10-K 1 a14-6541_110k.htm ANNUAL REPORT PURSUANT TO SECTION 13 AND 15(D)

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.)

 

1001 Louisiana Street

 

 

Houston, Texas

 

77002

(Address of Principal Executive Offices)

 

(Zip Code)

 

Telephone Number: (713) 997-1200

Internet Website: www.epenergy.com

 

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

 

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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Table of Contents

 

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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Table of Contents

 

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.

 

iii



Table of Contents

 

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.

 

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Table of Contents

 

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

 

 


(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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Table of Contents

 

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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Table of Contents

 

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

%

 


(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.

 

4



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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Table of Contents

 

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

%

 


(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

 

 


(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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Table of Contents

 

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

 

 


(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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Table of Contents

 

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

 

 


(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

 

 


(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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Table of Contents

 

 

 

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

 

 


(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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Table of Contents

 

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

 

 


(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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Table of Contents

 

 

 

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

 

 


(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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Table of Contents

 

 

 

2013

 

2012

 

2011

 

Average Transportation Costs

 

 

 

 

 

 

 

Core Areas

 

 

 

 

 

 

 

Oil and Condensate ($/Bbl)

 

$

2.01

 

$

2.09

 

$

0.05

 

Natural Gas ($/Mcf)

 

$

0.52

 

$

0.40

 

$

0.34

 

NGLs ($/Bbl)

 

$

6.08

 

$

2.93

 

$

1.12

 

Other

 

 

 

 

 

 

 

Oil and Condensate ($/Bbl)

 

$

0.01

 

$

0.02

 

$

0.02

 

Natural Gas ($/Mcf)

 

$

0.83

 

$

0.46

 

$

0.39

 

NGLs ($/Bbl)

 

$

7.95

 

$

9.32

 

$

11.46

 

Core Areas and Other(1)

 

 

 

 

 

 

 

Oil and Condensate ($/Bbl)

 

$

1.96

 

$

1.99

 

$

0.05

 

Natural Gas ($/Mcf)

 

$

0.55

 

$

0.40

 

$

0.35

 

NGLs ($/Bbl)

 

$

6.17

 

$

4.12

 

$

2.06

 

Divested Assets(2)

 

 

 

 

 

 

 

Oil and Condensate ($/Bbl)

 

$

 

$

0.17

 

$

0.13

 

Natural Gas ($/Mcf)

 

$

 

$

0.43

 

$

0.35

 

NGLs ($/Bbl)

 

$

 

$

6.82

 

$

4.33

 

Consolidated

 

 

 

 

 

 

 

Oil and Condensate ($/Bbl)

 

$

1.96

 

$

1.93

 

$

0.06

 

Natural Gas ($/Mcf)

 

$

0.55

 

$

0.41

 

$

.35

 

NGLs ($/Bbl)

 

$

6.17

 

$

4.65

 

$

3.83

 

Average Lease Operating Expenses ($/Boe)

 

 

 

 

 

 

 

Core Areas

 

$

5.04

 

$

3.26

 

$

2.53

 

Other

 

$

7.49

 

$

5.33

 

$

5.17

 

Core Areas and Other(1) 

 

$

5.19

 

$

3.43

 

$

3.04

 

Divested Assets(2) 

 

$

 

$

5.44

 

$

5.19

 

Total Consolidated

 

$

5.19

 

$

3.80

 

$

3.89

 

Average Production Taxes ($/Boe)

 

 

 

 

 

 

 

Core Areas

 

$

2.84

 

$

1.93

 

$

1.25

 

Other

 

$

3.99

 

$

3.30

 

$

2.50

 

Core Areas and Other(1) 

 

$

2.90

 

$

2.04

 

$

1.38

 

Divested Assets(2) 

 

$

 

$

1.18

 

$

1.71

 

Total Consolidated

 

$

2.90

 

$

1.89

 

$

1.53

 

 


(1)             Average costs per unit are calculated using only costs associated with core areas and other oil and natural gas properties divided by the production of those areas.

(2)             Divested assets in 2012 and 2011 represents activity prior to May 24, 2012 and include our CBM, South Texas and Arklatex assets, each sold in 2013 and our Gulf of Mexico assets sold in 2012.

 

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Acquisition, Development and Exploration Expenditures

 

See Part II, Item 8, Financial Statements and Supplementary Data under the heading Supplemental Oil and Natural Gas Operations in the Cost Incurred table for details on our acquisition, development and exploration expenditures.

 

Transportation, Markets and Customers

 

Our marketing strategy seeks to ensure both maximum deliverability of our physical production and to achieve 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, 2013, three purchasers accounted for approximately 80% of our oil revenues: Chevron Corporation, Flint Hills Resources, LP, an affiliate of Koch Industries and 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 core 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, which is comprised of a crude oil gathering pipeline system and a separate natural gas gathering pipeline system. The Camino Real gas gathering system receives high-pressure unprocessed wellhead gas into an 83-mile pipeline with capacity of 150-170 MMcf/d. The gas is redelivered to interconnects with Energy Transfer, Enterprise, Regency and Eagle Ford Gathering. We currently have 125 MMcf/d of firm transportation capacity on the Camino Real gas gathering system, of which we used an average of 76% during the month of December 2013, and have additional capacity available as needed. Our gas gathering capacity utilization will increase as additional wells are connected. We have firm gas gathering, processing and transportation agreements on three of the interconnected pipelines downstream of the Camino Real gas gathering system that range between 85 and 100 MMBtu/d, with rights to increase firm capacity if necessary. We market our physical gas to various purchasers at spot market prices.

 

The Camino Real oil gathering system is a 68-mile long pipeline with over 110,000 Bbls/d of capacity and a gravity bank which allows for oil blending to support attractive API levels. We have 80,000 Bbls/d of firm capacity on this system, of which we used an average of 41% during December 2013. 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 Arrowhead #2 pipelines or loaded into trucks. Oil can also be delivered into trucks at the various central tank batteries throughout the field, providing additional deliverability and flexibility. We expect our utilization rate of this system to increase as additional wells are connected. We currently market our oil 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 are receiving a price premium for our Eagle Ford Shale oil relative to NYMEX/WTI, due primarily to Louisiana Light Sweet pricing and exposure to waterborne crude markets. With adequate takeaway capacity in the region and close proximity to the Gulf Coast refining complex, we do not anticipate any issues with marketing additional crude volumes from the Eagle Ford Shale.

 

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 (WTG), DCP and Lucid Energy Group gathering systems, and we process a majority of our gas at the WTG Benedum gas plant. 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 Plains pipeline at Owens Station in Reagan 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. With new Permian Basin takeaway pipelines coming online this year, we anticipate no constraints 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. 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 growth forecasts. In addition, we entered a crude-by-rail solution four years ago 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

 

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produced natural gas is gathered and processed at an Altamont plant under a long-term sales agreement that provides for residue gas return for operational use.

 

In our Haynesville Shale operating area, our 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 300 MMcf/d of firm capacity on these pipelines, of which we used an average of 51% during December 2013. 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 an 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 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 2,100 square miles of 3-D seismic data. We have 1,027 square miles of 3-D seismic data in our four core areas which provides approximately 36% 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 and Brazil. These regulations include, but are not limited to, those governing the drilling and spacing of wells, conservation, forced pooling and protection of correlative rights among interest owners.  We are also subject to various governmental safety and environmental regulations in the jurisdictions in which we operate.

 

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

 

Hydraulic Fracturing. Hydraulic fracturing is 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 core areas. Our domestic proved undeveloped oil and natural gas reserves are subject to hydraulic fracturing. For the year ended December 31, 2013, we incurred costs of approximately $521 million associated with hydraulic fracturing.

 

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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 federal regulators. Key aspects of our field protection measures include: (i) pressure testing well construction and integrity, (ii) casing and cementing practices to ensure pressure management and separation of hydrocarbons from groundwater, and (iii) public disclosure of the contents of hydraulic fracture fluids.

 

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

 

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

 

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

 

·                  Surface casing is set 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 USDW’s.

 

·                  Intermediate casing is set through the surface casing to a depth necessary to isolate abnormally pressured subsurface formations from normally pressured formations. Intermediate casing is not necessary or required for all wells. Our standard practices include 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 (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

 

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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

 

A description of our environmental remediation activities is included in Part II, Item 8, Financial Statements and Supplementary Data, Note 9.

 

Employees

 

As of February 25, 2014, we had 770 full-time employees in the United States.  We also had 30 employees in Brazil who are subject to collective bargaining arrangements.

 

Available Information

 

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

 

ITEM 1A. RISK FACTORS

 

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:

 

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

 

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

 

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

 

·                  adoption of various energy efficiency and conservation measures;

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

·                  natural gas inventory levels in the United States;

 

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

 

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

 

·                  volatile trading patterns in capital and commodity-futures markets;

 

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

 

·                  weather conditions;

 

·                  technological advances affecting energy consumption and energy supply;

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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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 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;

 

·                  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;

 

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·                  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 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 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.

 

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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 rules adopted 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 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 February 10, 2014. 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. We have established a capital budget for 2014 of approximately $2.0 billion and we intend to rely on cash flow from operating activities, available cash and borrowings under the RBL Facility as our primary sources of liquidity. We also may engage in asset sale transactions such as the pending and recently completed divestitures to, among other things, fund capital expenditures when market conditions permit us to complete transactions on terms we find acceptable. There can be no assurance that such sources will be sufficient to fund our exploration, development and acquisition activities. If our revenues and cash flows decrease in the future as a result of a decline in commodity prices or a reduction in production levels, however, and we are unable to obtain additional equity or debt financing in the capital markets or access alternative sources of funds, we may be required to reduce the level of our capital expenditures and may lack the capital necessary to increase or even maintain our reserves and production levels.

 

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

 

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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.

 

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 member’s equity. Changes in the present value of these reserves could also result in increasing our depreciation, depletion and amortization rates, which could decrease earnings.

 

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

 

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

 

The oil, natural gas and NGLs businesses are highly competitive. We compete with third parties in the search for and acquisition of leases, properties and reserves, as well as the equipment, materials and services required to explore for and produce our reserves. There has been intense competition for the acquisition of leasehold positions, particularly in many of the oil and natural gas shale plays. Our ability to acquire additional properties and to discover reserves in the future will be dependent upon our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. In addition, because we have fewer financial and human resources than many companies in our industry, we may be at a disadvantage in bidding for

 

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exploratory prospects and producing oil properties. Similarly, we compete with many third parties in the sale of oil, natural gas and NGLs to customers, some of which have substantially larger market positions, marketing staff and financial resources than us. Our competitors include major and independent oil and natural gas companies, as well as financial services companies and investors, many of which have financial and other resources that are substantially greater than those available to us. Many of these companies not only explore for and produce oil and natural gas, but also carry on refining operations and market petroleum and other products on a regional, national or worldwide basis. These companies may be able to pay more for productive oil and natural gas properties and exploratory prospects or define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit. In addition, these companies may have a greater ability to continue exploration activities during periods of low oil and natural gas market prices.

 

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

 

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

 

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

 

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

 

·                  Adverse weather conditions, natural disasters, and/or other climate related matters—including extreme cold or heat, lightning and flooding, fires, earthquakes, hurricanes, tornadoes and other natural disasters. Although the potential effects of climate change on our operations (such as hurricanes, flooding, etc.) are uncertain at this time, changes in climate patterns as a result of global emissions of greenhouse gas (GHG) could also have a negative impact upon our operations in the future, particularly with regard to any of our facilities that are located in or near coastal regions;

 

·                  Acts of aggression on critical energy infrastructure—including terrorist activity or “cyber security” events. We are subject to the ongoing risk that one of these incidents may occur which could significantly impact our business operations and/or financial results. Should one of these events occur in the future, it could impact our ability to operate our drilling and exploration processes, our operations could be disrupted, and/or property could be damaged resulting in substantial loss of revenues, increased costs to respond or other financial loss, damage to reputation, increased regulation and litigation and/or inaccurate information reported from our exploration and production operations to our financial applications, to our customers and to regulatory entities; and

 

·                  Other hazards—including the collision of third-party equipment with our infrastructure; explosions, equipment malfunctions, mechanical and process safety failures, well blowouts, formations with abnormal pressures and collapses of wellbore casing or other tubulars; events causing our facilities to operate below expected levels of capacity or efficiency; uncontrollable flows of natural gas, oil, brine or well fluids, release of pollution or contaminants (including hydrocarbons) into the environment (including discharges of toxic gases or substances) and other environmental hazards.

 

Each of these risks could result in (i) damage to and destruction of our facilities; (ii) damage to and destruction of property, natural resources and equipment; (iii) injury or loss of life; (iv) business interruptions while damaged energy infrastructure is repaired or replaced; (v) pollution and other environmental damage; (vi) regulatory investigations and penalties; and (vii) repair and remediation costs. Any of these results could cause us to suffer substantial losses. Our offshore operations in Brazil, which are in the process of being divested, may encounter additional marine perils, including adverse weather conditions, damage from collisions with

 

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vessels, and governmental regulations (including interruption or termination of drilling rights by governmental authorities based on environmental, safety and other considerations).

 

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

 

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.

 

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, 2013, three 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;

 

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·                  plugging and abandoning of wells, even if we no longer own and/or operate such wells;

 

·                  air quality, noise levels and related permits;

 

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

 

·                  taxation; and

 

·                  competitive bidding rules on federal and state lands.

 

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

 

Also, some of our assets are located and operate on federal, state, local or tribal lands and are typically regulated by one or more federal, state or local agencies. For example, we have drilling and production operations that are located on federal lands, which are regulated by the U.S. Department of the Interior (DOI), particularly by the Bureau of Land Management (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 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 us and may have conflicts of interest with us and or 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 our board of directors. As a result, the Sponsors and such other investors have control over our decisions to enter into certain

 

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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 or stock 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 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 our board of directors, 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, and Dane E. Whitehead, our Executive Vice President and Chief Financial Officer, but these agreements do not guarantee that these executives will remain with us. The unexpected loss of services of one or more of our executive officers or members of senior management could have a material adverse effect on our business.

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

We may face unanticipated water and other waste disposal costs.

 

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

 

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

 

·                  we cannot obtain future permits from applicable regulatory agencies;

 

·                  water of lesser quality or requiring additional treatment is produced;

 

·                  our wells produce excess water;

 

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

 

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

 

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;

 

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·                  we may encounter disruption to our ongoing business, distract management, divert resources and make it difficult to maintain our current business standards, controls,  procedures and policies;

 

·                  we may issue (or assume) additional equity or debt securities or debt instruments in connection with future acquisitions, which may affect our liquidity or financial leverage;

 

·                  we may make mistaken assumptions about costs, including synergies related to an acquired business;

 

·                  we may encounter difficulties in complying with regulations, such as environmental regulations, and managing risks related to an acquired business;

 

·                  we may encounter limitations on rights to indemnity from the seller;

 

·                  we may make mistaken assumptions about the overall costs of equity or debt used to finance any such acquisition;

 

·                  we may encounter difficulties in entering markets in which we have no or limited direct prior experience and where competitors in such markets have stronger expertise and/or market positions;

 

·                  we may 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 fund our anticipated capital program there is a risk that some of our existing proved reserves and some of our unproved inventory could be subject to lease expiration or a requirement to incur additional leasehold costs to extend the lease. This could result in a reduction in our reserves and our growth opportunities (or the incurrence of significant costs) and therefore could have a material adverse effect on our financial results.

 

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

 

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

 

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

 

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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. Our exploration and production operations in Brazil (which we expect to sell in 2014) are subject to various types of regulations similar to those described above, which are imposed by the Brazilian government, and which may affect our operations and costs within that country. Liabilities, penalties, suspensions, terminations and increased costs resulting from any failure to comply with regulations and requirements of the type described above, or from the enactment of additional similar regulations or requirements in the future or a change in the interpretation or the enforcement of existing regulations or requirements of this type, could have a material adverse effect on our business, results of operations and financial condition.

 

On December 15, 2009, the EPA published its findings that emissions of carbon dioxide, methane, and other GHGs present an endangerment to public health and the environment because emissions of such gases are, according to the EPA, contributing to the warming of the earth’s atmosphere and other climate changes. These findings served as a statutory prerequisite for EPA to adopt and implement regulations that would restrict emissions of GHGs under existing provisions of the Clean Air Act. The EPA has adopted two sets of related rules, one of which regulates emissions of GHGs from motor vehicles and the other of which regulates emissions of GHGs from certain large stationary sources of emissions such as power plants or industrial facilities. The EPA finalized the motor vehicle rule in April 2010 and it became effective January 2011. The EPA adopted the stationary source rule, also known as the “Tailoring Rule,” in May 2010, and it also became effective January 2011, although on October 15, 2013, the U.S. Supreme Court announced it will review aspects of the rule in 2014. Additionally, in September 2009, the EPA issued a final rule requiring the reporting of GHG emissions from specified large GHG emission sources in the U.S., including NGLs fractionators and local natural gas/distribution companies, beginning in 2011 for emissions occurring in 2010. In November 2010, the EPA expanded its existing GHG reporting rule to include onshore and offshore oil and natural gas production and onshore processing, transmission, storage and distribution facilities, which may include certain of our facilities, beginning in 2012 for emissions occurring in 2011. In addition, the EPA has continued to adopt GHG regulations of 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 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

 

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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.

 

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 in the Gulf of Mexico. Although we have sold our Gulf of Mexico assets, it is possible that similar, more stringent, regulations might be enacted or delays in receiving permits may occur in other areas, such as in offshore regions of other countries (such as Brazil) and in other onshore regions of the United States (including drilling operations on other federal or state lands).

 

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

 

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

 

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

 

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

 

We use hydraulic fracturing extensively in our operations. The hydraulic fracturing process is typically regulated by state oil and natural gas commissions. Hydraulic fracturing involves the injection of water, sand and chemicals under pressure into formations to fracture the surrounding rock and stimulate production. The Safe Drinking Water Act (the SDWA) regulates the underground injection of substances through the Underground Injection Control (UIC) program. While hydraulic fracturing generally is exempt from regulation under the UIC program, the EPA has taken the position that hydraulic fracturing with fluids containing diesel fuel is subject to regulation under the UIC program as “Class II” UIC wells. On October 21, 2011, the EPA announced its intention to propose federal Clean Water Act regulations by 2014 governing wastewater discharges from hydraulic fracturing and certain other natural gas operations. In addition, the DOI published a revised proposed rule on May 24, 2013 that would update existing regulation of hydraulic fracturing activities on federal lands, including requirements for disclosure, well bore integrity and handling of flowback water. The revised proposed rule was subject to an extended 90-day public comment period, which ended on August 23, 2013 and a final rule is expected in 2014.

 

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

 

On August 16, 2012, the EPA published final regulations under the Clean Air Act (CAA) that establish new air emission controls for oil and natural gas production and natural gas processing operations. Specifically, EPA promulgated New Source Performance Standards establishing emission limits for sulfur dioxide (SO2) and volatile organic compounds (VOCs). The final rule requires a 95% reduction in VOCs emitted by mandating the use of reduced emission completions or “green completions” on all hydraulically-fractured gas wells constructed or refractured after January 1, 2015. Until this date, emissions from fractured and refractured gas wells must be reduced through reduced emission completions or combustion devices. The rules also establish new requirements regarding emissions from compressors, controllers, dehydrators, storage tanks and other production equipment. In response to numerous requests for reconsideration of these rules from both industry and the environmental community and court challenges to the final rules, EPA announced its intention to issue revised rules in 2013. For example, 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.

 

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

 

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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.

 

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

 

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

 

·                  the repeal of the percentage depletion allowance for oil and gas properties;

 

·                  the elimination of current expensing of intangible drilling and development costs;

 

·                  the elimination of the deduction for certain U.S. production activities; and

 

·                  an extension of the amortization period for certain geological and geophysical expenditures.

 

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

 

Our Brazilian operations involve special risks.

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

We have certain contingent liabilities that could exceed our estimates.

 

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

 

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

 

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

 

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

 

Although we believe that the banks participating in the RBL Facility have adequate capital and resources, we can provide no assurance that all of those banks will continue to operate as a going 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 and have agreed to sell various assets and either retained certain liabilities or indemnified certain purchasers against future liabilities relating to businesses and assets sold or to be sold, including breaches of warranties, environmental expenditures, asset retirements and other representations that we have provided.  We may also be subject to retained liabilities with respect to certain divested assets by operation of law.  Although we believe that we have established appropriate reserves for any such liabilities, we could be required to accrue additional amounts in the future and these amounts could be material.

 

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

 

Our existing debt agreements contain, and any other existing or future indebtedness of ours would likely contain, a number of covenants that impose operating and financial restrictions on us, including restrictions on our and our subsidiaries ability to, among other things:

 

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·                  incur additional debt, guarantee indebtedness or issue certain preferred shares;

 

·                  pay dividends on or make distributions in respect of, or repurchase or redeem, our capital stock or make other restricted payments;

 

·                  prepay, redeem or repurchase certain debt;

 

·                  make loans or certain investments;

 

·                  sell certain assets;

 

·                  create liens on certain assets;

 

·                  consolidate, merge, sell or otherwise dispose of all or substantially all of our assets;

 

·                  enter into certain transactions with our affiliates;

 

·                  alter the businesses we conduct;

 

·                  enter into agreements restricting our subsidiaries’ ability to pay dividends; and

 

·                  designate our subsidiaries as unrestricted subsidiaries.

 

In addition, the RBL Facility requires us to comply with certain financial covenants. See Note 8 for additional discussion of the RBL covenants.

 

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 or any of our other indebtedness could result in an event of default, which, if not cured or waived, could have a material adverse effect on our business, financial condition and results of operations. In the event of any such default, the lenders thereunder:

 

·                  will not be required to lend any additional amounts to us;

 

·                  could elect to declare all borrowings outstanding, together with accrued and unpaid interest and fees, to be due and payable and terminate all commitments to extend further credit; or

 

·                  could require us to apply all of our available cash to repay these borrowings.

 

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

 

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ITEM 1B.             UNRESOLVED STAFF COMMENTS

 

None.

 

ITEM 2.                          PROPERTIES

 

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

 

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

 

ITEM 3.                         LEGAL PROCEEDINGS

 

A description of our material legal proceedings is included in Part II, Item 8, Financial Statements and Supplementary Data, Note 9, and is incorporated herein by reference.

 

ITEM 4.                         MINE SAFETY DISCLOSURES

 

Not applicable.

 

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

 

Apollo Global Management, LLC (“Apollo”) has provided notice to us that, as of October 24, 2013, certain investment funds managed by affiliates of Apollo beneficially owned approximately 22% of the limited liability company interests of CEVA Holdings, LLC (“CEVA”).  Under the limited liability company agreement governing CEVA, certain investment funds managed by affiliates of Apollo hold a majority of the voting power of CEVA and have the right to elect a majority of the board of CEVA.  CEVA may be deemed to be under common control with us, but this statement is not meant to be an admission that common control exists.  As a result, it appears that we are required to provide disclosures as set forth below pursuant to Section 219 of the Iran Threat Reduction and Syria Human Rights Act of 2012 (“ITRA”) and Section 13(r) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”).

 

Apollo has informed us that CEVA has provided it with the information below relevant to Section 13(r) of the Exchange Act.  The disclosure below does not relate to any activities conducted by us and does not involve us or our management. The disclosure relates solely to activities conducted by CEVA and its consolidated subsidiaries.  We have not independently verified or participated in the preparation of the disclosure below.

 

“Through an internal review of its global operations, CEVA has identified the following transactions in an Initial Notice of Voluntary Self-Disclosure that CEVA filed with the U.S. Treasury Department Office of Foreign Assets Control (“OFAC”) on October 28, 2013.  CEVA’s review is ongoing.  CEVA will file a further report with OFAC after completing its review.

 

The internal review indicates that, in  February 2013, CEVA Freight Holdings (Malaysia) SDN BHD (“CEVA Malaysia”) provided customs brokerage for export and local haulage services for a shipment of polyethylene resin to Iran shipped on a vessel owned and/or operated by HDS Lines, also an SDN.  The revenues and net profits for these services were approximately $779.54 USD and $311.13 USD, respectively.  In September 2013, CEVA Malaysia provided customs brokerage services for the import into Malaysia of fruit juice from Alifard Co. in Iran via HDS Lines.  The revenues and net profits for these services were approximately $227.41 USD and $89.29 USD, respectively.

 

These transactions violate the terms of internal CEVA compliance policies, which prohibit transactions involving Iran.  Upon discovering these transactions, CEVA promptly launched an internal investigation, and is taking action to block and prevent such transactions in the future.  CEVA intends to cooperate with OFAC in its review of this matter.”

 

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PART II

 

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

 

Our common stock started trading on the New York Stock Exchange under the symbol EPE on January 17, 2014. As of February 20, 2014, we had 23 stockholders of record which does not include beneficial owners whose shares are held by a clearing agency, such as a broker or bank.

 

ITEM 6.                SELECTED HISTORICAL CONSOLIDATED FINANCIAL DATA

 

Set forth below is our 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, 2013 and December 31, 2012 and the statements of income data  and statements of cash flow data for the year ended December 31, 2013, for the period from February 14 to December 31, 2012, the period from January 1, 2012 through May 24, 2012 and the year ended December 31, 2011, from  the audited consolidated financial statements of EP Energy Corporation included in this Report on Form 10-K.  We have derived the selected historical consolidated balance sheet data as of December 31, 2011, 2010 and 2009, and the statements of income data and statements of cash flow data for the years ended December 31, 2010 and 2009 from the consolidated historical predecessor financial statements of EP Energy Corporation, which are not included in this Report on Form 10-K.  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.  See Item 8. Financial Statements and Supplementary Data, Note 2. Acquisitions and Divestitures, for further discussion.

 

The following selected historical financial data should be read in conjunction with Item 7, “Management’s Discussion and Analysis of Financial Condition” and “Results of Operations” and Item 8, “Financial Statements and Supplementary Data” included in this Report on Form 10-K.

 

 

 

Successor

 

 

Predecessor

 

 

 

Year ended
December 31,

 

February 14
to
December 31,

 

 

January 1,
to May 24,

 

For Years ended December 31,

 

 

 

2013

 

2012

 

 

2012

 

2011

 

2010

 

2009

 

 

 

 

 

 

 

 

(in millions)

 

 

 

 

 

Results of Operations

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Operating revenues

 

$

1,640

 

$

727

 

 

$

932

 

$

1,756

 

$

1,704

 

$

1,803

 

Operating income (loss)

 

380

 

(66

)

 

338

 

648

 

738

 

(1,231

)

Interest expense

 

(354

)

(219

)

 

(14

)

(14

)

(23

)

(27

)

(Loss) income from continuing operations

 

(58

)

(300

)

 

187

 

385

 

451

 

(823

)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Cash Flow

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net cash provided by (used in):

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Operating activities

 

$

960

 

$

449

 

 

$

580

 

$

1,426

 

$

1,067

 

$

1,573

 

Investing activities

 

(475