unaudited)

	Quarters ended March 31,

	2015			2014
Cash flows from operating activities
Net income (loss)	$	19		$	(36	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities
Depreciation, depletion and amortization		224			198
Gain on sale of assets		—			(13	)
Deferred income tax expense		6			—
Share-based compensation expense		5			4
Non-cash portion of exploration expense		4			7
Amortization of debt issuance costs		5			5
Other		(1	)		3
Asset and liability changes
Accounts receivable		38			(16	)
Accounts payable		(90	)		6
Derivative instruments		14			111
Accrued interest		53			53
Other asset changes		1			2
Other liability changes		(8	)		(17	)

Net cash provided by operating activities		270			307

Cash flows from investing activities
Capital expenditures		(432	)		(459	)
Proceeds from the sale of assets		—			17

Net cash used in investing activities		(432	)		(442	)

Cash flows from financing activities
Proceeds from issuance of long-term debt		364			550
Repayments of long-term debt		(236	)		(570	)
Contribution from parent		20			186

Net cash provided by financing activities		148			166

Change in cash and cash equivalents		(14	)		31
Cash and cash equivalents
Beginning of period		21			48

End of period	$	7		$	79

See accompanying notes

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EP ENERGY LLC

CONDENSED CONSOLIDATED STATEMENT OF CHANGES IN EQUITY

(In millions)

(Unaudited)

	Total Member's Equity

Balance at December 31, 2014	$	3,782
Share-based compensation		5
Cash contributions from parent		20
Net income		19

Balance at March 31, 2015	$	3,826

See accompanying notes.

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EP ENERGY LLC

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

1. Basis of Presentation and Significant Accounting Policies

Basis of Presentation

We prepared this Quarterly Report on Form 10-Q under the rules and regulations of the United States Securities and Exchange Commission (SEC) and in accordance with United States generally accepted accounting principles (U.S. GAAP) as it applies to interim financial statements. Because this is an interim period report presented using a condensed format, it does not include all of the disclosures required by U.S. GAAP and should be read along with our 2014 Annual Report on Form 10-K. The condensed consolidated financial statements as of March 31, 2015 and 2014 are unaudited. The consolidated balance sheet as of December 31, 2014 has been derived from the audited consolidated balance sheet included in our 2014 Annual Report on Form 10-K. In our opinion, all adjustments which are of a normal, recurring nature are reflected to fairly present these interim period results. Our financial statements for prior periods include reclassifications that were made to conform to the current period presentation, none of which impacted our reported net income or member's equity. The results for any interim period are not necessarily indicative of the expected results for the entire year.

Significant Accounting Policies

There were no changes in significant accounting policies as described in the 2014 Annual Report on Form 10-K other than as further described in Note 3, Income Taxes.

New Accounting Pronouncements Issued But Not Yet Adopted

The following accounting standards have been issued but not yet been adopted.

Debt Issuance Costs. In April 2015, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update No. 2015-03,Simplifying the Presentation of Debt Issuance Costs, which will require us to present unamortized debt issue costs on our balance sheet as a direct deduction from the associated debt liability. Retrospective application of this standard is required beginning in the first quarter of 2016.

Revenue Recognition. In May 2014, the FASB issued Accounting Standards Update No. 2014-09,Revenue from Contracts with Customers, which clarifies the principles for recognizing revenue and develops a common revenue standard for U.S. GAAP and International Financial Reporting Standards. Retrospective application of this standard is required beginning in the first quarter of 2017. In April 2015, the FASB proposed a deferral of the new revenue standard by one year, with the option of early adoption in 2017. We are currently evaluating the impact, if any, that this update will have on our financial statements.

2. Acquisitions and Divestitures

Discontinued Operations. In 2014, we reflected as discontinued operations certain non-core assets sold including domestic natural gas assets in our Arklatex and South Louisiana Wilcox areas and our Brazilian operations. We have classified the results of operations of these assets prior to their sale in

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EP ENERGY LLC

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(Unaudited)

2. Acquisitions and Divestitures (Continued)

2014 as income (loss) from discontinued operations. Summarized operating results of our discontinued operations were as follows:

	Quarter ended March 31, 2014

	(in millions)
Operating revenues	$	31

Operating expenses
Transportation costs		3
Lease operating expense		13
Depreciation, depletion and amortization		6
Impairment charges(1)		3
Other expense		5

Total operating expenses		30

Gain on sale of assets		13
Other income		3

Income from discontinued operations before income taxes		17
Income tax expense		—

Income from discontinued operations, net of tax	$	17

(1): During the quarter ended March 31, 2014, we recorded $3 million in impairment charges related to the sale of our Brazilian operations.

3. Income Taxes

General. On December 31, 2014, we simplified our structure and as a result we became a division of a corporation subject to federal and state income taxes. Prior to December 31, 2014, we were a limited liability company treated as a partnership for federal and state income tax purposes. During that time, our Brazil operations were subject to foreign income taxes; however, these have been reclassified as discontinued operations. See Note 2 for further discussion of discontinued operations.

Our taxable income or loss is included in our parent's (EP Energy Corporation) U.S. federal and certain state returns. EP Energy Corporation pays all consolidated U.S. federal and state income tax directly to the appropriate taxing jurisdictions. We record income taxes on a separate return basis in our financial statements as if we had filed separate income tax returns under our existing structure. In certain states, we also file and pay directly to the state taxing authorities.

Effective Tax Rate. Interim period income taxes are computed by applying an anticipated annual effective tax rate to year-to-date income or loss, except for significant unusual or infrequently occurring items, which are recorded in the period in which they occur. Changes in tax laws or rates are recorded in the period they are enacted. For the quarter ended March 31, 2015, our effective tax rate was relatively consistent with the statutory rate. Our effective tax rate is primarily impacted by the effects of state income taxes (net of federal income tax effects) and non-deductible compensation expense.

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EP ENERGY LLC

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(Unaudited)

4. Financial Instruments

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

	March 31, 2015				December 31, 2014

	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	(in millions)
Long-term debt	$	4,726	$	4,809	$	4,598	$	4,582



Derivative instruments	$	1,034	$	1,034	$	1,048	$	1,048

As of March 31, 2015 and December 31, 2014, the carrying amount of cash and cash equivalents, accounts receivable and accounts payable represent fair value because of the short-term nature of these instruments. We hold long-term debt obligations (see Note 6) 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, Natural Gas and NGLs Derivative Instruments. We attempt to mitigate a portion of our commodity price risk and stabilize cash flows associated with forecasted sales of oil and natural gas through the use of financial derivatives. As of March 31, 2015 and December 31, 2014, we had fixed price derivative contracts for 36 MMBbls and 37 MMBbls of oil and 54 TBtu and 69 TBtu of natural gas, respectively. In addition, we also have derivative contracts related to locational basis differences and/or timing of physical settlement prices. As of March 31, 2015, we also had derivative contracts on 35 MMGal of propane. None of these contracts are designated as accounting hedges.

The following table reflects the volumes associated with derivative contracts entered into between April 1, 2015 and April 24, 2015.



Oil (MBbls)
Fixed Price Swaps
LLS(1)	—	4,392
Basis Swaps
WTI—CM vs. TM(2)	—	3,660
NYMEX Roll(3)	490	182

(1): In April 2015, we unwound 1,464 MBbls of 2016 LLS three way collars in exchange for 4,392 MBbls of 2016 LLS fixed price swaps. No cash or other consideration was included as part of this exchange.
(2): EP Energy receives WTI trade month (TM) and pays WTI calendar month (CM).
(3): Hedges the timing risk associated with our physical sales. We generally sell oil for the delivery month at a sales price based on the average NYMEX WTI price during that month, plus an adjustment calculated as a spread between the weighted average prices of the delivery month, the next month and the following month during the period when the delivery month is prompt (the "trade month roll").

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EP ENERGY LLC

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(Unaudited)

4. Financial Instruments (Continued)

Interest Rate Derivative Instruments. We have interest rate swaps with a notional amount of $600 million that extend through April 2017 and are intended to reduce variable interest rate risk. As of March 31, 2015, we have a net liability of less than $1 million and as of December 31, 2014, we had a net asset of $3 million related to interest rate derivative instruments included in our consolidated balance sheets. For the quarters ended March 31, 2015 and 2014, we recorded $4 million and $1 million of interest expense, respectively, related to the change in fair market value and cash settlements of our interest rate derivative instruments.

Fair Value Measurements. We use various methods to determine the fair values of our financial instruments. The fair value of a financial instrument depends on a number of factors, including the availability of observable market data over the contractual term of the underlying instrument. We separate the fair value of our financial instruments into three levels (Levels 1, 2 and 3) based on our assessment of the availability of observable market data and the significance of non-observable data used to determine fair value. As of March 31, 2015 and December 31, 2014, all derivative financial instruments were classified as Level 2. Our assessment of an instrument within a level can change over time based on the maturity or liquidity of the instrument, which could result in a change in the classification of our financial instruments between other levels.

Financial Statement Presentation. The following table presents the fair value associated with our derivative financial instruments as of March 31, 2015 and December 31, 2014. All of our derivative instruments are subject to master netting arrangements which provide for the unconditional right of offset for all derivative assets and liabilities with a given counterparty in the event of default. We present assets and liabilities related to these instruments in our balance sheets as either current or non-current assets or liabilities based on their anticipated settlement date, net of the impact of master netting agreements. On derivative contracts recorded as assets in the table below, we are exposed to the risk that our counterparties may not perform.

	Level 2

	Derivative Assets									Derivative Liabilities
						Balance Sheet Location									Balance Sheet Location
	Gross Fair Value		Impact of Netting			Current		Non- current		Gross Fair Value			Impact of Netting		Current			Non- current
			(in millions)										(in millions)
March 31, 2015
Derivative instruments	$	1,069	$	(34	)	$	746	$	289	$	(35	)	$	34	$	(1	)	$	—



December 31, 2014
Derivative instruments	$	1,093	$	(44	)	$	752	$	297	$	(45	)	$	44	$	(1	)	$	—

For the quarters ended March 31, 2015 and 2014, we recorded a derivative gain of $203 million and a derivative loss of $135 million, respectively, on our financial oil and natural gas derivative instruments. Derivative gains and losses on our oil, natural gas and NGLs financial derivative instruments are recorded in operating revenues in our consolidated income statement.

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EP ENERGY LLC

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(Unaudited)

5. Property, Plant and Equipment

Oil and Natural Gas Properties. As of March 31, 2015 and December 31, 2014, we had approximately $8.9 billion and $8.7 billion of total property, plant, and equipment, net of accumulated depreciation, depletion and amortization on our balance sheet, substantially all of which related to both proved and unproved oil and natural gas properties. At March 31, 2015 and December 31, 2014, the costs associated with unproved oil and natural gas properties totaled approximately $0.5 billion and $0.7 billion, respectively. During the first quarter of 2015, we transferred approximately $0.2 billion from unproved properties to proved properties. For the quarters ended March 31, 2015 and 2014, we recorded $4 million and $7 million, respectively, of amortization of unproved leasehold costs in exploration expense in our consolidated income statement. Suspended well costs were not material as of March 31, 2015 or December 31, 2014.

Impairment Assessment. Forward commodity prices can play a significant role in determining future impairments of our proved or unproved property. Due to the continued decline in oil prices in the first quarter of 2015, we reviewed our proved and unproved property for impairment. For the quarters ended March 31, 2015 and 2014, we did not record any impairments of our oil and natural gas properties included in continuing operations. Considering the significant amount of fair value allocated to our oil and natural gas properties pursuant to our acquisition in 2012 by affiliates of Apollo Global Management, LLC (Apollo) and other private equity investors, sustained lower oil and natural gas prices and further price reductions or changes to our future capital and development plans due to the lower price environment could result in an impairment of the carrying value of our proved and/or unproved properties in the future, and such charges could be material.

Leasehold acquisition costs associated with non-producing areas are assessed for impairment based on our estimated drilling plans and capital expenditures relative to potential lease expirations. Our unproved property costs were approximately $0.5 billion at March 31, 2015, of which approximately $0.4 billion was associated with Wolfcamp and $0.1 billion with Altamont. 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 activities. Our allocation of capital to the development of unproved properties may be influenced by changes in commodity prices (e.g. the decline in oil prices beginning in the fourth quarter of 2014), the availability of drilling rigs and associated costs, and/or the relative returns of our unproved property development in comparison to the use of capital for other strategic objectives. Due to the significant decline in oil prices, we have reduced our expected capital expenditures in certain of our operating areas for 2015; however, we currently have the intent and ability to fulfill our drilling commitments prior to the expiration of the associated leases. Should oil prices not justify sufficient capital allocation to the continued development of these unproved properties, we could incur impairment charges of our unproved property, and such charges could be material.

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

In estimating the liability associated with our asset retirement obligations, we utilize several assumptions, including a credit-adjusted risk-free rate between 7-9 percent and a projected inflation

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EP ENERGY LLC

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(Unaudited)

5. Property, Plant and Equipment (Continued)

rate of 2.5 percent. The net asset retirement liability as of March 31, 2015 on our consolidated balance sheet in other current and non-current liabilities and the changes in the net liability from January 1 through March 31, 2015 were as follows:

	2015

	(in millions)
Net asset retirement liability at January 1	$	42
Liabilities incurred		1
Liabilities settled		(1	)
Accretion expense		1

Net asset retirement liability at March 31	$	43

Capitalized Interest. Interest expense is reflected in our financial statements net of capitalized interest. Capitalized interest for the quarters ended March 31, 2015 and 2014 was approximately $4 million and $5 million, respectively.

6. Long-Term Debt

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

	Interest Rate	March 31, 2015		December 31, 2014

		(in millions)
$2.75 billion RBL credit facility—due May 24, 2019	Variable	$	980	$	852
$750 million senior secured term loan—due May 24, 2018(1)(3)	Variable		496		496
$400 million senior secured term loan—due April 30, 2019(2)(3)	Variable		150		150
$750 million senior secured notes—due May 1, 2019(3)	6.875%		750		750
$2.0 billion senior unsecured notes—due May 1, 2020	9.375%		2,000		2,000
$350 million senior unsecured notes—due September 1, 2022	7.75%		350		350

Total		$	4,726	$	4,598

(1): The term loan was issued at 99% of par and carries interest at a specified margin over the LIBOR of 2.75%, with a minimum LIBOR floor of 0.75%. As of March 31, 2015 and December 31, 2014, the effective interest rate of the term loan was 3.50%.
(2): The term loan carries interest at a specified margin over the LIBOR of 3.50%, with a minimum LIBOR floor of 1.00%. As of March 31, 2015 and December 31, 2014, the effective rate for the term loan was 4.50%.
(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.

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EP ENERGY LLC

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(Unaudited)

6. Long-Term Debt (Continued)

As of March 31, 2015 and December 31, 2014, we had $85 million and $90 million, respectively, in deferred financing costs on our consolidated balance sheets. During each of the quarters ended March 31, 2015 and 2014, we amortized $5 million of deferred financing costs in interest expense.

$2.75 Billion Reserve-based Loan (RBL). We have a $2.75 billion credit facility in place which allows us to borrow funds or issue letters of credit (LC's). As of March 31, 2015, we had $980 million of outstanding borrowings and approximately $82 million of LC's issued under the facility, leaving $1.7 billion of remaining capacity available.

The RBL Facility is collateralized by certain of our oil and natural gas properties and has a borrowing base subject to semi-annual redetermination. In April 2015, we completed our semi-annual redetermination, reaffirming the borrowing base at $2.75 billion and extending the maturity date to May 2019, provided that the 2018 and 2019 secured term loans and senior notes are retired or refinanced six months prior to maturity. Downward revisions of our oil and natural gas reserves due to future declines in commodity prices, performance revisions, sales of assets or the incurrence of certain types of additional debt, among other items, could cause a redetermination of the borrowing base and could negatively impact our ability to borrow funds under the RBL Facility in the future.

Guarantees. Our obligations under the RBL Facility, term loan, secured and unsecured notes are fully and unconditionally guaranteed, jointly and severally, by the Company's present and future direct and indirect wholly owned material domestic subsidiaries. EP Energy LLC has no independent assets or operations. Any subsidiaries of EP Energy LLC, other than the subsidiary guarantors, are minor. The subsidiary guarantees are subject to certain automatic customary releases, including the sale or disposition of the capital stock or substantially all of the assets of a subsidiary guarantor, exercise of legal defeasance or covenant defeasance, or designation of a subsidiary guarantor as unrestricted in accordance with the applicable indenture. There are no significant restrictions on the ability of the Company or any guarantor to obtain funds from its subsidiaries by dividend or loan.

Restrictive Provisions/Covenants. The availability of borrowings under our credit agreements and our ability to incur additional indebtedness is subject to various financial and non-financial covenants and restrictions. There have been no significant changes to our restrictive covenants, and as of March 31, 2015, we were in compliance with all of our debt covenants. For a further discussion of our debt agreements and restrictive covenants, see our 2014 Annual Report on Form 10-K.

7. Commitments and Contingencies

Legal Matters

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

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EP ENERGY LLC

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(Unaudited)

7. Commitments and Contingencies (Continued)

potential exposure related to these matters and adjust our accruals accordingly, and these adjustments could be material. As of March 31, 2015, we had approximately $2 million accrued for all outstanding legal matters.

Southeast Louisiana Flood Protection Authority v. EP Energy Management, L.L.C. On July 24, 2013, the levee authority for New Orleans and surrounds (The Authority) filed suit against 97 oil, gas and pipeline companies, seeking (among other relief) restoration of wetlands allegedly lost due to historic industry operations in those areas. On February 13, 2015, the District Court dismissed the case for failure to state a claim, finding that the defendants had no duty to the Authority. The Authority has appealed to the U.S. Court of Appeals for the Fifth Circuit. Based on our current analysis of factors surrounding this claim, we believe our exposure to this claim, if any, will not be material to our financial statements.

Indemnifications and Other Matters. We periodically enter into indemnification arrangements as part of the divestitures of assets or businesses. These arrangements include, but are not limited to, indemnifications for income taxes, the resolution of existing disputes, environmental and other contingent matters. In addition, under various laws or regulations, we could be subject to the imposition of certain liabilities. For example, the recent decline in commodity prices may create an environment where there is an increased risk that owners and/or operators of assets purchased from us may no longer be able to satisfy plugging and abandonment obligations that attach to such assets. In that event, under various laws or regulations, we may be required to assume these plugging or abandonment obligations on assets no longer owned and operated by us. As of March 31, 2015, we had approximately $8 million accrued related to these indemnifications and other matters.

Environmental Matters

We are subject to existing federal, state and local laws and regulations governing environmental quality, pollution control and greenhouse gas (GHG) emissions. The environmental laws and regulations to which we are subject also require us to remove or remedy the effect on the environment of the disposal or release of specified substances at current and former operating sites. As of March 31, 2015, we had accrued and had exposure of approximately $1 million for related environmental remediation costs associated with onsite, offsite and groundwater technical studies and for related environmental legal costs. Our accrual represents a combination of two estimation methodologies. First, where the most likely outcome can be reasonably estimated, that cost has been accrued. Second, where the most likely outcome cannot be estimated, a range of costs is established and if no one amount in that range is more likely than any other, the lower end of the expected range has been accrued. Our environmental remediation projects are in various stages of completion. The liabilities we have recorded reflect our current estimates of amounts that we will expend to remediate these sites. However, depending on the stage of completion or assessment, the ultimate extent of contamination or remediation required may not be known. As additional assessments occur or remediation efforts continue, we may incur additional liabilities.

Climate Change and Other Emissions. The Environmental Protection Agency (EPA) and several state environmental agencies have adopted regulations to regulate GHG emissions. Although the EPA has adopted a "tailoring" rule to regulate GHG emissions, the U.S. Supreme Court partially invalidated

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EP ENERGY LLC

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(Unaudited)

7. Commitments and Contingencies (Continued)

it in an opinion decided June 2014. The tailoring rule remains applicable for those facilities considered major sources of six other "criteria" pollutants and at this time we do not expect a material impact to our existing operations from the rule. 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, which will generally favor the use of natural gas over other fossil fuels such as coal. It remains uncertain what regulations or amended final rules will ultimately be adopted and when they will be adopted. As part of the White House's Climate Action Plan Strategy to Reduce Methane Emissions, the EPA has announced it will propose additional regulations in 2015, and the Pipeline and Hazardous Materials Safety Administration is expected to propose new standards in 2015 for natural gas pipelines. Any regulations regarding GHG emissions would likely increase our costs of compliance by potentially delaying the receipt of permits and other regulatory approvals; requiring us to monitor emissions, install additional equipment or modify facilities to reduce GHG and other emissions; purchase emission credits; and utilize electric-driven compression at facilities to obtain regulatory permits and approvals in a timely manner.

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 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. Recently, on March 26, 2015, the Bureau of Land Management (BLM) published final rules for hydraulic fracturing on federal and certain tribal lands, including use of tanks for recovered water, updated cementing and testing requirements, and disclosure of chemicals used in hydraulic fracturing. Although we are reviewing these amendments, there is no expected material cost associated with the Company's 2015 program.

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EP ENERGY LLC

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(Unaudited)

7. Commitments and Contingencies (Continued)

Comprehensive Environmental Response, Compensation and Liability Act (CERCLA) Matters. As part of our environmental remediation projects, we are or have received notice that we could be designated as a Potentially Responsible Party (PRP) with respect to one active site under the CERCLA or state equivalents. As of March 31, 2015, we have estimated our share of the remediation costs at this site to be less than $1 million. Because the clean-up costs are estimates and are subject to revision as more information becomes available about the extent of remediation required, and because in some cases we have asserted a defense to any liability, our estimates could change. Moreover, liability under the federal CERCLA statute may be joint and several, meaning that we could be required to pay in excess of our pro rata share of remediation costs. Our understanding of the financial strength of other PRPs has been considered, where appropriate, in estimating our liabilities. Accruals for these matters are included in the reserve for environmental matters discussed above.

8. Long-Term Incentive Compensation

Our long-term incentive (LTI) programs currently include a cash-based incentive and certain equity-based compensation awards, as further described in our 2014 Annual Report on Form 10-K. A summary of the changes in our parent's non-vested restricted shares for the quarter ended March 31, 2015 is presented below:

			Weighted Average Grant Date Fair Value per Share

Non-vested at December 31, 2014	1,033,394		$	19.80
Granted	3,538,385			9.38
Vested	(2,564	)		19.82
Forfeited	(7,223	)		16.21

Non-vested at March 31, 2015	4,561,992		$	11.72

We record compensation expense on our LTI awards as general and administrative expense over the requisite service period, net of estimates of forfeitures. Pre-tax compensation expense related to all of our parent's LTI awards (both equity-based and cash-based) was approximately $5 million and $9 million during the quarters ended March 31, 2015 and 2014, respectively. As of March 31, 2015, we had unrecognized compensation expense of $69 million. We will recognize an additional $17 million related to outstanding awards as of March 31, 2015 during the remainder of 2015, $36 million over the

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EP ENERGY LLC

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(Unaudited)

8. Long-Term Incentive Compensation (Continued)

remaining requisite service periods subsequent to 2015 and $16 million upon a specified capital transaction when the right to such amounts become non-forfeitable.

9. Related Party Transactions

Management Fee Agreement. In January 2014, we paid a quarterly management fee of $6.25 million to our private equity investors (affiliates of Apollo, Riverstone Holdings LLC, Access Industries and Korea National Oil Corporation, collectively the Sponsors). We recorded this fee in general and administrative expense. Our Management Fee Agreement with the Sponsors, including the obligation to pay the quarterly management fee, terminated automatically in accordance with its terms upon the closing of our parent's initial public offering in January 2014.

Affiliate Supply Agreement. For the quarter ended March 31, 2015, we have recorded approximately $7 million in capital expenditures for amounts provided under two supply agreements entered into with an Apollo affiliate to provide certain fracturing materials for our Eagle Ford drilling operations.

Cash Management Agreement. On March 26, 2014, we entered into a cash management agreement with our parent, EP Energy Corporation (our parent), where we will provide cash management services and provide funds for its expenditures. All funds advanced pursuant to this agreement will be considered interest-bearing loans payable on demand. Interest will be paid on the net cumulative daily balance using one-month LIBOR plus an applicable LIBOR loan margin.

Contribution from Parent. During the first quarter of 2015, we received a cash contribution from our parent of $20 million. Subsequent to our parent's initial public offering in 2014, they contributed $186 million in cash to us.

Taxes. We are party to a tax accrual policy with our parent whereby our parent files U.S. and certain state tax returns on our behalf. At March 31, 2015, we had federal income tax payable due to parent of $5 million. For the quarter ended March 31, 2014, we were a partnership not subject to federal and state income taxes.

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Report of Independent Registered Public Accounting Firm

The Board of Directors of
EP Energy Corporation

We have audited the accompanying consolidated balance sheets of EP Energy LLC as of December 31, 2014 and 2013, and the related consolidated statements of income, comprehensive income, cash flows and changes in equity for each of the two years in the period ended December 31, 2014 (Successor), the period from March 23, 2012 to December 31, 2012 (Successor), and the period from January 1, 2012 to May 24, 2012 (Predecessor). These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.

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 provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of EP Energy LLC at December 31, 2014 and 2013, and the consolidated results of its operations and its cash flows for each of the two years in the period ended December 31, 2014 (Successor), the period from March 23, 2012 to December 31, 2012 (Successor), and the period from January 1, 2012 to May 24, 2012 (Predecessor), in conformity with U.S. generally accepted accounting principles.


		/s/ Ernst & Young LLP

Houston, Texas
February 20, 2015

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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, 2014			Year Ended December 31 2013


Operating revenues
Oil	$	1,705		$	1,254		$	499		$	310
Natural gas		284			300			216			228
NGLs		110			74			28			29
Financial derivatives		985			(52	)		(62	)		365

Total operating revenues		3,084			1,576			681			932

Operating expenses
Natural gas purchases		23			25			19			—
Transportation costs		100			85			48			45
Lease operating expense		193			147			63			80
General and administrative		160			228			358			69
Depreciation, depletion and amortization		875			585			188			307
Impairment and ceiling test charges		2			2			1			62
Exploration and other expense		25			41			40			—
Taxes, other than income taxes		129			79			36			31

Total operating expenses		1,507			1,192			753			594
										��
Operating income (loss)		1,577			384			(72	)		338
Other income (expense)		1			(12	)		(1	)		(3	)
Loss on extinguishment of debt		—			(9	)		(14	)		—
Interest expense		(316	)		(321	)		(218	)		(14	)

Income (loss) from continuing operations before income taxes		1,262			42			(305	)		321
Income tax expense		1,121			—			—			134

Income (loss) from continuing operations		141			42			(305	)		187
Income (loss) from discontinued operations, net of tax		7			507			50			(9	)

Net income (loss)	$	148		$	549		$	(255	)	$	178

See accompanying notes.

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EP ENERGY LLC

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(In millions)

	Successor							Predecessor

					March 23 (inception) to December 31, 2012
	Year Ended December 31, 2014		Year Ended December 31, 2013					January 1 to May 24, 2012


Net income (loss)	$	148	$	549	$	(255	)	$	178
Cash flow hedging activities:
Reclassification adjustment(1)		—		—		—			3

Comprehensive income (loss)	$	148	$	549	$	(255	)	$	181

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

See accompanying notes.

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EP ENERGY LLC

CONSOLIDATED BALANCE SHEETS

(In millions)

	December 31, 2014		December 31, 2013

ASSETS
Current assets
Cash and cash equivalents	$	21	$	48
Accounts receivable
Customer, net of allowance of less than $1 in 2014 and 2013		234		231
Other, net of allowance of $1 for 2014 and 2013		38		40
Materials and supplies		25		20
Derivative instruments		752		47
Assets of discontinued operations		—		293
Prepaid assets		7		10

Total current assets		1,077		689

Property, plant and equipment, at cost
Oil and natural gas properties		10,241		8,136
Other property, plant and equipment		76		56

		10,317		8,192
Less accumulated depreciation, depletion and amortization		1,589		770

Total property, plant and equipment, net		8,728		7,422

Other assets
Derivative instruments		297		97
Unamortized debt issue costs		90		111
Other		2		7

		389		215

Total assets	$	10,194	$	8,326



LIABILITIES AND EQUITY
Current liabilities
Accounts payable
Trade	$	142	$	135
Other		402		382
Deferred income taxes		251		—
Derivative instruments		1		35
Accrued interest		53		54
Asset retirement obligations		2		2
Liabilities of discontinued operations		—		125
Other accrued liabilities		47		64

Total current liabilities		898		797

Long-term debt		4,598		4,039
Other long-term liabilities
Deferred income taxes		869		—
Asset retirement obligations		40		28
Other		7		7

Total non-current liabilities		5,514		4,074

Commitments and contingencies (Note 7)
Member's equity		3,782		3,455

Total liabilities and equity	$	10,194	$	8,326

See accompanying notes.

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EP ENERGY LLC

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In millions)

	Successor									Predecessor

							March 23 (inception) to December 31, 2012
	Year Ended December 31, 2014			Year Ended December 31, 2013						January 1 to May 24, 2012


Cash flows from operating activities
Net income (loss)	$	148		$	549		$	(255	)	$	178
Adjustments to reconcile net income (loss) to net cash provided by operating activities
Depreciation, depletion and amortization		883			666			268			319
Gain on sale of assets		(2	)		(468	)		—			—
Deferred income tax expense		1,120			1			1			199
Loss from unconsolidated affiliates, net of cash distributions		—			37			15			12
Impairment and ceiling test charges		20			46			1			62
Loss on extinguishment of debt		—			9			14			—
Share-based compensation expense		13			22			17			—
Non-cash portion of exploration expense		19			39			23			—
Amortization of debt issuance costs		21			21			12			7
Other		2			1			1			—
Asset and liability changes
Accounts receivable		8			(51	)		(73	)		132
Accounts payable		17			80			66			(56	)
Derivative instruments		(939	)		56			281			(201	)
Accrued interest		—			(3	)		57			(1	)
Other asset changes		4			(10	)		(18	)		(7	)
Other liability changes		(19	)		(20	)		39			(64	)

Net cash provided by operating activities		1,295			975			449			580

Cash flows from investing activities
Capital expenditures		(2,033	)		(1,924	)		(877	)		(636	)
Proceeds from the sale of assets and investments, net of cash transferred		154			1,451			110			9
Cash paid for acquisitions, net of cash acquired		(165	)		(2	)		(7,126	)		(1	)
Increase in note receivable with parent		(20	)		—			—			—

Net cash used in investing activities		(2,064	)		(475	)		(7,893	)		(628	)

Cash flows from financing activities
Proceeds from issuance of long-term debt		2,455			1,880			5,477			215
Repayment of long-term debt		(1,898	)		(2,190	)		(1,139	)		(1,065	)
Distributions to member		—			(200	)		—			—
Contributions from member		—			—			3,323			—
Contributions from parent		186			—			—			960
Debt issuance costs		(1	)		(5	)		(154	)		—

Net cash provided by (used in) financing activities		742			(515	)		7,507			110

Change in cash and cash equivalents		(27	)		(15	)		63			62
Cash and cash equivalents
Beginning of period		48			63			—			25

End of period	$	21		$	48		$	63		$	87



Supplemental cash flow information
Interest paid, net of amounts capitalized	$	289		$	305		$	145		$	7
Income tax payments, net of refunds		3			4			2			2

See accompanying notes.

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EP ENERGY LLC

CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY

(In millions)

			Common Stock		Additional Paid-in Capital			Retained Earnings (Accumulated deficit)			Accumulated Other Comprehensive Income			Total Stockholder's / Member's Equity

Predecessor
Balance at January 1, 2012	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 contribution				—		—			—			—			3,323
Share-based compensation				—		—			—			—			17
Net loss				—		—			—			—			(255	)

Balance at December 31, 2012			$	—	$	—		$	—		$	—		$	3,085
Member distributions				—		—			—			—			(200	)
Share-based compensation				—		—			—			—			22
Other				—		—			—			—			(1	)
Net loss				—		—			—			—			549

Balance at December 31, 2013			$	—	$	—		$	—		$	—		$	3,455
Share-based compensation				—		—			—			—			13
Cash contributions from parent				—		—			—			—			186
Net income				—		—			—			—			148
Distribution to parent				—		—			—			—			(20	)

Balance at December 31, 2014			$	—	$	—		$	—		$	—		$	3,782

See accompanying notes.

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EP ENERGY LLC

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

1. Basis of Presentation and Significant Accounting Policies

Basis of Presentation and Consolidation

EP Energy LLC (the successor) was formed as a Delaware limited liability company on March 23, 2012 by investment funds affiliated with and managed by Apollo Global Management LLC (together with its subsidiaries, Apollo) and other private equity investors (collectively, the Sponsors). On April 24, 2012, we issued approximately $2.75 billion in private placement notes. Proceeds from these notes, along with other sources, were used by the Sponsors to acquire EP Energy Global LLC (formerly known as EP Energy Corporation and EP Energy, L.L.C. after its conversion into a Delaware limited liability company) and subsidiaries for approximately $7.2 billion on May 24, 2012, from El Paso Corporation (El Paso) immediately prior to and in connection with its merger with Kinder Morgan, Inc. (KMI) which is further described in Note 2. The acquired entities engage in the exploration for and the acquisition, development, and production of oil, natural gas and NGLs in the United States. EP Energy Global LLC constituted the oil and natural gas operations of El Paso prior to the Acquisition. Hereinafter, we refer to the May 24, 2012 transaction as the Acquisition and the acquired entities prior to the Acquisition are referred to as the predecessor for financial accounting and reporting purposes.

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

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

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

New Accounting Pronouncements Issued But Not Yet Adopted

The following accounting standards have been issued but not yet been adopted.

Revenue Recognition. In May 2014, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update No. 2014-09,Revenue from Contracts with Customers, which clarifies the principles for recognizing revenue and develops a common revenue standard for U.S. GAAP and International Financial Reporting Standards. Retrospective application of this standard is required beginning in the first quarter of 2017. We are currently evaluating the impact, if any, that this update will have on our financial statements.

Discontinued Operations. In April 2014, the FASB issued Accounting Standards Update No. 2014-08,Presentation of Financial Statements and Property, Plant, and Equipment: Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity, which alters the

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EP ENERGY LLC

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)

1. Basis of Presentation and Significant Accounting Policies (Continued)

criteria under which assets to be disposed of are evaluated for reporting as a discontinued operation. While early adoption of this update is permitted, prospective application is required in the first quarter of 2015. Accordingly, the update will not impact our historical presentation of assets as discontinued operations. The revised standard will (i) raise the threshold for divestitures to qualify as discontinued operations and (ii) require new disclosures for both discontinued operations and material divestitures which do not qualify as discontinued operations.

Significant Accounting Policies

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

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

For the years ended December 31, 2014 and 2013 and the successor period in 2012, we had two customers that individually accounted for 10 percent or more of our total revenues. The predecessor period in 2012 had three customers that individually accounted for 10 percent or more of total revenues. The loss of any one customer would not have an adverse effect on our ability to sell our oil, natural gas and NGLs production.

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, 2014 and 2013, we had less than $1 million, of restricted cash in other current assets to cover escrow amounts required for leasehold agreements in our operations.

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EP ENERGY LLC

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)

1. Basis of Presentation and Significant Accounting Policies (Continued)

Allowance for Doubtful Accounts

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

Oil and Natural Gas Properties

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

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

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

We evaluate capitalized costs related to proved properties at least annually or upon a triggering event to determine if impairment of such properties is necessary. Our evaluation of recoverability 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. 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, estimated or published commodity prices as of the date of the estimate, adjusted for geographical location, contractual and quality differentials, estimates of future operating and development costs, and a risk-adjusted discount rate. The discount rate is based on rates utilized by market participants that are commensurate with the risks inherent in the development and production of the underlying crude oil and natural gas. Leasehold acquisitions costs associated with non-producing areas are assessed for impairment by major prospect area based on our estimates or current drilling plans.

Full Cost (Predecessor). Prior to the Acquisition, the predecessor used the full cost method to account for their oil and natural gas properties. Under the full cost method, substantially all costs incurred in connection with the acquisition, development and exploration of oil and natural gas reserves were capitalized on a country-by-country basis. These capitalized amounts included the costs of unproved properties that were transferred into the full cost pool when the properties were determined to have proved reserves, internal costs directly related to acquisition, development and exploration

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1. Basis of Presentation and Significant Accounting Policies (Continued)

activities, asset retirement costs and capitalized interest. Under the full cost method, both dry hole costs and geological and geophysical costs were capitalized into the full cost pool, which was subject to amortization and was periodically assessed for impairment through a ceiling test calculation discussed below.

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

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

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

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

Accounting for Asset Retirement Obligations

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

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1. Basis of Presentation and Significant Accounting Policies (Continued)

the value of the liability as a result of the passage of time, which we record as depreciation, depletion and amortization expense in our consolidated income statement.

Accounting for Long-Term Incentive Compensation

We measure the cost of long-term incentive compensation based on the grant date fair value of the award. Awards issued under these programs are recognized as either equity awards or liability awards based on their characteristics. Expense is recognized in our consolidated financial statements as general and administrative expense over the requisite service period, net of estimated forfeitures. See Note 8 for further discussion of our long-term incentive compensation.

Environmental Costs, Legal and Other Contingencies

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

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

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

Derivatives

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

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1. Basis of Presentation and Significant Accounting Policies (Continued)

All of our derivatives are marked-to-market each period and changes in the fair value of our commodity based derivatives, as well as any realized amounts, are reflected as operating revenues. Changes in the fair value of our interest rate derivatives are reflected as interest expense. We classify cash flows related to derivative contracts based on the nature and purpose of the derivative. As the derivative cash flows are considered an integral part of our oil and natural gas operations, they are classified as cash flows from operating activities. In our consolidated balance sheet, receivables and payables resulting from the settlement of our derivative instruments are reported as trade receivables and payables. See Note 4 for a further discussion of our derivatives.

Income Taxes

On December 31, 2014, we simplified our structure and as a result became a division of a corporation subject to federal and state income taxes. From May 25, 2012 to December 31, 2014, we were a limited liability company, treated as a partnership for federal and state income tax purposes, with income tax liabilities and/or benefits passed through to our member.

The realization of our deferred tax assets depends on recognition of sufficient future taxable income 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 eligible carryback years, various 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 was 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 April 30, 2014, we acquired producing properties and undeveloped acreage in the Southern Midland Basin, of which 37,000 net acres are adjacent to our existing Wolfcamp Shale position, for an aggregate cash purchase price of approximately $152 million. The acquisition represented an approximate 25% expansion of our current Wolfcamp acreage. The fair value of the business acquired was allocated to the underlying properties and no goodwill or bargain purchase was recorded.

On May 24, 2012, investment funds managed by Apollo (collectively, "the Apollo Funds") and other investors acquired all of the equity of EP Energy Global LLC for approximately $7.2 billion. The Acquisition was funded with approximately $3.3 billion in equity contributions and the issuance of approximately $4.25 billion of debt. In conjunction with the Acquisition, a portion of the proceeds were

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2. Acquisitions and Divestitures (Continued)

also used to repay approximately $960 million outstanding under the predecessor's revolving credit facility at that time. See Note 6 for additional discussion of debt.

The unaudited pro forma information below for the year ended December 31, 2012 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, 2012. 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

	(in millions)
Operating Revenues	$	1,659
Net Income		143

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 consolidated income statement. Additionally, during the successor period in 2012 we recorded approximately $48 million related to transition and restructuring costs, including severance charges totaling approximately $17 million ($4 million related to divested assets). These amounts were included as general and administrative expenses in our consolidated income statement.

Discontinued Operations. We have reflected as discontinued operations certain non-core assets sold including (i) certain domestic natural gas assets in our Arklatex area and those in our South Louisiana Wilcox areas sold in May 2014, (ii) domestic natural gas assets which closed in June 2013 (including CBM properties located in the Raton, Black Warrior and Arkoma basins; Arklatex conventional natural gas assets located in East Texas and North Louisiana, and legacy South Texas conventional natural gas assets) and (iii) our Brazilian operations which closed in August 2014.

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

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2. Acquisitions and Divestitures (Continued)

Summarized operating results and financial position data of our discontinued operations were as follows:

	Successor							Predecessor

						March 23 (inception) to December 31, 2012
	Year ended December 31, 2014		Year ended December 31, 2013					January 1 to May 24, 2012


						(in millions)
Operating revenues	$	82	$	361		$	309	$	46

Operating expenses
Natural gas purchases		—		19			23		—
Transportation costs		5		25			25		—
Lease operating expense		31		92			74		16
Depreciation, depletion and amortization		8		81			80		12
Impairment and ceiling test charges(1)		18		44			—		—
Other expense		17		53			58		20

Total operating expenses		79		314			260		48

Gain on sale of assets		2		468			—		—
Other income (expense)		4		(2	)		3		(5	)

Income (loss) from discontinued operations before income taxes		9		513			52		(7	)
Income tax expense		2		6			2		2

Income (loss) from discontinued operations, net of tax	$	7	$	507		$	50	$	(9	)

(1): During the year ended December 31, 2014, we recorded $18 million in impairment charges to impair earnings subsequent to entering into a Quota Purchase Agreement to sell our Brazil operations. During the year ended December 31, 2013, we recorded $44 million in impairment charges ($34 million to impair earnings subsequent to entering into the Quota Purchase Agreement and $10 million based on a comparison of the fair value of our Brazil operations to its underlying carrying value).

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2. Acquisitions and Divestitures (Continued)

	December 31, 2013

	(in millions)
Assets of discontinued operations
Current assets	$	37
Property, plant and equipment, net		246
Other non-current assets		10

Total assets of discontinued operations	$	293



Liabilities of discontinued operations
Accounts payable	$	50
Other current liabilities		10
Asset retirement obligations		60
Other non-current liabilities		5

Total liabilities of discontinued operations	$	125

Other Divestitures. In 2014, we closed the sale of certain non-core acreage in Eagle Ford in Atascosa County for approximately $28 million. No gain or loss on the sale was recorded. During 2013, we (i) received approximately $10 million from the sale of certain domestic oil and natural gas properties and (ii) sold our approximate 49% equity interest in Four Star Oil & Gas Company (Four Star) for proceeds of approximately $183 million. We did not record a gain or loss on the sale of these other domestic properties; however, in connection with entering into the sale of Four Star, we recorded a $20 million impairment in earnings from unconsolidated affiliates. See Note 9 for further discussion.

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

3. Income Taxes

General. On December 31, 2014, we simplified our structure and as a result we became a division of a corporation subject to federal and state income taxes. Upon the change in tax status, we recorded deferred income tax expense of $1,121 million as a result of recording net deferred tax liabilities for initial temporary differences at that date. No current tax liability or expense was incurred as of the date of the change in status. From May 25, 2012, until December 31, 2014, we were a limited liability company treated as a partnership for federal and state income tax purposes. During that time, our Brazil operations continued to be subject to foreign income taxes; however, amounts related to Brazil have been reclassified in all periods as discontinued operations (see Note 2).

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NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)

3. Income Taxes (Continued)

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

	Successor							Predecessor

					March 23 (inception) to December 31, 2012			January 1 to May 24, 2012
	Year ended December 31, 2014		Year ended December 31, 2013


			(in millions)
Pretax Income (Loss)
U.S.	$	1,262	$	42	$	(305	)	$	384
Foreign		—		—		—			(63	)

	$	1,262	$	42	$	(305	)	$	321



Components of Income Tax Expense (Benefit)
Current
Federal	$	—	$	—	$	—		$	(62	)
State		—		—		—			(3	)

		—		—		—			(65	)

Deferred
Federal		1,072		—		—			188
State		49		—		—			11

		1,121		—		—			199

Total income tax expense	$	1,121	$	—	$	—		$	134

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% for the following reasons for the following periods:

	Successor									Predecessor

							March 23 (inception) to December 31, 2012			January 1 to May 24, 2012
	Year ended December 31, 2014			Year ended December 31, 2013


				(in millions)
Income taxes at the statutory federal rate of 35%	$	442		$	15		$	(107	)	$	112
Increase (decrease)
State income taxes, net of federal income tax effect		—			—			—			5
Partnership earnings not subject to tax		(442	)		(15	)		107			—
Earnings from unconsolidated affiliates where we received or will receive dividends		—			—			—			(2	)
Foreign income taxed at different rates		—			—			—			22
Change of entity tax status		1,121			—			—			—
Other		—			—			—			(3	)

Income tax expense	$	1,121		$	—		$	—		$	134

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3. Income Taxes (Continued)

The effective tax rate for the year ended December 31, 2014 was significantly higher than the statutory rate due to recording deferred income tax expense associated with recording initial net deferred tax liabilities upon our change in tax status. Prior to December 31, 2014, our earnings were not subject to federal and state income tax as we were a limited liability company treated as a partnership. The effective tax rate for both the year ended December 31, 2013 and the period from March 23 (inception) to December 31, 2012 was significantly lower than the statutory rate as we were a limited liability company, treated as a partnership for federal and state income tax purposes, with income tax liabilities and/or benefits of the Company passed through to our members. The effective tax rate for the predecessor period from January 1, 2012 to May 24, 2012 was significantly higher than the statutory rate primarily due to the impact of an Egyptian non-cash charge without a corresponding tax benefit.

Deferred Tax Assets and Liabilities. The change in tax status required the recognition of a deferred tax asset or liability for the initial temporary differences at the time of the change in status on December 31, 2014. The following are the components of net deferred tax assets and liabilities:

	December 31, 2014

	(in millions)
Deferred tax assets
Employee benefits	$	1
Legal and other reserves		5
Asset retirement obligations		15
Transaction costs		20

Total deferred tax assets	$	41

Deferred tax liabilities
Property, plant and equipment	$	794
Financial derivatives		367

Total deferred tax liabilities		1,161

Net deferred tax liabilities	$	1,120

Unrecognized Tax Benefits. We are currently not under any U.S. or state income tax audits; however, the 2013 and 2014 tax years remain open to examination. Furthermore, pursuant to the Acquisition agreement, KMI indemnified us for any U.S. or state 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. As of December 31, 2014 there were no unrecognized tax benefits as income taxes in our financial statements in continuing operations. We did not recognize any interest and penalties related to unrecognized tax benefits (classified as income taxes in our consolidated income statements) in 2014 or 2013, nor do we have any accrued interest and penalties in our consolidated balance sheet as of December 31, 2014 and December 31, 2013.

Valuation Allowances. The realization of our deferred tax assets depends on recognition of sufficient future taxable income in specific tax jurisdictions during periods in which those temporary differences are deductible. Valuation allowances are established when necessary to reduce deferred

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3. Income Taxes (Continued)

income tax assets to the amounts we believe are more likely than not to be recovered. As of December 31, 2014, we had no valuation allowances recorded on our deferred tax assets.

4. Financial Instruments

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

	December 31, 2014				December 31, 2013

	Carrying Amount		Fair Value		Carrying Amount		Fair Value
			(in millions)
Long-term debt	$	4,598	$	4,582	$	4,039	$	4,451



Derivative instruments	$	1,048	$	1,048	$	109	$	109

For the years ended December 31, 2014 and 2013, the carrying amount of cash and cash equivalents, accounts receivable and accounts payable represent fair value because of the short-term nature of these instruments. We hold long-term debt obligations (see Note 6) with various terms. We estimated the fair value of debt (representing a Level 2 fair value measurement) primarily based on quoted market prices for the same or similar issuances, including consideration of our credit risk related to these instruments.

Oil and Natural Gas Derivative Instruments. We attempt to mitigate a portion of our commodity price risk and stabilize cash flows associated with forecasted sales of oil and natural gas through the use of financial derivatives. As of December 31, 2014 and 2013, we had total derivative contracts of 37 MMBbls and 47 MMBbls of oil and 69 TBtu and 135 TBtu of natural gas, respectively. None of these contracts are designated as accounting hedges.

The following table reflects the volumes associated with derivative contracts entered into between January 1, 2015 and February 16, 2015.



Oil (MBbls)
Fixed Price Swaps
WTI(1)	3,294	4,015
Basis Swaps
LLS vs. WTI(2)	1,830	—

(1): In February 2015, we unwound 3,294 MBbls of 2016 LLS three way collars in exchange for 3,294 MBbls of 2016 WTI fixed price swaps. No cash or other consideration was included as part of this exchange.
(2): In February 2015, we unwound 1,830 MBbls of 2016 LLS vs. Brent basis swaps in exchange for 1,830 MBbls of 2016 LLS vs. WTI basis swaps. No cash or other consideration was included as part of this exchange.

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4. Financial Instruments (Continued)

Interest Rate Derivative Instruments. We have interest rate swaps with a notional amount of $600 million that extend through April 2017 and are intended to reduce variable interest rate risk. As of December 31, 2014 and 2013, we had a net asset of $3 million and $4 million, respectively, related to interest rate derivative instruments included in our consolidated balance sheets. For the years ended December 31, 2014 and 2013 and the period from March 23 (inception) to December 31, 2012, we recorded $5 million of interest expense, $3 million of interest income and $3 million of interest expense, respectively, related to the change in fair market value and cash settlements of our interest rate derivative instruments.

•: 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, 2014 and 2013, all derivative financial instruments were classified as Level 2. Our assessment of an instrument within a level can change over time based on the maturity or liquidity of the instrument, which could result in a change in the classification of our financial instruments between other levels.

Financial Statement Presentation. The following table presents the fair value associated with derivative financial instruments as of December 31, 2014 and 2013. All of our derivative instruments are subject to master netting arrangements which provide for the unconditional right of offset for all derivative assets and liabilities with a given counterparty in the event of default. We present assets and liabilities related to these instruments in our balance sheets as either current or non-current assets or liabilities based on their anticipated settlement date, net of the impact of master netting agreements.

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4. Financial Instruments (Continued)

On derivative contracts recorded as assets in the table below, we are exposed to the risk that our counterparties may not perform.

	Level 2

	Derivative Assets									Derivative Liabilities
						Balance Sheet Location									Balance Sheet Location
	Gross(1) Fair Value		Impact of Netting			Balance Sheet Location				Gross(1) Fair Value			Impact of Netting		Balance Sheet Location
	Gross(1) Fair Value		Impact of Netting			Current		Non-current		Gross(1) Fair Value			Impact of Netting		Current			Non-current
	(in millions)									(in millions)
December 31, 2014
Derivative instruments	$	1,093	$	(44	)	$	752	$	297	$	(45	)	$	44	$	(1	)	$	—



December 31, 2013
Derivative instruments	$	164	$	(20	)	$	47	$	97	$	(55	)	$	20	$	(35	)	$	—

(1): Gross derivative assets are comprised primarily of $1,088 million of oil and natural gas derivatives as of December 31, 2014, $157 million of oil and natural gas derivatives as of December 31, 2013, and $5 million and $7 million of interest rate derivatives as of December 31, 2014 and December 31, 2013, respectively. Gross derivative liabilities are comprised primarily of $43 million of oil and natural gas derivatives as of December 31, 2014, $52 million of oil and natural gas derivatives as of December 31, 2013 and $2 million and $3 million of interest rate derivatives as of December 31, 2014 and December 31, 2013, respectively.

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

	Successor								Predecessor

						March 23 (inception) to December 31, 2012			January 1 to May 24, 2012
	Year ended December 31, 2014		Year ended December 31, 2013


Gains (losses) on financial derivative instruments	$	985	$	(52	)	$	(62	)	$	365
Accumulated other comprehensive income		—		—			—			5

Credit Risk. We are subject to the risk of loss on our derivative instruments that we would incur as a result of non-performance by counterparties pursuant to the terms of their contractual obligations. We maintain credit policies with regard to our counterparties to minimize our overall credit risk. These policies require (i) the evaluation of potential counterparties' financial condition to determine their credit worthiness; (ii) the daily monitoring of our oil, natural gas and NGLs counterparties' credit exposures; (iii) comprehensive credit reviews on significant counterparties from physical and financial transactions on an ongoing basis; (iv) the utilization of contractual language that affords us netting or set off opportunities to mitigate exposure risk; and (v) when appropriate requiring counterparties to post cash collateral, parent guarantees or letters of credit to minimize credit risk. Our assets related to derivatives as of December 31, 2014 represent financial instruments from twelve counterparties; all of which are financial institutions that have an "investment grade" (minimum Standard & Poor's rating of A- or better) credit rating and are lenders associated with our $2.75 billion RBL credit facility. Subject

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4. Financial Instruments (Continued)

to the terms of our $2.75 billion RBL credit facility, collateral or other securities are not exchanged in relation to derivatives activities with the parties in the RBL Facility.

5. Property, Plant and Equipment

Oil and Natural Gas Properties. As of December 31, 2014 and 2013, we had approximately $8.7 billion and $7.4 billion of total property, plant, and equipment, net of accumulated depreciation, depletion, and amortization on our balance sheet, substantially all of which related to both proved and unproved oil and natural gas properties. At December 31, 2014 and 2013, the cost associated with unproved oil and natural gas properties totaled approximately $0.7 billion and $1.4 billion, respectively. During 2014, we transferred approximately $0.7 billion from unproved properties to proved properties. During 2014, 2013 and the period from March 23 to December 31, 2012, we recorded $18 million, $36 million and $23 million, respectively, of amortization of unproved leasehold costs in exploration expense in our consolidated income statement. Suspended well costs were not material as of December 31, 2014 or December 31, 2013.

Impairment Assessment / Ceiling Test Charges. Forward commodity prices can play a significant role in determining future impairments of our proved or unproved property. Due to the significant decline in oil prices in the fourth quarter of 2014, we reviewed our proved and unproved property for impairment. In 2014, 2013 and from the Acquisition (May 25, 2012) to December 31, 2012, all periods under which we applied the successful efforts method, we did not record any impairments of our oil and gas properties included in continuing operations. Under the full cost method of accounting, the predecessor recorded a non-cash charge of approximately $62 million in the period from January 1 to May 24, 2012, as a result of the decision to exit exploration and development activities in Egypt. The charge related to unevaluated costs in that country and included approximately $2 million related to equipment. Considering the significant amount of fair value allocated to our natural gas and oil properties in conjunction with the Acquisition, sustained lower oil and natural gas prices, further price reductions or changes to our future capital and development plans due to the lower price environment could result in an impairment of the carrying value of our proved and/or unproved properties in the future, and such charges could be significant.

Leasehold acquisition costs associated with non-producing areas are assessed for impairment based on our estimated drilling plans and capital expenditures relative to potential lease expirations. Our unproved property costs were approximately $0.7 billion at December 31, 2014, of which approximately $0.4 billion was associated with Wolfcamp, $0.2 billion with Altamont and $0.1 billion with Eagle Ford. 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 activities. Our allocation of capital to the development of unproved properties may be influenced by changes in commodity prices (e.g. the rapid decline in oil prices in the fourth quarter of 2014), the availability of drilling rigs and associated costs, and/or the relative returns of our unproved property development in comparison to the use of capital for other strategic objectives. Due to the significant decline in oil prices, we have reduced our expected capital expenditures in certain of our operating areas for 2015; however, we currently have the intent and ability to fulfill our drilling commitments prior to the expiration of the associated leases. Among other factors, should oil prices not justify sufficient capital allocation to the continued development of these unproved properties, we could incur impairment charges of our unproved property, and such charges could be significant.

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NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)

5. Property, Plant and Equipment (Continued)

In estimating the liability associated with our asset retirement obligations, we utilize several assumptions, including a credit-adjusted risk-free rate of between 7-9 percent and a projected inflation rate of 2.5 percent. Changes in estimates in the table below represent changes to the expected amount and timing of payments to settle our asset retirement obligations. Typically, these changes primarily result from obtaining new information about the timing of our obligations to plug and abandon oil and natural gas wells and the costs to do so. The net asset retirement liability as of December 31 on our consolidated balance sheet in other current and non-current liabilities and the changes in the net liability for the periods ended December 31 were as follows:

	2014			2013

	(in millions)
Net asset retirement liability at January 1	$	30		$	24
Liabilities incurred		10			6
Liabilities settled		(2	)		(2	)
Accretion expense		3			2
Changes in estimate		2			1
Property sales		—			(1	)
Other		(1	)		—

Net asset retirement liability at December 31	$	42		$	30

Capitalized Interest. Interest expense is reflected in our financial statements net of capitalized interest. We capitalize interest primarily on the costs associated with drilling and completing wells until production begins. The interest rate used is the weighted average interest rate of our outstanding borrowings. Capitalized interest for the year ended December 31, 2014 and 2013 was approximately $21 million and $19 million, respectively. For the period from March 23, 2012 (inception) to December 31, 2012, capitalized interest was $12 million, and for the predecessor period from January 1, 2012 to May 24, 2012, it was $4 million.

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NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)

6. Long Term Debt

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

	Interest Rate	December 31, 2014		December 31, 2013

		(in millions)
$2.75 billion RBL credit facility—due May 24, 2017	Variable	$	852	$	295
$750 million senior secured term loan—due May 24, 2018(1)(3)	Variable		496		495
$400 million senior secured term loan—due April 30, 2019(2)(3)	Variable		150		149
$750 million senior secured notes—due May 1, 2019(3)	6.875%		750		750
$2.0 billion senior unsecured notes—due May 1, 2020	9.375%		2,000		2,000
$350 million senior unsecured notes—due September 1, 2022	7.75%		350		350

Total		$	4,598	$	4,039

(1): The term loan was issued at 99% of par and carries interest at a specified margin over the LIBOR of 2.75%, with a minimum LIBOR floor of 0.75%. As of December 31, 2014 and 2013, the effective interest rate of the term loan was 3.50%.
(2): The term loan carries interest at a specified margin over the LIBOR of 3.50%, with a minimum LIBOR floor of 1.00%. As of December 31, 2014 and 2013, the effective interest rate for the term loan was 4.50%.
(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, 2014 and 2013, we had $90 million and $111 million, respectively, in deferred financing costs on our consolidated balance sheets. During 2014, 2013, the period from March 23 (inception) to December 31, 2012, and the predecessor period from January 1 to May 24, 2012, we amortized $21 million, $21 million, $12 million, and $7 million, respectively, of deferred financing costs in interest expense.

During 2013 and the period from March 23 (inception) to December 31, 2012, we recorded $9 million and $14 million in losses on extinguishment of debt. The 2013 losses were associated with the pro-rata portion of deferred financing costs written off in conjunction with (i) the repayment of approximately $250 million under each of our $750 million and $400 million term loans, (ii) our $750 million term loan re-pricing in May 2013 and (iii) the semi-annual redetermination of our RBL Facility in March 2013. The 2012 losses were associated with 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.

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NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)

6. Long Term Debt (Continued)

$2.75 Billion Reserve-based Loan (RBL). We have a $2.75 billion credit facility in place which allows us to borrow funds or issue letters of credit (LCs). As of December 31, 2014, we had $852 million of outstanding borrowings and approximately $83 million of letters of credit issued under the facility, leaving $1.8 billion of remaining capacity available. During 2014, we received a contribution from our parent subsequent to their initial public offering to pay down a portion of our then outstanding balance. Listed below is a further description of our credit facility as of December 31, 2014:

Credit Facility		Maturity Date		Interest Rate		Commitment fees

$2.75 billion RBL		May 24, 2017		LIBOR + 1.75%(1) 1.75% for LCs		0.375% commitment fee on unused capacity

(1): Based on our December 31, 2014 borrowing level. Amounts outstanding under the $2.75 billion RBL facility bear interest at specified margins over the LIBOR of between 1.50% and 2.50% for Eurodollar loans or at specified margins over the Alternative Base Rate (ABR) of between 0.50% and 1.50% for ABR loans. Such margins will fluctuate based on the utilization of the facility.

The RBL Facility is collateralized by certain of our oil and natural gas properties and has a borrowing base subject to semi-annual redetermination. In October 2014, we completed our semi-annual redetermination, increasing the borrowing base of our RBL Facility to $2.75 billion. Our next redetermination date is in April 2015. Downward revisions of our oil and natural gas reserves due to future declines in commodity prices, performance revisions, sales of assets, or the incurrence of certain types of additional debt, among other items, could cause a redetermination of the borrowing base and could negatively impact our ability to borrow funds under the RBL Facility in the future.

Restrictive Provisions/Covenants. The availability of borrowings under our credit agreements and our ability to incur additional indebtedness is subject to various financial and non-financial covenants and restrictions. Our most restrictive financial covenant requires that our debt to EBITDAX ratio, as defined in the credit agreement, must not exceed 4.50 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, 2014, we were in compliance with our debt covenants.

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NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)

7. Commitments and Contingencies

Legal Matters

Southeast Louisiana Flood Protection Authority v. EP Energy Management, L.L.C. On July 24, 2013, the levee authority for New Orleans and surrounds (the Authority) filed suit against 97 oil, gas and pipeline companies, seeking (among other relief) restoration of wetlands allegedly lost due to historic industry operations in those areas. The suit, which does not specify an amount of damages, was filed in Louisiana state court in New Orleans but then removed to the U.S. District Court for the Eastern District of Louisiana (the District Court). The Louisiana State Legislature has passed legislation that could result in dismissal of the lawsuit. Our subsidiary, EP Energy Management, L.L.C., is named as successor to Colorado Oil Company, Inc. and Gas Producing Enterprises as operators of five wells from the mid-1970s to 1980. On February 13, 2015, the District Court dismissed the case for failure to state a claim finding that the defendants had no duty to the Authority. The Authority will have 30 days from a final judgment to appeal to the U.S. Court of Appeals for Fifth Circuit.

Indemnifications and Other Matters. We periodically enter into indemnification arrangements as part of the divestitures of assets or businesses. These arrangements include, but are not limited to, indemnifications for income taxes, the resolution of existing disputes, environmental and other contingent matters. In addition, under various laws or regulations, we could be subject to the imposition of certain liabilities. For example, the recent decline in commodity prices may create an environment where there is an increased risk that owners and/or operators of assets purchased from us may no longer be able to satisfy plugging and abandonment obligations that attach to such assets. In that event, under various laws or regulations, we may be required to assume these plugging or abandonment obligations on assets no longer owned and operated by us. As of December 31, 2014, we had approximately $8 million accrued related to these indemnifications and other matters.

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

Environmental Matters

We are subject to existing federal, state and local laws and regulations governing environmental quality, pollution control and greenhouse gas (GHG) emissions. The environmental laws and

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7. Commitments and Contingencies (Continued)

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, 2014, we had accrued approximately $1 million for related environmental remediation costs associated with onsite, offsite and groundwater technical studies and for related environmental legal costs. Our accrual represents a combination of two estimation methodologies. First, where the most likely outcome can be reasonably estimated, that cost has been accrued. Second, where the most likely outcome cannot be estimated, a range of costs is established and if no one amount in that range is more likely than any other, the lower end of the expected range has been accrued. Our exposure could be as high as $1 million. Our environmental remediation projects are in various stages of completion. The liabilities we have recorded reflect our current estimates of amounts that we will expend to remediate these sites. However, depending on the stage of completion or assessment, the ultimate extent of contamination or remediation required may not be known. As additional assessments occur or remediation efforts continue, we may incur additional liabilities.

Climate Change and Other Emissions. The EPA and several state environmental agencies have adopted regulations to regulate GHG emissions. Although the EPA has adopted a "tailoring" rule to regulate GHG emissions, the U.S. Supreme Court partially invalidated it in an opinion decided June 2014. The tailoring rule remains applicable for those facilities considered major sources of six other "criteria" pollutants and at this time we do not expect a material impact to our existing operations from the rule. 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, which will generally favor the use of natural gas over other fossil fuels such as coal. It remains uncertain what regulations or amended final rules will ultimately be adopted and when they will be adopted. As part of the White House's Climate Action Plan Strategy to Reduce Methane Emissions, the EPA has announced it will propose additional regulations in 2015 for the oil and gas industry addressing methane and other emissions. Further, the Bureau of Land Management is expected to propose additional regulations for public lands in 2015, and the Pipeline and Hazardous Materials Safety Administration is expected to propose new standards in 2015 for natural gas pipelines. Any regulations regarding GHG emissions would likely increase our costs of compliance by potentially delaying the receipt of permits and other regulatory approvals; requiring us to monitor emissions, install additional equipment or modify facilities to reduce GHG and other emissions; purchase emission credits; and utilize electric-driven compression at facilities to obtain regulatory permits and approvals in a timely manner.

In August 2012, the EPA promulgated additional standards to reduce various air pollutants associated with hydraulic fracturing of natural gas wells and equipment including compressors, storage vessels, and pneumatic valves. Parts of the new standard were amended August 2013. We do not anticipate material capital expenditures to meet these requirements. Effective December 31, 2014, additional amendments to the new standard were finalized for which we do not anticipate material capital expenditure.

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NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)

7. Commitments and Contingencies (Continued)

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

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 through 2018. Future

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7. Commitments and Contingencies (Continued)

minimum annual rental commitments under non-cancelable future operating lease commitments at December 31, 2014, were as follows:

Year Ending December 31,	Operating Leases

	(in millions)
2015	$	11
2016		12
2017		7

Total	$	30

Subsequent to December 31, 2014, we extended certain office leases and will pay an additional $5 million and $9 million in 2017 and 2018, respectively. These amounts are not included in the table above.

Rental expense for the successor periods for the years ended December 31, 2014 and 2013, and for the period from March 23, 2012 (inception) to December 31, 2012 was $13 million, $13 million and $10 million, respectively. Rental expense for the predecessor period from January 1, 2012 to May 24, 2012 was $1 million.

Other Commercial Commitments

At December 31, 2014, we have various commercial commitments totaling $809 million primarily related to commitments and contracts associated with volume and transportation, drilling rigs, completion activities and seismic activities. Our annual obligations under these arrangements are $184 million in 2015, $185 million in 2016, $83 million in 2017, $83 million in 2018, and $274 million thereafter.

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

Overview. Under our parent's, EP Energy Corporation's, current stock-based compensation plan (the EP Energy Corporation 2014 Omnibus Incentive Plan, oromnibus plan), our parent may issue to our employees and non-employee directors various forms of long term incentive (LTI) compensation including stock options, stock appreciation rights, restricted stock, restricted stock units, performance shares/units, incentive awards, cash awards, and other stock-based awards. They are authorized to grant awards of up to 12,433,749 shares of their common stock for awards under the omnibus plan, with 11,179,603 shares remaining available for issuance as of December 31, 2014. In addition, in conjunction with the Acquisition in 2012, certain employees received other LTI awards based on their purchased equity interests including (i) Class A "matching" units (subsequently converted into common shares upon our parent's Corporate Reorganization) and (ii) a "guaranteed bonus" as well as (iii) Management Incentive Units (subsequently converted into Class B shares upon our parent's Corporate Reorganization) which become payable upon certain liquidity events. At the time of our parent's 2013 Corporate Reorganization, they also issued additional Class B shares to a subsidiary for grants to current and future employees that likewise become payable upon certain liquidity events. No additional Class B shares are available for issuance.

We record stock-based compensation expense as general and administrative expense over the requisite service period, net of estimates of forfeitures. If actual forfeitures differ from our estimates,

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

additional adjustments to compensation expense will be required in future periods. All of these LTI programs are discussed further below.

Restricted stock. Our parent grants shares of restricted common stock which carry voting and dividend rights and may not be sold or transferred until they are vested. The fair value of our parent's restricted stock is determined on the date of grant and these shares generally vest in equal amounts over 3 years from the date of the grant. A summary of the changes in our parent's non-vested restricted shares for the year ended December 31, 2014 is presented below:

			Weighted Average Grant Date Fair Value per Share

Non-vested at December 31, 2013	—		$	—
Granted	1,131,154			19.80
Vested	(1,929	)		19.82
Forfeited	(95,831	)		19.82

Non-vested at December 31, 2014	1,033,394		$	19.80

During 2014 we recognized approximately $5 million of pre-tax compensation expense and recorded income tax benefits of $2 million on our parent's restricted share awards. The total unrecognized compensation cost related to these arrangements at December 31, 2014 was approximately $14 million, which is expected to be recognized over a weighted average period of 2 years.

Stock Options. Our parent grants stock options as compensation for future service at an exercise price equal to the closing share price of their stock on the grant date. Stock options granted have contractual terms of 10 years and vest in three tranches over a five-year period (with the first tranche vesting on the third anniversary of the grant date, the second tranche vesting on the fourth anniversary of the grant date and the third tranche vesting on the fifth anniversary thereof), but commence vesting earlier in the event of a complete sell-down by certain of our private equity investors of their shares of our parent's common stock. Our parent does not pay dividends on unexercised options. A summary of our parent's stock option transactions for the year ended December 31, 2014 is presented below.

			Weighted Average Exercise Price per Share		Weighted Average Remaining Contractual Term		Aggregate Intrinsic Value

					(in years)		(in millions)
Outstanding at December 31, 2013	—			—
Granted	253,740		$	19.82
Forfeited or canceled	(34,388	)		19.82

Outstanding at December 31, 2014	219,352		$	19.82		9.25		—

During 2014 we recognized less than $1 million of pre-tax compensation expense related to stock options awards granted. Total compensation cost related to non-vested option awards not yet

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

recognized at December 31, 2014 was approximately $2 million, which is expected to be recognized over a weighted average period of 4 years. There were no options exercised during the year.

Fair Value Assumptions. The fair value of each stock option granted was estimated on the date of grant using a Black-Scholes option-pricing model based on several assumptions utilizing management's best estimate at the time of grant. For the years ended December 31, 2014 the weighted average grant date fair value per share of options granted was $9.03. Listed below is the weighted average of each assumption based on grants in 2014:


Expected Term in Years	7.0
Expected Volatility	40	%
Expected Dividends	—
Risk-Free Interest Rate	2.3	%

We estimated expected volatility based on an analysis of historical stock price volatility of a group of similar publicly traded peer companies which share similar characteristics with our parent over the expected term because our parent's stock has been publicly traded for a very short period of time. We estimate the expected term of our parent's option awards based on the vesting period and average remaining contractual term, referred to as the "simplified method." We use this method to provide a reasonable basis for estimating our expected term based on insufficient historical data prior to 2014.

Cash-Based Long Term Incentive. In 2012 and 2013, we provided long term cash-based incentives to certain of our employees linking annual performance-based cash incentive payments to the financial performance of the company as approved by the Compensation Committee of the board of directors of our parent, EPE Acquisition, LLC, and the employee's individual performance for the year. These cash-based LTI awards have a three-year vesting schedule (50% vesting at the end of the first year, and 25% vesting at the end of each of the succeeding two years). These performance based cash incentive awards were treated as liability awards. Cash-based LTI awards granted during 2013 and 2012 had a fair value of $22 million and $24 million on each respective grant date that will be amortized primarily on an accelerated basis over a three-year vesting period. For the years ended December 31, 2014 and 2013 and the period from March 23 (inception) to December 31, 2012, we recorded approximately $8 million, $16 million and $8 million, respectively, in expense related to these awards. As of December 31, 2014, we had unrecognized compensation expense of $3 million related to these awards which we will recognize in 2015.

Class A "Matching" Grants. In conjunction with the Acquisition, certain of our employees purchased Class A units. In connection with their purchase of these units, these employees were awarded compensatory awards for accounting purposes including (i) "matching" Class A unit grants with a fair value of $12 million equal to 50% of the Class A units purchased subject to repurchase by the Company in the event of certain termination scenarios and (ii) a "guaranteed cash bonus" with a fair value of $12 million which was treated as a liability award and was paid in March 2013 equivalent to the amount of the "matching" Class A unit grant. In connection with our parent's Corporate Reorganization in August 2013, each "matching" unit was converted into common stock. For the "guaranteed cash bonus", we recognized the fair value as compensation cost ratably over the period from the date of grant (May 24, 2012) through the cash payout date in March 2013. For the "matching" Class A unit grant, we recognize the fair value as compensation cost ratably over the four year period from the date of grant through the period over which the requisite service is provided and

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

the time period at which certain transferability restrictions are removed. For the years ended December 31, 2014 and 2013 and the period from March 23 (inception) to December 31, 2012, we recognized approximately $2 million, $6 million and $11 million, respectively, as compensation expense related to both of these awards. As of December 31, 2014, we had unrecognized compensation expense of $4 million related to the "matching" Class A unit grants, of which we will recognize $3 million in 2015 and the remainder in 2016.

Management Incentive Units (MIPs). In addition to the Class A "matching" awards described above, certain employees were awarded MIPs at the time of the Acquisition. These MIPs are intended to constitute profits interests. Each award of MIPs represents a share in any future appreciation of the Company after the date of grant, subject to certain limitations, and once certain shareholder returns have been achieved. The MIPs vest ratably over 5 years subject to certain forfeiture provisions based on continued employment with the Company, although 25% of any vested awards are forfeitable in the event of certain termination events. The MIPs become payable based on the achievement of certain predetermined performance measures (e.g. certain liquidity events in which our private equity investors receive a return of at least one times their invested capital plus a stated return). The MIPs were issued at no cost to the employees and have value only to the extent the value of the Company increases. For accounting purposes, these awards were treated as compensatory equity awards. On May 24, 2012, the grant date fair value of this award was determined using a non-controlling, non-marketable option pricing model which valued these MIPs assuming a 0.77% risk free rate, a 5 year time to expiration, and a 73% volatility rate. Based on these factors, we determined a grant date fair value of $74 million. For the years ended December 31, 2014 and 2013 and the period from March 23 (inception) to December 31, 2012, we recognized approximately $6 million, $19 million and $15 million, respectively, of compensation expense related to these awards. As of December 31, 2014, we had unrecognized compensation expense of $9 million. Of this amount, we will recognize $6 million in 2015 and the remainder on an accelerated basis for each tranche of the award, over the remainder of the five year requisite service period. The remaining $16 million of compensation will be recognized upon a specified capital transaction when the right to such amounts become nonforfeitable.

Other. On September 18, 2013, EP Energy Corporation, our ultimate parent, issued an additional 70,000 shares of Class B common stock to EPE Employee Holdings II, LLC (EPE Holdings II). EPE Holdings II was formed to hold such shares and serve as an entity through which current and future employee incentive awards will be granted. Holders of the awards will not hold actual Class B common stock or equity in EPE Holdings II, but rather will have a right to receive proceeds paid to EPE Holdings II in respect of such shares which is conditional upon certain events (e.g. certain liquidity events in which our private equity investors receive a return of at least one times their invested capital plus a stated return) that are not yet probable of occurring. As a result, no compensation expense was recognized upon the issuance of the Class B shares to EPE Holdings II, and none will occur until those events that give rise to a payout on such shares becomes probable of occurring. At that time, the full value of the awards issued to EPE Holdings II will be recognized based on actual amounts paid on the Class B common stock.

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

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

2014 and 2013 and the period from March 23 (inception) to December 31, 2012, we had contributed $11 million, $12 million and $7 million, respectively, of matching and non-elective employer contributions.

9. Investments in Unconsolidated Affiliate

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

Below is summarized financial information of the operating results of Four Star.

	Successor				Predecessor

	Successor				Predecessor
	Year ended December 31, 2013		March 23 (inception) to December 31, 2012		January 1 to May 24, 2012


			(in millions)
Operating revenues	$	142	$	105	$	75
Operating expenses		94		87		58
Net income		30		11		11

In addition to recording our share of Four Star operating results, we amortized the excess of our investment in Four Star prior to its sale over the underlying equity in its net assets using the unit-of-production method over the life of our estimate of Four Star's oil and natural gas reserves. Amortization of our investment for the year ended December 31, 2013 and the period of March 23 (inception) to December 31, 2012, was $8 million and $7 million, respectively. Amortization of our investment for the predecessor period from January 1 to May 24, 2012 was $12 million. Our financial results related to our equity investment in Four Star were included as other income (expense) on our consolidated income statements.

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

10. Related Party Transactions

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

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10. Related Party Transactions (Continued)

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

Management Fee Agreement. In January 2014, we paid a quarterly management fee of $6.25 million to our private equity investors (affiliates of Apollo Management LLC (Apollo), Riverstone Holdings LLC, Access Industries and Korea National Oil Corporation, collectively the Sponsors). We recorded this fee in general administrative expense. The amended and restated Management Fee Agreement, including the obligation to pay the quarterly management fee, terminated automatically in accordance with its terms upon the closing of our parent's initial public offering.

Affiliate Supply Agreement. For the year ended December 31, 2014, we have recorded approximately $112 million in capital expenditures for amounts provided under two supply agreements to provide certain fracturing materials for our Eagle Ford drilling operations.

Contribution from Parent. Subsequent to our parent's initial public offering, they contributed $186 million in cash to us.

Distributions. In 2014, we made a non-cash distribution to our parent of approximately $20 million. In 2013, we made a leveraged distribution of approximately $200 million to our member.

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

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

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

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EP ENERGY LLC

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)

10. Related Party Transactions (Continued)

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

•: Pension and Retirement Benefits. El Paso maintained a primary pension plan, the El Paso Corporation Pension Plan, a defined benefit plan covering substantially all of our employees prior to the Acquisition and providing benefits under a cash balance formula. El Paso also maintained a defined contribution plan covering all of our employees prior to the Acquisition. El Paso matched 75% of participant basic contributions up to 6 percent of eligible compensation and made additional discretionary matching contributions. El Paso was responsible for benefits accrued under these plans and allocated related costs.
•: Other Post-Retirement Benefits. El Paso provided limited post-retirement life insurance benefits for current and retired employees prior to the Acquisition. El Paso was responsible for benefits accrued under its plan and allocated the related costs to its affiliates.

•: Marketing. Prior to the completion of the Acquisition, the predecessor sold natural gas primarily to El Paso Marketing at spot market prices. The predecessor was also a party to a hedging contract with El Paso Marketing. Realized gains and losses on these hedges were included in operating revenues.
•: Transportation and Related Services. Prior to the completion of the Acquisition, the predecessor contracted for services with El Paso's regulated interstate pipelines that provided transportation and related services for natural gas production.

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

	January 1 to May 24, 2012

Operating revenues	$	143
Operating expenses		44
Reimbursements of operating expenses		—

•: 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 3 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.

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Supplemental Selected Quarterly Financial Information (Unaudited)

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

2014

Operating revenues
Physical sales	511		566		572	450
Financial derivatives	(135	)	(290	)	381	1,029
Operating income (loss)	24		(100	)	573	1,080
Income tax expense	—		—		—	1,121
(Loss) income from continuing operations	(53	)	(180	)	497	(123	)
Net (loss) income	(36	)	(191	)	495	(120	)

2013

Operating revenues
Physical sales	345		390	456		437
Financial derivatives	(131	)	166	(142	)	55
Operating (loss) income	(50	)	272	—		162
(Loss) income from continuing operations	(133	)	197	(108	)	86
Net (loss) income	(106	)	209	348		98

Below are additional significant items affecting comparability of amounts reported in the respective periods of 2014 and 2013:

December 31, 2014. We recorded deferred income tax expense of $1,121 million as a result of recording net deferred tax liabilities for initial temporary differences upon the change in tax status.

September 30, 2013. We recorded a $455 million gain on sale of assets from discontinued operations.

Supplemental Oil and Natural Gas Operations (Unaudited)

We are engaged in the exploration for, and the acquisition, development and production of oil, natural gas and NGLs, in the United States (U.S.). We also had operations in Brazil that were sold in 2014 and Egypt that were sold in 2012.

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

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

	2014		2013

Oil and natural gas properties	$	10,241	$	8,112
Less accumulated depreciation, depletion and amortization		1,560		744

Net capitalized costs	$	8,681	$	7,368

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Total Costs Incurred. Costs incurred in oil and natural gas producing activities, whether capitalized or expensed, were as follows for the successor periods for the years ended December 31, 2014 and 2013, the period from March 23, 2012 (inception) to December 31, 2012 and the predecessor period from January 1, 2012 to May 24, 2012 (in millions):

	U.S.

*Successor*
2014 Consolidated:
Property acquisition costs
Proved properties	$	117
Unproved properties		62
Exploration costs (capitalized and expensed)		57
Development costs		1,953

Costs expended		2,189
Asset retirement obligation costs		10

Total costs incurred	$	2,199



2013 Consolidated:
Property acquisition costs
Proved properties	$	2
Unproved properties		20
Exploration costs (capitalized and expensed)		95
Development costs		1,783

Costs expended		1,900
Asset retirement obligation costs		6

Total costs incurred	$	1,906



Consolidated from March 23, 2012 (inception) to December 31, 2012:
Property acquisition costs
Proved properties	$	—
Unproved properties		19
Exploration costs (capitalized and expensed)		107
Development costs		792

Costs expended		918
Asset retirement obligation costs		3

Total costs incurred	$	921



Unconsolidated Affiliate from March 23, 2012 (inception) to December 31, 2012:
Development costs expended(1)	$	2

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	U.S.		Egypt(2)		Worldwide

*Predecessor*
Consolidated from January 1, 2012 to May 24, 2012:
Property acquisition costs
Proved properties	$	—	$	—	$	—
Unproved properties		31		—		31
Exploration costs		79		2		81
Development costs		503		—		503

Costs expended		613		2		615
Asset retirement obligation costs		21		—		21

Total costs incurred	$	634	$	2	$	636



Unconsolidated Affiliate from January 1, 2012 to May 24, 2012:
Development costs expended(1)	$	3	$	—	$	3

(1): Amounts represent our approximate 49% equity interest in the underlying costs incurred by Four Star. We sold our interest in Four Star in September 2013.
(2): In June of 2012 we sold our Egyptian oil and gas properties.

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 $38 million, $37 million and $25 million for the years ended December 31, 2014 and 2013 and for the period from March 23, 2012 (inception) to December 31, 2012, and capitalized interest of $21 million, $19 million and $12 million for the same periods.

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

Oil and Natural Gas Reserves. Net quantities of proved developed and undeveloped reserves of natural gas, oil and NGLs and changes in these reserves at December 31, 2014 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 2014 proved reserves were consistent with estimates of proved reserves filed with other federal agencies in 2014 except for differences of less than five percent resulting from actual production, acquisitions, property sales, necessary reserve revisions and additions to reflect actual experience.

Ryder Scott Company, L.P. (Ryder Scott), conducted an audit of the estimates of the proved reserves that we prepared as of December 31, 2014. In connection with its audit, Ryder Scott reviewed 94% (by volume) of our total proved reserves on a barrel of oil equivalent basis, representing 98% of the total discounted future net cash flows of these proved reserves. For the audited properties, 91% of our total proved undeveloped (PUD) reserves were evaluated. Ryder Scott concluded the overall procedures and methodologies that we utilized in preparing our estimates of proved reserves as of December 31, 2014 complied with current SEC regulations and the overall proved reserves for the reviewed properties as estimated by us are, in aggregate, reasonable within the established audit

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tolerance guidelines of 10% as set forth in the Society of Petroleum Engineers auditing standards. Ryder Scott's report is included as an exhibit to this Annual Report on Form 10-K.

	Year Ended December 31, 2014(1)

	U.S.
	Natural Gas (in Bcf)			Oil (in MBbls)			NGLs (in MBbls)			Equivalent Volumes (in MMBoe)
Proved developed and undeveloped reserves
Beginning of year		1,070			293,201			75,605			547.2
Revisions due to prices		206			(1,720	)		(538	)		31.9
Revisions other than prices		(32	)		(8,310	)		3,702			(9.8	)
Extensions and discoveries(2)		146			59,242			19,805			103.3
Purchase of reserves		9			4,079			1,530			7.1
Sales of reserves in place		(83	)		(5,615	)		(1,738	)		(21.2	)
Production		(73	)		(20,064	)		(4,140	)		(36.3	)

End of year		1,243			320,813			94,226			622.2



Proved developed reserves:
Beginning of year		484			83,811			17,647			182.1
End of year		464			128,396			32,474			238.1
Proved undeveloped reserves:
Beginning of year		586			209,391			57,958			365.1
End of year		779			192,417			61,752			384.1

(1): Proved reserves were evaluated using first day 12-month average prices of $94.99 per barrel of oil (WTI) and $4.34 per MMBtu of natural gas (Henry Hub).
(2): Of the 103 MMBoe of extensions and discoveries, 2 MMBoe were from assets sold, 68 MMBoe are in the Eagle Ford Shale, 19 MMBoe are in the Wolfcamp Shale, 14 MMBoe are in the Altamont area and 2 MMBoe are in the Haynesville Shale. Of the 103 MMBoe of extensions and discoveries, 79 MMBoe were liquids representing 77% of EP Energy's total extensions and discoveries.

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	Year Ended December 31, 2013(1)

	U.S.												Brazil									Total
	Natural Gas (in Bcf)			Oil (in MBbls)			NGLs (in MBbls)			Equivalent Volumes (in MMBoe)			Natural Gas (in Bcf)			Oil (in MBbls)			Equivalent Volumes (in MMBoe)			Equivalent Volumes (in MMBoe)
Consolidated
Proved developed and undeveloped reserves
Beginning of year		1,727			256,242			34,331			578.5			68			2,152			13.4			591.9
Revisions due to prices		83			376			166			14.4			—			5			—			14.4
Revisions other than prices		129			(36,322	)		20,459			5.6			—			(17	)		—			5.6
Extensions and discoveries(2)		231			88,174			28,583			155.3			—			—			—			155.3
Sales of reserves in place		(965	)		(1,642	)		(5,108	)		(167.6	)		—			—			—			(167.6	)
Production		(135	)		(13,627	)		(2,826	)		(39.0	)		(9	)		(305	)		(1.8	)		(40.8	)

End of year(3)		1,070			293,201			75,605			547.2			59			1,835			11.6			558.8



Proved developed reserves:
Beginning of year		1,189			55,924			9,080			263.2			68			2,152			13.3			276.5
End of year		484			83,811			17,647			182.1			59			1,835			11.6			193.7
Proved undeveloped reserves:
Beginning of year		538			200,318			25,251			315.2			—			—			—			315.2
End of year		586			209,391			57,958			365.1			—			—			—			365.1
Unconsolidated Affiliate—Four Star
Proved developed and undeveloped reserves
Beginning of year		150			2,148			5,967			33.1			—			—			—			33.1
Revisions due to prices		5			66			191			1.1			—			—			—			1.1
Revisions other than prices		11			128			348			2.3			—			—			—			2.3
Sales of reserves in place		(156	)		(2,145	)		(6,179	)		(34.3	)		—			—			—			(34.3	)
Production		(10	)		(197	)		(327	)		(2.2	)		—			—			—			(2.2	)

End of year		—			—			—			—			—			—			—			—



Proved developed reserves:
Beginning of year		140			2,111			5,289			30.9			—			—			—			30.9
End of year		—			—			—			—			—			—			—			—
Proved undeveloped reserves:
Beginning of year		10			37			678			2.4			—			—			—			2.4
End of year		—			—			—			—			—			—			—			—
Total Combined
Proved developed reserves:
Beginning of year		1,329			58,035			14,369			294.1			68			2,152			13.3			307.4
End of year		484			83,811			17,647			182.1			59			1,835			11.6			193.7
Proved undeveloped reserves:
Beginning of year		548			200,355			25,929			317.6			—			—			—			317.6
End of year		586			209,391			57,958			365.1			—			—			—			365.1

(1): Proved reserves were evaluated using first day 12-month average prices of $96.94 per barrel of oil (WTI) and $3.67 per MMBtu of natural gas (Henry Hub).
(2): Of the 155 MMBoe of combined extensions and discoveries, including assets sold, 5 MMBoe are in the Altamont area, 91 MMBoe are in the Eagle Ford Shale and 51 MMBoe are in the Wolfcamp Shale. There were no extensions or discoveries in Brazil. Of the 155 MMBoe of extensions and discoveries, 117 MMBoe were liquids representing 75% of EP Energy's total extensions and discoveries.
(3): Equivalent volumes include an adjustment of .3 MMBoe to reflect an adjustment made to the prices used to calculate proved reserves.

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	Year Ended December 31, 2012(1)

	U.S.												Brazil									Total
	Natural Gas (in Bcf)			Oil (in MBbls)			NGLs (in MBbls)			Equivalent Volumes (in MMBoe)			Natural Gas (in Bcf)			Oil (in MBbls)			Equivalent Volumes (in MMBoe)			Equivalent Volumes (in MMBoe)
Consolidated
Proved developed and undeveloped reserves
Beginning of year		2,566			177,801			14,245			619.7			81			2,269			15.8			635.5
Revisions due to prices		(718	)		(604	)		(371	)		(120.6	)		—			1			—			(120.6	)
Revisions other than prices		55			(18,451	)		10,267			1.1			(3	)		288			(0.3	)		0.8
Extensions and discoveries(2)		119			109,125			13,450			142.4			—			—			—			142.4
Purchases of reserves in place		—			3			2			—			—			—			—			—
Sales of reserves in place		(72	)		(2,501	)		(1,358	)		(15.9	)		—			—			—			(15.9	)
Production		(223	)		(9,131	)		(1,904	)		(48.2	)		(10	)		(406	)		(2.1	)		(50.3	)

End of year		1,727			256,242			34,331			578.5			68			2,152			13.4			591.9



Proved developed reserves:
Beginning of year		1,488			46,797			5,168			300.0			81			2,269			15.8			315.8
End of year		1,189			55,924			9,080			263.2			68			2,152			13.3			276.5
Proved undeveloped reserves:
Beginning of year		1,078			131,004			9,077			319.7			—			—			—			319.7
End of year		538			200,318			25,251			315.2			—			—			—			315.2
Unconsolidated Affiliate—Four Star
Proved developed and undeveloped reserves
Beginning of year		135			1,569			4,908			29.0			—			—			—			29.0
Revisions due to prices		(13	)		(37	)		(310	)		(2.5	)		—			—			—			(2.5	)
Revisions other than prices		19			803			1,710			5.8			—			—			—			5.8
Extensions and discoveries(2)		25			95			137			4.3			—			—			—			4.3
Production		(16	)		(282	)		(478	)		(3.5	)		—			—			—			(3.5	)

End of year		150			2,148			5,967			33.1			—			—			—			33.1



Proved developed reserves:
Beginning of year		116			1,519			4,066			24.9			—			—			—			24.9
End of year		140			2,111			5,289			30.9			—			—			—			30.9
Proved undeveloped reserves:
Beginning of year		19			49			842			4.0			—			—			—			4.0
End of year		10			37			678			2.4			—			—			—			2.4
Total Combined
Proved developed reserves:
Beginning of year		1,604			48,316			9,234			324.9			81			2,269			15.8			340.7
End of year		1,329			58,035			14,369			294.1			68			2,152			13.3			307.4
Proved undeveloped reserves:
Beginning of year		1,097			131,053			9,919			323.7			—			—			—			323.7
End of year		548			200,355			25,929			317.6			—			—			—			317.6

(1): Proved reserves were evaluated using first day 12-month average prices of $94.61 per barrel of oil (WTI) and $2.76 per MMBtu of natural gas (Henry Hub).
(2): Of the 146.7 MMBoe of combined extensions and discoveries, 6.2 MMBoe are in the Altamont area, 110.7 MMBoe are in the Eagle Ford Shale and 23.5 MMBoe are in the Wolfcamp Shale. There were no extensions or discoveries in Brazil. Of the 146.7 MMBoe of extensions and discoveries, 122.8 MMBoe were liquids representing 84% of EP Energy's total extensions and discoveries.

In accordance with SEC Regulation S-X, Rule 4-10 as amended, we use the 12-month average price calculated as the unweighted arithmetic average of the spot price on the first day of each month preceding the 12-month period prior to the end of the reporting period. The first day 12-month average price used to estimate our proved reserves at December 31, 2014 was $94.99 per barrel of oil (WTI) and $4.34 per MMBtu for natural gas (Henry Hub).

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

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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; a revision of that estimate may be necessary.

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, 2014, 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, 2014.

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Results of Operations. Results of operations for oil and natural gas producing activities for the successor periods for the years ended December 31, 2014 and 2013 and from March 23, 2012 (inception) to December 31, 2012 and the predecessor period from January 1, 2012 to May 24, 2012 (in millions):

	U.S.

*Successor*
2014 Consolidated:
Net Revenues(1)—Sales to external customers	$	2,099

Costs of products and services		(147	)
Production costs(2)		(314	)
Depreciation, depletion and amortization(3)		(863	)
Exploration and other expense		(25	)

Results of operations from producing activities	$	750



2013 Consolidated:
Net Revenues(1)—Sales to external customers	$	1,628

Costs of products and services		(150	)
Production costs(2)		(231	)
Depreciation, depletion and amortization(3)		(573	)
Exploration expense		(41	)

Results of operations from producing activities	$	633



2013 Unconsolidated Affiliate—Four Star(4):
Net Revenues—Sales to external customers	$	69

Costs of products and services		(6	)
Production costs(2)		(19	)
Depreciation, depletion and amortization(5)		(18	)

		26
Income tax expense		(8	)

Results of operations from producing activities	$	18



Consolidated from March 23, 2012 (inception) to December 31, 2012:
Net Revenues(1)—Sales to external customers	$	743

Costs of products and services		(82	)
Production costs(2)		(100	)
Depreciation, depletion and amortization(3)		(183	)
Exploration expense		(40	)

Results of operations from producing activities	$	338



Unconsolidated Affiliate—Four Star from March 23, 2012 (inception) to December 31, 2012(4):
Net Revenues—Sales to external customers	$	52

Costs of products and services		(3	)
Production costs(2)		(24	)
Depreciation, depletion and amortization(5)		(16	)

		9
Income tax expense		(3	)

Results of operations from producing activities	$	6

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	U.S.			Egypt(5)			Worldwide

*Predecessor*
Consolidated from January 1, 2012 to May 24, 2012:
Net Revenues(1)
Sales to external customers	$	424		$	—		$	424
Affiliated sales		143			—			143

Total		567			—			567
Costs of products and services		(49	)		—			(49	)
Production costs(2)		(115	)		—			(115	)
Impairments and ceiling test charges		—			(60	)		(60	)
Depreciation, depletion and amortization(3)		(301	)		—			(301	)

		102			(60	)		42
Income tax expense		(37	)		—			(37	)

Results of operations from producing activities	$	65		$	(60	)	$	5



Unconsolidated Affiliate—Four Star from January 1, 2012 to May 24, 2012(4):
Net Revenues—Sales to external customers	$	35		$	—		$	35
Costs of products and services		(1	)		—			(1	)
Production costs(2)		(15	)		—			(15	)
Depreciation, depletion and amortization(6)		(11	)		—			(11	)

		8			—			8
Income tax expense		(3	)		—			(3	)

Results of operations from producing activities	$	5		$	—		$	5

(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 $3 million, $4 million and $9 million for the years ended December 31, 2014 and 2013 and the period from March 23, 2012 to December 31, 2012, $5 million for the predecessor period from January 1, 2012 to May 24, respectively.
(4): Results for 2013 are reported as of September 10, 2013 (the date the investment was sold). Results do not include amortization of $8 million for the year ended December 31, 2013, $7 million for the period from March 23, 2012 to December 31, 2012 and $12 million for the predecessor period from January 1, 2012 to May 24, 2012 related to cost in excess of our equity interest in the underlying net assets of Four Star. In addition, in 2013 we recorded an impairment of $20 million, not included in the table above.
(5): In June of 2012, we sold our Egyptian oil and gas properties.
(6): Includes accretion expense on asset retirement obligations of $1 million for the period from March 23, 2012 to December 31, 2012 and $1 million for the predecessor period from January 1, 2012 to May 24, 2012, respectively.

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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.

2014 Consolidated:
Future cash inflows(1)	$	35,028
Future production costs		(9,628	)
Future development costs		(6,488	)
Future income tax expenses		(5,565	)

Future net cash flows		13,347
10% annual discount for estimated timing of cash flows		(6,449	)

Standardized measure of discounted future net cash flows	$	6,898

	U.S.			Brazil			Worldwide

2013 Consolidated:
Future cash inflows(1)(2)	$	32,577		$	615		$	33,192
Future production costs(2)		(9,083	)		(365	)		(9,448	)
Future development costs		(6,789	)		(71	)		(6,860	)
Future income tax expenses(2)		—			(18	)		(18	)

Future net cash flows		16,705			161			16,866
10% annual discount for estimated timing of cash flows		(8,335	)		(32	)		(8,367	)

Standardized measure of discounted future net cash flows(2)	$	8,371		$	129		$	8,499



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(3)		—			(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(4):
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

(1): The company had no commodity-based derivative contracts designated as accounting hedges at December 31, 2014, 2013 and 2012. Amounts also exclude the impact on future net cash flows of derivatives not designated as accounting hedges.
(2): For 2013, U.S. future cash inflows and U.S. production costs include an adjustment of $(1,142) million and $104 million, respectively, to reflect an adjustment made to the prices used to calculate the standardized measure of discounted future net cash flows at December 31, 2013. Due to this change, future income taxes and 10% annual discount for estimated timing of cash flows changed

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accordingly, for a total net adjustment to the originally reported standardized measure of discounted future net cash flows of $(561) million.

(3): For the years ended December 31, 2013 and 2012, there were no U.S. future income taxes because the company is not subject to federal income taxes.
(4): Amounts represent our approximate 49% equity interest in Four Star which was sold in September 2013.

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)

	2014			2013			2012
Consolidated:
Sales and transfers of oil and natural gas produced net of production costs	$	(1,785	)	$	(1,493	)	$	(1,433	)
Net changes in prices and production costs		(762	)		(745	)		(871	)
Extensions, discoveries and improved recovery, less related costs		1,728			2,626			2,539
Changes in estimated future development costs		63			(10	)		978
Previously estimated development costs incurred during the period		1,192			679			587
Revision of previous quantity estimates		441			447			(1,863	)
Accretion of discount		833			796			731
Net change in income taxes		(2,477	)		(3	)		1,683
Purchase of reserves in place		137			—			—
Sales of reserves in place		(229	)		(886	)		(296	)
Change in production rates, timing and other		(613	)		27			(210	)

Net change	$	(1,472	)	$	1,438		$	1,845



Unconsolidated Affiliate—Four Star(2):
Sales and transfers of oil and natural gas produced net of production costs				$	(41	)	$	(48	)
Net changes in prices and production costs					6			(112	)
Extensions, discoveries and improved recovery, less related costs					—			25
Changes in estimated future development costs					25			5
Revision of previous quantity estimates					10			19
Accretion of discount					18			22
Net change in income taxes					68			39
Sales of reserves in place					(260	)		—
Change in production rates, timing and other					38			(8	)

Net change				$	(136	)	$	(58	)



Representative NYMEX prices:(3)
Oil (Bbl)	$	94.99		$	96.94		$	94.61
Natural gas (MMBtu)	$	4.34		$	3.67		$	2.76
Aggregate International prices:(3)
Oil (Bbl)				$	108.02		$	111.21
Natural gas (MMBtu)				$	6.31		$	6.55

(1): This disclosure reflects changes in the standardized measure calculation excluding the effects of hedging activities.
(2): We sold our interest in Four Star in 2013.
(3): First day 12-month historical average U.S. price and an aggregate international price before price differentials and deducts. Price differentials and deducts were applied when the estimated future cash flows from estimated production from proved reserves were calculated.

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EP Energy LLC
Everest Acquisition Finance Inc.

EP Energy 424B3Prospectus supplement