Table of Contents

 

 

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

 

Form 10-K

 

(Mark One)

 

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

 

For the fiscal year ended December 31, 2013

 

OR

 

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

 

For the transition period from                  to                  .

 

Commission File Number 333-183815

 

 

EP Energy Corporation

(Exact Name of Registrant as Specified in Its Charter)

 

Delaware		46-3472728
(State or Other Jurisdiction of		(I.R.S. Employer
Incorporation or Organization)		Identification No.)

 

 

Telephone Number: (713) 997-1200

Internet Website: www.epenergy.com

 

Securities registered pursuant to Section 12(b) of the Act:

 

Title of Each Class		Name of Each Exchange on which Registered
Class A Common Stock, par value $0.01 per share		New York Stock Exchange

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

Large accelerated filer   o

Accelerated filer   o

 

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

 

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

 

As of June 30, 2013, the last business day of the registrant’s most recently completed second fiscal quarter, the registrant’s equity was not listed on any domestic exchange or over-the-counter market. The registrant’s Class A Common Stock began trading on the NYSE on January 17, 2014.

 

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

 

Class A Common Stock, par value $0.01 per share. Shares outstanding as of February 20, 2014: 243,877,539

Class B Common Stock, par value $0.01 per share. Shares outstanding as of February 20, 2014: 872,586

 

 

Documents Incorporated by Reference:  None

 

 

Table of Contents

 

EP ENERGY CORPORATION

 

TABLE OF CONTENTS

 

Caption		Page
PART I
Item 1. Business		1
Item 1A. Risk Factors		17
Item 1B. Unresolved Staff Comments		36
Item 2. Properties		36
Item 3. Legal Proceedings		36
Item 4. Mine Safety Disclosures		36
PART II
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities		37
Item 6. Selected Financial Data		37
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations		39
Item 7A. Quantitative and Qualitative Disclosures About Market Risk		60
Item 8. Financial Statements and Supplementary Data		62
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure		104
Item 9A. Controls and Procedures		104
Item 9B. Other Information		104
PART III
Item 10. Directors, Executive Officers and Corporate Governance		105
Item 11. Executive Compensation		110
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters		126
Item 13. Certain Relationships and Related Transactions, and Director Independence		129
Item 14. Principal Accountant Fees and Services		137
PART IV
Item 15. Exhibits and Financial Statement Schedules		138
Signatures		139

 

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

 

/d	=	per day
Bbl	=	Barrel
Bcf	=	billion cubic feet
Bcfe	=	billion cubic feet of natural gas equivalents
Boe	=	barrel of oil equivalent
CBM	=	coal bed methane
Gal	=	gallons
LNG	=	liquified natural gas
MBoe	=	thousand barrels of oil equivalent
MBbls	=	thousand barrels
Mcf	=	thousand cubic feet
Mcfe	=	thousand cubic feet of natural gas equivalents
MMGal	=	million gallons
MMBtu	=	million British thermal units
MMBoe	=	million barrels of oil equivalent
MMBbls	=	million barrels
MMcf	=	million cubic feet
MMcfe	=	million cubic feet of natural gas equivalents
NGLs	=	natural gas liquids
TBtu	=	trillion British thermal units

 

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

 

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

 

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

 

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CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

 

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

 

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

·                   our ability to meet production volume targets;

·                   the uncertainty of estimating proved reserves and unproved resources ;

·                   the future level of service and capital costs;

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

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

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

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

·                   actions by credit rating agencies;

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

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

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

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

·                   political and currency risks associated with our international operations;

·                   competition; and

·                   the other factors described under Item 1A, “Risk Factors,” on pages 17 through 35 of this Annual Report on Form 10-K, and any updates to those factors set forth in our subsequent Quarterly Reports on Form 10-Q or Current Report on Form 8-K.

 

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

 

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PART I

 

ITEM 1.                         BUSINESS

 

Overview

 

EP Energy Corporation (EP Energy) was formed on August 30, 2013, and is an independent exploration and production company engaged in the acquisition and development of unconventional onshore oil and natural gas properties in the United States. Prior to August 30, 2013, EP Energy conducted its activities through EPE Acquisition, LLC, and its predecessor entities and their subsidiaries. On May 24, 2012, affiliates of Apollo Global Management LLC (together with its subsidiares, Apollo), Riverstone Holdings LLC (Riverstone), Access Industries (Access) and Korea National Oil Corporation (KNOC) (collectively, the Sponsors) and other co-investors acquired EP Energy Global LLC and its subsidiaries for approximately $7.2 billion in cash as contemplated by the merger agreement among El Paso Corporation (El Paso) and Kinder Morgan, Inc. (KMI).  Hereinafter, the acquisition of EP Energy Global LLC is referred to as the “Acquisition” with EP Energy Corporation referred to as the successor and the acquired entities referred to as the predecessor for financial accounting and reporting purposes.

 

We operate through a large and diverse base of producing assets located predominantly in four core areas: the Eagle Ford Shale (South Texas), the Wolfcamp Shale (Permian Basin in West Texas), the Altamont field in the Uinta Basin in northeastern Utah and the Haynesville Shale (North Louisiana). We also operate in other non-core areas primarily in Texas and Louisiana.  In our core areas, we have identified approximately 5,170 drilling locations (including 968 drilling locations to which we have attributed proved undeveloped reserves as of December 31, 2013), of which approximately 97% are oil wells. At current activity levels, this represents approximately 23 years of drilling inventory. As of December 31, 2013, we had proved reserves of 547.5 MMBoe (54% oil and 67% liquids) and for the three months ended December 31, 2013, we had average net daily production of 87,304 Boe/d (49% oil and 58% liquids).

 

Each of our core 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 440,000 net (613,000 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 continuing production growth of 15% and 55%, respectively, from December 31, 2012 to December 31, 2013.

 

During 2013, we divested non-core domestic natural gas assets and an equity investment for a total consideration of approximately $1.5 billion. We also entered into a Quota Purchase Agreement relating to the sale of our Brazil operations, which is expected to close in 2014.  All periods present our Brazil operations as discontinued operations, and accordingly its operations are excluded from the discussion in this section.  Periods after the Acquisition in May 2012, referred to as successor periods also present domestic natural gas assets sold, including the CBM and South Texas assets and the majority of our Arklatex assets, as discontinued operations, and accordingly those operations are excluded from the discussion in this section.  The predecessor periods present our domestic natural gas assets sold in 2013 and our Gulf of Mexico assets sold in 2012 as divested assets.

 

As a result of these asset sales, we are a higher-growth, 100% onshore U.S., oil-weighted company with a large inventory of high-return, low-risk drilling locations. We intend to continue developing our oil-weighted assets, which offer the best rates of return in our portfolio in the current commodity price environment. In addition, our Haynesville Shale position is 100% held-by-production, which gives us the flexibility to allocate capital to this natural gas-weighted asset in the future.

 

1

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The following table provides a summary of our oil, natural gas and NGLs reserves and production data as of December 31, 2013 for each of our ongoing areas of operation.

 

		Estimated Proved Reserves												Average
												Proved		Net Daily
		Oil (MMBbls)		NGLs (MMBbls)		Natural Gas (Bcf)		Total (MMBoe)		Liquids (%)		Developed (%)		Production (MBoe/d)
Core Areas
Eagle Ford Shale		173.6		54.9		376.6		291.2		78	%	24	%	36.6
Wolfcamp Shale		45.9		19.8		115.0		84.9		77	%	25	%	5.5
Altamont		72.0		—		149.6		96.9		74	%	39	%	11.9
Haynesville Shale		—		—		353.6		59.0		0	%	68	%	27.1
Total Core Areas		291.5		74.7		994.8		532.0		69	%	32	%	81.1
Other (1)		1.9		1.0		75.7		15.5		19	%	81	%	5.0
Total		293.4		75.7		1,070.5		547.5		67	%	33	%	86.1

 

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

 

 

Approximately 165 MMBoe, or 30%, of our total proved reserves are proved developed producing assets, which generated an average production of 86,108 Boe/d in 2013 from approximately 1,405 wells. As of December 31, 2013, we had approximately 293 MMBbls of proved oil reserves, 76 MMBbls of proved NGLs reserves and 1,071 Bcf of proved natural gas reserves in the United States, representing 54%, 13% and 33%, respectively, of our total proved reserves. For the year ended December 31, 2013, 51% of our production and 80% of our revenues (excluding realized and unrealized gains on financial derivatives) were related to oil and NGLs versus 31% and 66% in 2012, respectively, and over that same period and on that same basis, our continuing oil production has grown by approximately 55%. As a result of our development program and our divestitures of natural gas assets in 2013, the oil-weighting of our reserves is 54% as of December 31, 2013 as compared to 42% as of December 31, 2012 without giving effect to the divestitures of certain natural gas assets in 2013. We anticipate that substantially all of our 2014 capital expenditures will be allocated to our core oil programs.

 

We operate over 87% of our producing wells and have operational control over approximately 95% of our core area drilling inventory as of December 31, 2013. This control provides us with flexibility around the amount and timing of capital spending and has allowed us to continually improve our capital and operating efficiencies. We also employ a centralized operational structure to accelerate our internal knowledge transfer around the execution of our drilling and completion programs and to continually enhance our field operations and base production performance. In 2013, we drilled 231 wells with a success rate of 99%, adding approximately 147 MMBoe of proved reserves (79% of which were liquids), excluding divested assets. Our reserve replacement cost as of December 31, 2013 was $12.62 per Boe. See Part II, Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Reserve Replacement Ratio/Reserve Replacement Costs” for further discussion of these metrics.

 

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Core Areas

 

Eagle Ford Shale .  The Eagle Ford Shale, located in South Texas, is one of the premier unconventional oil plays in the United States. We were an early entrant into this play in late 2008, and since that time have acquired a leasehold position in the core of the oil window, primarily in La Salle and Atascosa counties. The Eagle Ford formation in La Salle county has up to 125 feet of net thickness (165 feet gross). Due to its high carbonate content, the formation is also very brittle, and exhibits high productivity when fractured, with initial 30-day oil equivalent production rates up to 1,100 Boe/d, comprised of 893 Bbl/d of oil, 97 Bbl/d of NGLs and 662 Mcf/d of natural gas. We currently have 91,675 net (104,958 gross) acres in the Eagle Ford, in which we have identified 946 drilling locations.

 

During 2013, we invested $1,191 million in capital expenditures in our Eagle Ford Shale and operated an average of 5.5 drilling rigs.  As of December 31, 2013, we had 271 net producing wells (270 net operated wells) and are currently running six rigs. For the year ended December 31, 2013, our average net daily production was 36,637 Boe/d, representing growth of 82% over the same period in 2012.  For the year ended December 31, 2013 our average cost per gross well was $7.4 million ($6.8 million per net well), representing a 12% decline from our average cost per gross well (17% per net well) from 2012.

 

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. 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. We are currently in full development of the Wolfcamp B and C. Our initial 30-day oil equivalent production rates are up to 700 Boe/d, comprised of 516 Bbl/d of oil, 88 Bbl/d of NGLs and 577 Mcf/d of natural gas. As of December 31, 2013, we have 138,173 net (138,512 gross) acres in the Wolfcamp, in which we have identified approximately 2,900 drilling locations in the Wolfcamp A, the Wolfcamp B and the Wolfcamp C. In early 2013, we piloted a five-well development program in the Wolfcamp B and Wolfcamp C using alternating laterals. Initial results of the pilot program suggest that the combined development of the two zones may yield greater oil recovery from each interval. We plan to continue with this development approach in 2014. On the first 19 wells developed in 2013 and early 2014 utilizing this approach, our initial 30-day oil equivalent production rates have averaged 545 Boe/d, comprised of 353 Bbl/d of oil, 92 Bbl/d of NGLs and 602 Mcf/d of natural gas.

 

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 2013, we invested $505 million in capital expenditures in our Wolfcamp Shale and operated an average of 3.0 drilling rigs. As of December 31, 2013, we had 99 net operated producing wells and are currently running three rigs.  For the year ended December 31, 2013, our average net daily production was 5,478 Boe/d, representing growth of 173% over 2012.  For the year ended December 31, 2013 our average cost per gross well was $5.6 million ($5.6 million per net well), representing a 27% decline from our average cost per gross well (27% per net well) from 2012.

 

Altamont .  The Altamont field is located in the Uinta Basin in northeastern Utah. 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 173,110 net (313,686 gross) acres in Duchesne and Uinta Counties. The Altamont Field Complex has gross thicknesses over 4,300 feet across multiple sandstone and carbonate intervals and we believe the Wasatch and Green River formations are ideal targets for low-risk, infill, vertical drilling and modern fracture stimulation techniques. The commingled production from over 1,500 feet of net stimulated rock results in initial 30-day oil production rates of up to 950 Boe/d, comprised of approximately 799 Bbl/d of oil and 907 MMcf/d of natural gas. Our current activity is mainly focused on the development of our vertical inventory on 160-acre spacing. As of December 31, 2013, we have identified an inventory of 1,126 drilling locations (776 vertical and 350 horizontal). The industry is currently piloting 80-acre vertical downspacing programs in the Wasatch and Green River formations and horizontal development programs in the multiple shale, carbonate and tight sand intervals. Due to the largely held-by-production nature of our acreage position, if these programs are successful, it will result in additional vertical and horizontal drilling opportunities that could be added to our inventory of drilling locations.

 

During 2013, we invested $207 million in capital expenditures in the Altamont Field, operated an average of 2.5 drilling rigs, and drilled 27 gross wells. As of December 31, 2013, we had 325 net producing wells (318 net operated wells) and are currently running four rigs, with the addition of a fourth rig in late January 2014.  For the year ended December 31, 2013, our average net daily production was 11,855 Boe/d, representing growth of 12% over 2012.  For the year ended December 31, 2013 our average cost per gross well was $5.4 million ($4.5 million per net well), representing a 9% decline from our average cost per gross well (23% per net well) from 2012.

 

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Haynesville Shale .  In addition to our core 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 36,865 net (55,817 gross) acres in this area. As of December 31, 2013, we have identified 197 drilling locations.

 

During 2013, we invested $1 million in capital expenditures in our Haynesville Shale program. For the year ended December 31, 2013, our average net daily production was 163 MMcfe/d. As of December 31, 2013, we had 194 producing wells, which provided cash flow to fund the development of our core oil programs. Although we had a very efficient drilling program in the Haynesville Shale, we suspended the program in early 2012 due to low natural gas prices.  At this time, we do not plan to drill any new wells in the Haynesville Shale in 2014. Although we believe our wells generate attractive returns in the current natural gas price environment, we have chosen to allocate capital to our higher-return, oil-weighted areas. Our acreage in the Haynesville Shale is 100% held-by-production, giving us the flexibility to allocate capital in the future to this natural gas-weighted asset.

 

The following table provides a summary of acreage and inventory data for our core areas, as of December 31, 2013:

 

		Core Acreage and Inventory Summary as of December 31, 2013
		Acres				Drilling Locations (1)		2013 Drilling Locations (2)		Inventory		Working Interest		Net  Revenue Interest
		Gross		Net		(#)		(#)		(Years) (3)		(%)		(%)
Core Areas
Eagle Ford Shale		104,958		91,675		946		136		7.0		90	%	68	%
Wolfcamp Shale		138,512		138,173		2,900		68		42.6		96	%	72	%
Wolfcamp A						1,001						96	%	72	%
Wolfcamp B						912						96	%	72	%
Wolfcamp C						987						96	%	72	%
Altamont		313,686		173,110		1,126		27		41.7		72	%	60	%
Vertical						776						73	%	61	%
Horizontal						350						71	%	59	%
Haynesville Shale		55,817		36,865		197		—		NA		79	%	63	%
Holly						104						81	%	66	%
Non-Holly						93						76	%	58	%
Total Core Areas		612,973		439,823		5,169		231		22.4		88	%	68	%

 

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(1)                                      Our inventory as of December 31, 2013 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) vertical infill locations and (ii) horizontal drilling locations in the Wasatch and Green River formations.

(2)                                      Represents gross operated wells completed in 2013.

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

 

We use 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.

Other Oil and Natural Gas Properties and Assets

 

We have other domestic producing assets that contribute to our operations.  During 2013, we invested an aggregate of $12 million in capital expenditures in the following areas:

 

South Louisiana Wilcox .  In our South Louisiana Wilcox area we control 47,447 total net (52,161 gross) acres located primarily in Beauregard Parish, Louisiana.  We focus on development of the conventional vertical Wilcox area which produces oil, natural gas and NGLs from a series of completed sands. We are also evaluating horizontal drilling in certain sand intervals.  We have over 1,000 square miles of 3-D seismic data across this play.  The oil and NGLs from South Louisiana Wilcox have access to Louisiana Light Sweet Crude and Gulf Coast NGLs pricing, respectively.  In addition, it does not compete for horizontal drilling and completion services due to vertical drilling and completion design. For the year ended December 31, 2013 we had average daily production of 1.5 MBoe/d and as of that date we had 21 net producing wells.

 

Arklatex Tight Gas.  Our Arklatex Tight Gas area includes wells producing from reservoirs other than the Haynesville Shale in our acreage located in Northern Louisiana. These properties are generally in the same areas as our Haynesville Shale. Our wells in this area produce from reservoirs such as the Travis Peak, Hosston and Cotton Valley, and have relatively stable production with shallow declines rates. In the current gas price environment, we are not currently drilling in this area. We have a significant low-risk inventory in this area that we believe would generate economic returns at higher gas prices. For the year ended December 31, 2013, we had average daily production of 3.4 MBoe/d and as of that date we had 272 net producing wells.

 

Discontinued Operations

 

We also have exploration and development projects in offshore Brazil that are under contract to be sold and treated as discontinued operations in our financial statements.  Our Brazilian operations are in the Camamu, Espirito Santo and Potiguar basins covering approximately 33,000 net acres.  During 2013, we invested $1 million on capital projects in Brazil, and production averaged 5.0 MBoe/d.  As of December 31, 2013, we have 11.6 MMBoe of net proved reserves in Brazil. The sale of Brazil is expected to close in 2014, subject to Brazilian regulatory approval and certain other customary closing conditions.

 

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Oil and Natural Gas Properties

 

Oil and Condensate, Natural Gas and NGLs Reserves and Production

 

Proved Reserves

 

The table below presents information about our estimated net proved reserves as of December 31, 2013, based on our internal reserve report. The reserve data represents only estimates which are often different from the quantities of oil and natural gas that are ultimately recovered. The risks and uncertainties associated with estimating proved oil and natural gas reserves are discussed further in Item 1A, “Risk Factors”. Net proved reserves exclude royalties and interests owned by others and reflect contractual arrangements and royalty obligations in effect at December 31, 2013.

 

		Net Proved Reserves
		Oil (MMBbls)		NGLs (MMBbls)		Natural Gas (Bcf)		Total (MMBoe)		Percent (%)
Reserves by Classification
Proved Developed
Core Areas
Eagle Ford Shale		44.1		12.1		83.8		70.0		13	%
Wolfcamp Shale		11.0		5.3		30.8		21.5		4	%
Altamont		27.9		—		60.9		38.1		7	%
Haynesville Shale		—		—		241.0		40.2		7	%
Total Core Areas		83.0		17.4		416.5		169.8		31	%
Other		1.0		0.3		67.5		12.6		2	%
Total Proved Developed (1)		84.0		17.7		484.0		182.4		33	%
Proved Undeveloped
Core Areas
Eagle Ford Shale		129.5		42.8		292.8		221.2		40	%
Wolfcamp Shale		34.9		14.5		84.2		63.4		12	%
Altamont		44.1		—		88.7		58.8		11	%
Haynesville Shale		—		—		112.6		18.8		3	%
Total Core Areas		208.5		57.3		578.3		362.2		66	%
Other		0.9		0.7		8.2		2.9		1	%
Total Proved Undeveloped		209.4		58.0		586.5		365.1		67	%
Total Proved Reserves		293.4		75.7		1,070.5		547.5		100	%

 

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(1)                       Includes 165 MMBoe of proved developed producing reserves representing 30% of total net proved reserves and 17 MMBoe of proved developed non-producing reserves representing 3% of total net proved reserves at December 31, 2013.

 

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 net proved reserves were prepared by our internal reserve engineers and audited by Ryder Scott Company, L.P. (Ryder Scott), our independent petroleum engineering consultants.

 

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, 2013.

 

		Net Proved Reserves
		(MMBoe)
As Reported		547.5
10 percent increase in commodity prices (1)		549.7
10 percent decrease in commodity prices (1)		528.1

 

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(1)                       Based on the first day 12-month average U.S prices of $96.94 per barrel of oil and $3.67 per MMBtu of natural gas used to determine net proved reserves at December 31, 2013.

 

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,

 

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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 the Marketing and Business Development groups.  In addition, he 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 Part II, Item 7. 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, 2013.  In connection with its audit, Ryder Scott reviewed 94% (by volume) of our total net proved reserves (or 96% not including proved reserves associated with our Brazil assets classified as discontinued operations) on a barrel of oil equivalent basis, representing 96% of the total discounted future net cash flows of these net proved reserves.  For the audited properties, 98% of our total net PUD reserves were evaluated.  As of December 31, 2013, we did not have PUD reserves associated with our Brazil assets.  Ryder Scott concluded the overall procedures and methodologies that we utilized in preparing our estimates of net proved reserves as of December 31, 2013 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 (SPE) auditing standards.  Ryder Scott’s report is included as an exhibit to this Annual Report on Form 10-K.

 

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 10 years of experience in petroleum reserves evaluation.

 

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

 

Proved Undeveloped Reserves (PUDs)

 

As of December 31, 2013, we have 981 net PUD locations, of which 968 are in our core areas.  At this time we do not have a developed to undeveloped relationship that is beyond one adjacent offset to a productive well.

 

We assess our PUD reserves on a quarterly basis. At December 31, 2013, we had 365 MMBoe of PUD reserves, representing an increase of 50 MMBoe of PUD reserves compared to December 31, 2012, excluding sales related to our divestitures of 26 MMBoe of PUD reserves. During 2013, we added 109 MMBoe of PUD reserves primarily from our drilling activities in the Eagle Ford Shale and the Wolfcamp Shale. We had 39 MMBoe of PUD reserves transferred to proved developed reserves and positive revisions of 6 MMBoe primarily due to better than originally forecasted performance of offsetting proved developed producing properties.  As of December 31, 2013, we have no PUD reserves associated with our Brazil assets classified as discontinued operations.

 

We spent approximately $679 million, $587 million and $601 million during 2013, 2012 and 2011, respectively, to convert approximately 12% or 39 MMBoe, 10% or 32 MMBoe and 17% or 35 MMboe, respectively, of our prior year-end PUD reserves to proved developed reserves. In our December 31, 2013 internal reserve report, the amounts estimated to be spent in 2014, 2015 and 2016 to develop our PUD reserves are $1,187 million, $1,611 million and $1,556 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 core 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.

 

Of the 365 MMBoe of PUD reserves at December 31, 2013, none are scheduled to remain undeveloped beyond five years.

 

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The following table summarizes our changes in PUDs for the years ended December 31, 2012 and December 31, 2013, respectively (in MMBoe):

 

Balance, December 31, 2011		320
Extensions and discoveries		131
Revisions of previous estimates (1)		(103	)
Transfers to proved developed		(32	)
Divestitures		(1	)
Balance, December 31, 2012		315
Extensions and discoveries		109
Revisions of previous estimates (2)		6
Transfers to proved developed		(39	)
Divestitures		(26	)
Balance, December 31, 2013		365

 

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(1)                                      Revisions to previous estimates during 2012 are primarily due to lower natural gas prices.

(2)                                      Revisions to previous estimates during 2013 are primarily due to improved performance and improved ownership positions.

 

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Acreage and Wells

 

The following tables detail (i) our interest in developed and undeveloped acreage at December 31, 2013, (ii) our interest in oil and natural gas wells at December 31, 2013 and (iii) our exploratory and development wells drilled during the years 2011 through 2013. 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
Core Areas
Eagle Ford Shale		19,406		18,211		85,552		73,464		104,958		91,675
Wolfcamp Shale		14,271		14,220		124,241		123,953		138,512		138,173
Altamont		139,574		118,779		174,112		54,331		313,686		173,110
Haynesville Shale		38,571		27,362		17,246		9,503		55,817		36,865
Total Core Areas		211,822		178,572		401,151		261,251		612,973		439,823
Other (3)		144,858		33,660		381,836		253,819		526,694		287,479
Total Acreage		356,680		212,232		782,987		515,070		1,139,667		727,302

 

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(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.

(3)                                      Includes South Louisiana Wilcox and Arklatex Tight Gas areas.

 

Our net developed acreage is concentrated primarily in Utah (56%), Louisiana (22%) and Texas (19%). Our net undeveloped acreage is concentrated primarily in Texas (40%), Wyoming (12%), Utah (11%), Michigan (10%), and Colorado (9%). Approximately 6%, 15% and 10% of our net undeveloped acreage is held under leases that have minimum remaining primary terms expiring in 2014, 2015 and 2016, 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, 2013 (1)
		Gross (2)		Net (4)		Gross (2)(3)		Net (4)		Gross (2)		Net (4)(5)		Gross (2)		Net (4)
Productive Wells
Core Areas
Eagle Ford Shale		284		269		3		3		287		272		24		24
Wolfcamp Shale		105		102		—		—		105		102		19		19
Altamont		432		324		3		1		435		325		7		5
Haynesville Shale		—		—		194		106		194		106		—		—
Total Core Areas		821		695		200		110		1,021		805		50		48
Other (6)		5		4		379		288		384		292		—		—
Total Productive Wells		826		699		579		398		1,405		1,097		50		48

 

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(1)                                      Comprised of wells that were spud as of December 31, 2013 and have not been completed.

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

(3)                                      Includes three wells with multiple completions.

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

(5)                                      At December 31, 2013, we operated 1,077 of the 1,097 net productive wells.

(6)                                      Includes South Louisiana Wilcox and Arklatex Tight Gas areas.

 

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		Net Exploratory (1)						Net Development (1)
		2013		2012		2011		2013		2012		2011
Wells Drilled
Core Areas
Productive		8		13		73		216		116		57
Dry		—		1		—		2		2		—
Total Core Areas		8		14		73		218		118		57
Other
Productive		—		7		9		—		5		2
Dry		—		—		—		—		1		—
Total Other		—		7		9		—		6		2
Divested Assets (2)
Productive		—		—		5		—		11		36
Dry		—		—		—		—		—		—
Total Divested Assets		—		—		5		—		11		36
Total
Productive		8		20		87		216		132		95
Dry		—		1		—		2		3		—
Total Wells Drilled		8		21		87		218		135		95

 

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(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 and 2011 include those for 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 core area and other, 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 three years ended December 31:

 

		2013		2012		2011
Volumes:
Consolidated Net Production Volumes
Core Areas
Oil and Condensate (MBbls)		13,230		8,277		4,220
Natural Gas (MMcf)		83,606		122,254		105,429
NGLs (MBbls)		2,424		1,056		216
Total Core Areas (MMBoe)		29,588		29,709		22,008
Other
Oil and Condensate (MBbls)		285		427		234
Natural Gas (MMcf)		8,634		12,603		14,440
NGLs (MBbls)		117		245		22
Total Other (MMBoe)		1,841		2,772		2,662
Core Areas and Other
Oil and Condensate (MBbls)		13,515		8,704		4,454
Natural Gas (MMcf)		92,240		134,857		119,869
NGLs (MBbls)		2,541		1,301		238
Total Core Areas and Other (MMBoe)		31,429		32,481		24,670
Divested Assets (1)
Oil and Condensate (MBbls)		—		297		1,226
Natural Gas (MMcf)		—		39,419		110,800
NGLs (MBbls)		—		312		830
Total Divested Assets(MMBoe)		—		7,179		20,523
Consolidated
Oil and Condensate (MBbls)		13,515		9,001		5,680
Natural Gas (MMcf)		92,239		174,276		230,669
NGLs (MBbls)		2,541		1,613		1,068
Total Consolidated (MMBoe)		31,429		39,660		45,193
MBoe/d		86.1		108.4		123.8
Unconsolidated Affiliate (2)
Oil and Condensate (MBbls)		197		282		306
Natural Gas (MMcf)		10,050		15,552		16,881
NGLs (MBbls)		327		478		556
Total Unconsolidated Affiliate (MMBoe)		2,199		3,352		3,675
MBoe/d		6.0		9.2		10.1
Total Combined Volumes
Oil and Condensate (MBbls)		13,712		9,283		5,986
Natural Gas (MMcf)		102,289		189,828		247,550
NGLs (MBbls)		2,868		2,091		1,624
Total Equivalent Volumes (MMBoe)		33,628		43,012		48,868
MBoe/d		92.1		117.6		133.9

 

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(1)              Predecessor periods  prior to May 24, 2012 include volumes from our CBM, South Texas, and the majority of our Arklatex assets, all of which were in sold in 2013, and our Gulf of Mexico assets, which were sold in 2012.  For periods after May 24, 2012, our CBM, South Texas, and Arklatex assets are treated as discontinued operations and accordingly volumes relating to those assets are excluded from all financial and non-financial metrics.  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)              Represents our approximate 49% equity interest in the volumes of Four Star Oil & Gas Company (Four Star), which we sold in September 2013.

 

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		2013		2012		2011
Core Area Net Production Volumes
Eagle Ford Shale
Oil and Condensate (MBbls)		8,763		5,023		1,702
Natural Gas (MMcf)		14,857		8,425		3,094
NGLs (MBbls)		2,133		936		207
Total Eagle Ford Shale (MMBoe)		13,372		7,364		2,425
Wolfcamp Shale
Oil and Condensate (MBbls)		1,306		489		132
Natural Gas (MMcf)		2,483		763		212
NGLs (MBbls)		280		116		—
Total Wolfcamp Shale (MMBoe)		2,000		734		168
Altamont
Oil and Condensate (MBbls)		3,161		2,765		2,385
Natural Gas (MMcf)		6,931		6,632		5,677
NGLs (MBbls)		11		4		7
Total Altamont (MMBoe)		4,327		3,876		3,338
Haynesville Shale
Oil and Condensate (MBbls)		—		—		1
Natural Gas (MMcf)		59,335		106,434		96,446
NGLs (MBbls)		—		—		2
Total Haynesville Shale (MMBoe)		9,889		17,736		16,077

 

		2013			2012			2011
Consolidated Prices and Costs per Unit:
Oil and Condensate Average Realized Sales Price ($/Bbl)
Physical Sales		$	94.97		$	92.58		$	90.22
Including Financial Derivatives (1)		$	97.72		$	97.19		$	88.98
Natural Gas Average Realized Sales Price ($/Mcf)
Physical Sales		$	3.31		$	2.54		$	3.91
Including Financial Derivatives (1)		$	3.02		$	4.49		$	5.37
NGLs Average Realized Sales Price ($/Bbl)
Physical Sales		$	30.81		$	37.63		$	53.50

 

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(1)              Amounts reflect settlements on financial derivatives, including cash premiums.  For the years ended December 31, 2013 and 2012 we received $9 million and paid $3 million of cash premiums, respectively. There were no cash premiums for the year ended December 31, 2011.

 

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