Table of Contents

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

 

FORM 10-K

 

 

 

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

For the Fiscal Year Ended December 31, 2014

 

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

For the Transition Period From                  to                 

Commission File No. 333-186686

 

 

SAMSON RESOURCES CORPORATION

(Exact name of registrant as specified in its charter)

 

 

 

Delaware   45-3991227

(State or other jurisdiction of

incorporation or organization)

 

(I.R.S. Employer

identification No.)

Samson Plaza

Two West Second Street

Tulsa, OK 74103-3103

(Address and zip code of registrant’s principal executive offices)

(918) 591-1791

(Registrant’s telephone number, including area code)

 

 

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

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

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 (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes  x    No  ¨

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  ¨

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

 

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

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

As of March 15, 2015, Samson Resources Corporation had 845,600,000 shares of common stock outstanding.

 

 

 


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SAMSON RESOURCES CORPORATION

TABLE OF CONTENTS

 

     Page
Number
 

Part I.

     6   

Item 1. Business

     6   

Item 1A. Risk Factors

     25   

Item 1B. Unresolved Staff Comments

     48   

Item 2. Properties

     48   

Item 3. Legal Proceedings

     48   

Item 4. Mine Safety Disclosures

     48   

Part II.

     49   

Item  5. Market for Our Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

     49   

Item 6. Selected Financial Data

     49   

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations

     51   

Item 7A. Quantitative and Qualitative Disclosures about Market Risk

     75   

Item 8. Financial Statements and Supplementary Data

     76   

Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosures

     76   

Item 9A. Controls and Procedures

     76   

Item 9B. Other Information

     76   

Part III.

     77   

Item 10. Directors, Executive Officers and Corporate Governance

     77   

Item 11. Executive Compensation

     84   

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

     109   

Item 13. Certain Relationships and Related Transactions, and Director Independence

     111   

Item 14. Principal Accounting Fees and Services

     117   

Part IV.

     118   

Item 15. Exhibits, Financial Statement Schedules

     118   

Signatures

     127   

Index to Financial Statements

     F-1   

Index to Exhibits

  

Certification of CEO Pursuant to Rule 13a-14(a)

  

Certification of CFO Pursuant to Rule 13a-14(a)

  

Certification of CEO Pursuant to Rule 13a-14(b)

  

Certification of CFO Pursuant to Rule 13a-14(b)

  

 

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CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

The information in this report includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”), and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). All statements included in this report, other than statements of historical fact, may constitute forward-looking statements, including, but not limited to, statements or information regarding our future growth, results of operations, operational and financial performance, business prospects and opportunities and future events. Words such as, but not limited to, “anticipate,” “continue,” “estimate,” “expect,” “may,” “might,” “will,” “project,” “should,” “believe,” “intend,” “continue,” “could,” “plan,” “predict,” “potential,” “goal,” “foresee” and negatives of these words and similar expressions are intended to identify forward-looking statements. In particular, statements about our expectations, beliefs, plans, objectives, assumptions or future events or performance contained in this report are forward-looking statements. These statements are based on, but not limited to, management’s assessment of such factors as the condition of our industry and the competitive environment. These assessments could prove inaccurate.

All forward-looking statements involve risks and uncertainties. The occurrence of the events described and the achievement of the expected results depend on many events and assumptions, some or all of which are not predictable or within our control. Although the forward-looking statements contained in this report reflect our current beliefs based upon information currently available to us and upon assumptions which we believe to be reasonable, actual results may differ materially from expected results.

We caution you that these forward-looking statements are subject to all of the risks and uncertainties, most of which are difficult to predict and many of which are beyond our control, incident to the exploration for and development, production, gathering and sale of oil and natural gas. Factors that may cause actual results to differ from expected results include, but are not limited to: (i) our substantial indebtedness; (ii) our ability to refinance, restructure or amend our indebtedness or otherwise improve our capital structure and liquidity; (iii) our ability to generate or obtain sufficient cash to service our indebtedness and other obligations; (iv) fluctuations in oil and natural gas prices; (v) restrictions contained in our debt agreements; (vi) the uncertainty inherent in estimating our reserves, future net revenues and discounted future cash flows; (vii) the timing and amount of future production of oil and natural gas; (viii) cash flow and changes in the availability and cost of capital; (ix) environmental, drilling and other operating risks, including liability claims as a result of our oil and natural gas operations; (x) proved and unproved drilling locations and future drilling plans; (xi) the effects of existing and future laws and governmental regulations, including environmental, hydraulic fracturing and climate change regulation; (xii) our ability to make acquisitions and divestitures on favorable terms or at all; and (xiii) any of the risk factors and other cautionary statements described under Part I, Item 1A—“Risk Factors” in this report or in any other report, registration statement or other document that we may file from time to time with the Securities and Exchange Commission (the “SEC”).

Readers are cautioned not to place undue reliance on forward-looking statements. Should one or more of the risks or uncertainties referenced above occur, or should underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements. Further, new factors that could cause actual results to differ materially from those described in forward-looking statements emerge from time to time, and it is not possible to predict all such factors, or to the extent to which any such factor or combination of factors may cause actual results to differ from those contained in any forward-looking statement.

All forward-looking statements, expressed or implied, included in this report are expressly qualified in their entirety by this cautionary statement. This cautionary statement should also be considered in connection with any subsequent written or oral forward-looking statements that we or persons acting on our behalf may issue.

Each forward-looking statement speaks only as of the date of this report, and, except as otherwise required by applicable law, we disclaim any duty to update any forward-looking statements, all of which are expressly qualified by the statements in this section, to reflect events or circumstances after the date of this report.

 

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GLOSSARY OF OIL AND NATURAL GAS TERMS

The following are abbreviations and definitions of certain terms used in this document, which are commonly used in the oil and natural gas industry:

Basin.” A large natural depression on the earth’s surface in which sediments generally brought by water accumulate.

Bbl.” One stock tank barrel, of 42 U.S. gallons liquid volume, used herein in reference to crude oil, condensate or natural gas liquids.

Bcf.” One billion cubic feet of natural gas.

Bcfe.” One billion cubic feet equivalent, determined using a ratio of six Mcf of natural gas to one Bbl of oil, condensate or natural gas liquids.

Bcfe/d.” Bcfe per day.

“Btu.” One British thermal unit, which is the quantity of heat required to raise the temperature of a one pound mass of water by one degree Fahrenheit.

Completion.” The process of treating a drilled well followed by the installation of permanent equipment for the production of oil and/or natural gas, or in the case of a dry hole, the reporting of abandonment to the appropriate agency.

Delay rental.” A payment under an oil and gas lease by the lessee to the lessor for the privilege of deferring the commencement of drilling operations or the commencement of production during the primary term of the lease.

Developed acreage.” The number of acres that are allocated or assignable to productive wells or wells capable of production.

Development well.” A well drilled within the proved area of an oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.

Dry hole.” A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes.

Exploratory well.” A well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or natural gas in another reservoir.

Field.” An area consisting of a single reservoir or multiple reservoirs all grouped on, or related to, the same individual geological structural feature and/or stratigraphic condition. There may be two or more reservoirs in a field that are separated vertically by intervening impervious, strata, or laterally by local geologic barriers, or by both. Reservoirs that are associated by being in overlapping or adjacent fields may be treated as a single or common operational field. The geological terms structural feature and stratigraphic condition are intended to identify localized geological features as opposed to the broader terms of basins, trends, provinces, plays, areas-of-interest, etc.

Formation.” A layer of rock which has distinct characteristics that differs from nearby rock.

Gross acres or gross wells.” The total acres or wells, as the case may be, in which a working interest is owned.

Horizontal drilling.” A drilling technique used in certain formations where a well is drilled vertically to a certain depth and then drilled horizontally within a specified interval.

 

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Mcf.” One thousand cubic feet of natural gas.

Mcfe.” One thousand cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids.

MMBbl.” One million barrels of crude oil, condensate or natural gas liquids.

MMBtu.” One million British thermal units.

MMcfe.” One million cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids.

MMcfe/d.” Mmcfe per day.

Natural gas liquids or NGLs.” Hydrocarbons found in natural gas which may be extracted as liquefied petroleum gas and natural gasoline.

Net acres or net wells.” The sum of the fractional working interest owned in gross acres or gross wells. An owner who has 50% interest in 100 acres has 50 net acres.

NYMEX.” The New York Mercantile Exchange.

Potential drilling locations.” The gross resource play locations that we potentially may be able to drill on our existing acreage. Our actual drilling activities may change depending on the availability of capital, regulatory approvals, seasonal restrictions, oil and natural gas prices, costs, drilling results and other factors.

Productive well.” A well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of the production exceed production expenses and taxes. Productive wells include producing wells and wells that are mechanically capable of production.

Prospect.” A specific geographic area which, based on supporting geological, geophysical or other data and also preliminary economic analysis using reasonably anticipated prices and costs, is deemed to have potential for the discovery of commercial hydrocarbons.

Proved developed reserves.” Proved reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.

Proved reserves.” Those quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation.

Proved undeveloped reserves (‘PUD’).” Proved reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion.

Recompletion.” The process of re-entering an existing wellbore that is either producing or not producing and completing new reservoirs in an attempt to establish or increase existing production.

Reserves.” Estimated remaining quantities of oil and natural gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations.

 

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Reservoir.” A porous and permeable underground formation containing a natural accumulation of producible oil and/or natural gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.

Spacing.” The distance between wells producing from the same reservoir. Spacing is often expressed in terms of acres, e.g., 40-acre spacing, and is often established by regulatory agencies.

Spud.” The commencement of drilling operations of a new well.

Standardized measure of discounted future net cash flows.” The standardized measure provides value-based information about proved oil and gas reserves based on estimates of future cash flows from production of proved reserves assuming continuation of year-end economic and operating conditions.

Tcfe.” One trillion cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids.

Undeveloped acreage.” Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas regardless of whether such acreage contains proved reserves.

Unit.” The joining of all or substantially all interests in a particular spacing or development area or section, rather than a single tract, to provide for development and operation without regard to separate property interests. Also, the area covered by a unitization agreement or pooling order.

Wellbore.” The hole drilled by the bit that is equipped for oil or natural gas production on a completed well. Also called well or borehole.

Working interest.” The right granted to the lessee of a property to explore for and to produce and own oil, natural gas or other minerals. The working interest owners bear the exploration, development, and operating costs on either a cash, penalty, or carried basis.

 

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PART I

Unless the context requires otherwise, in this report, references to (i) “Samson,” the “Company,” “we,” “us” and “our” refer to Samson Resources Corporation and its consolidated subsidiaries and (ii) “natural gas” or “gas” include natural gas liquids, which we sometimes refer to as “NGLs.” Certain other operational and industry terms used in this report are defined above under “Glossary of Oil and Natural Gas Terms.”

 

ITEM 1. BUSINESS

Overview

We are an independent oil and gas company engaged in the exploration, development and production of oil and natural gas properties located onshore in the United States. We operate our business and properties through our West Division, which includes properties primarily in the Rocky Mountain region, and our East Division, which includes properties primarily in the Mid-Continent and East Texas regions.

As of December 31, 2014, we had proved reserves of approximately 1.5 Tcfe. Approximately 12.9% of our net proved reserves were oil, 14.3% were natural gas liquids and 72.8% were natural gas. Our net daily production for the year ended December 31, 2014 averaged approximately 530 MMcfe per day, including approximately13,674 Bbls per day of oil and approximately 12,792 Bbls per day of natural gas liquids. As of December 31, 2014, we owned interests in approximately 7,354 gross (3,289 net) productive wells, with approximately 81% of our net production operated by Samson. During 2014, we completed 107 gross (80 net) operated wells.

The table below provides certain selected operational information for the periods indicated.

 

     Year Ended
December 31,
2014
     As of December 31, 2014  
     Average
Net Daily
Production
(MMcfe/d)
     Proved
Reserves
(Bcfe)
     Proved
Developed
Reserves
(%)
    Net
Acreage
(in
thousands)
 

West Division Business Units:

          

Williston

     25         83         56     98   

Powder River

     27         58         91     292   

Greater Green River

     53         104         87     211   

San Juan

     80         198         99     55   
  

 

 

    

 

 

    

 

 

   

 

 

 

Total West Division

  185      443      88   656   

East Division Business Units:

Mid-Continent West

  80      260      76   173   

Mid-Continent East

  102      255      90   278   

East Texas

  161      533      82   360   
  

 

 

    

 

 

    

 

 

   

 

 

 

Total East Division

  343      1,048      83   811   

Other(1)

  2      1      —        101   
  

 

 

    

 

 

    

 

 

   

 

 

 

Total

  530      1,492      84   1,568   
  

 

 

    

 

 

    

 

 

   

 

 

 

 

(1) Other reflects our interests in certain non-core assets located throughout the continental United States.

Corporate History

Samson Resources Corporation, a Delaware corporation, was formed in November 2011 in connection with the acquisition of Samson Investment Company from its selling stockholders (the “Acquisition”) by certain

 

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affiliates of Kohlberg Kravis Roberts & Co. L. P. (“KKR”), ITOCHU Corporation (“ITOCHU”) and certain other co-investors. In December 2011, the Acquisition closed and Samson Investment Company became a direct, wholly-owned subsidiary of Samson Resources Corporation, with KKR and certain other co-investors, including investment funds affiliated with Crestview Partners II GP, L.P. and Natural Gas Partners IX, L.P., holding their shares of common stock of Samson Resources Corporation through Samson Aggregator L.P. (“Samson Aggregator”) and ITOCHU holding their shares of common stock of Samson Resources Corporation through JD Rockies Resources Limited (“JD Rockies”). In this report, Samson Aggregator and JD Rockies are sometimes collectively referred to as the “Principal Stockholders.” For more information about our equity investors, see Part III, Item 12—“Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters” and Part III, Item 13—“Certain Relationships and Related Transactions, and Director Independence.”

We financed the Acquisition, repaid all of Samson Investment Company’s then outstanding long-term indebtedness and paid related fees and expenses with: (i) approximately $1.345 billion of borrowings under a reserves-based borrowing base revolving credit facility (the “RBL Revolver”); (ii) $2.250 billion of borrowings under a syndicated senior unsecured bridge facility (the “Bridge Facility”); (iii) $4.145 billion of equity capital from the Principal Stockholders; and (iv) $180.0 million aggregate liquidation preference of cumulative redeemable preferred stock, par value $0.10 per share (the “Cumulative Preferred Stock”), issued by Samson Resources Corporation to the selling stockholders. In February 2012, we issued $2,250,000,000 aggregate principal amount of 9.750% Senior Notes due 2020 (the “Senior Notes”) and used the proceeds, together with cash on hand, to repay outstanding borrowings under our Bridge Facility in full and pay related fees and expenses.

Samson Investment Company is a Nevada corporation and was formed in June 1986 as the holding company for a Tulsa, Oklahoma-based oil and natural gas exploration and production business, which had previously been operating since 1971 under our subsidiary, Samson Resources Company. Prior to the Acquisition, Samson Investment Company completed a reorganization transaction, which allowed the selling stockholders to retain certain assets and liabilities associated with its coastal Gulf of Mexico and offshore operations (the “Gulf Coast Assets”), and, as a result, the Gulf Coast Assets were not included in the Acquisition. In this report, references to “Predecessor” refer to Samson Investment Company and its consolidated subsidiaries prior to the consummation of the Acquisition.

Our Operations

Estimated Proved Reserves

The following table summarizes our historical estimated proved reserves as of the dates indicated. The estimated proved reserves presented below are based on reports prepared by Netherland, Sewell & Associates, Inc. (“NSAI”), our independent petroleum engineers. In preparing the reports, NSAI evaluated properties representing all of the Company’s reserves as of the dates indicated. The estimated proved reserves presented below include proved reserves attributable to assets divested subsequent to the dates indicated. You should refer to Part I, Item 1A—“Risk Factors,” Part II, Item 7—“Management’s Discussion and Analysis of Financial

 

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Condition and Results of Operations” and Note 23 to our audited consolidated financial statements included Part II, Item 8—“Financial Statements and Supplementary Data” of this report when evaluating the material presented below.

 

     As of
December 31,
2014
    As of
December 31,
2013
    As of
December 31,
2012
 

Estimated proved reserves:

      

Natural gas (Bcf)

     1,086        1,246        1,323   

Natural gas liquids (MMBbls)

     36        50        47   

Oil (MMBbls)

     32        52        68   

Total estimated proved reserves (Bcfe)

     1,492        1,857        2,014   

Proved developed producing (Bcfe)

     1,247        1,216        1,297   

Proved developed non-producing (Bcfe)

     6        16        11   

Proved undeveloped (Bcfe)

     240        625        707   

Percent proved developed producing reserves

     84     66     64

Development of Proved Undeveloped Reserves

Our estimated proved undeveloped reserves decreased from approximately 625 Bcfe at December 31, 2013 to approximately 240 Bcfe at December 31, 2014. This reduction was primarily due to negative revisions of previous estimates of approximately 333 Bcfe and current year drilling activity. The negative revisions particularly impacted certain of our assets in the Mid-Continent, East Texas, Powder River and Greater Green River Basins formations and principally occurred as a result of enhanced engineering, petrophysical and geological interpretation, operated and non-operated drilling patterns, and offset well analysis. These revisions were offset by additions of approximately 68 Bcfe from extensions and discoveries primarily in the Cotton Valley formation. In addition, approximately 126 Bcfe was converted from undeveloped to developed reserves. The following table summarizes the changes in our estimated proved undeveloped reserves during 2014 (in Bcfe):

 

Proved undeveloped reserves, December 31, 2013

     625   

Purchases of reserves in place

     6   

Sales of reserves

     —     

Extensions and discoveries

     68   

Revisions of previous estimates

     (333

Conversion to proved developed reserves

     (126
  

 

 

 

Proved undeveloped reserves, December 31, 2014

  240   
  

 

 

 

During 2014, we converted approximately 126 Bcfe of proved undeveloped reserves to proved developed reserves or 20% of our total proved undeveloped reserves booked at December 31, 2013. During 2014, we incurred approximately $558.1 million in drilling and completion capital expenditures, including approximately $253.0 million to convert reserves classified as proved undeveloped as of December 31, 2013 to reserves classified as proved developed as of December 31, 2014. Costs of proved undeveloped reserves development in 2014 do not represent the total costs of these conversions, as additional costs may have been incurred in previous years. For additional information on our capital expenditures, see Part II, Item 7—“Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources.”

As of December 31, 2014, none of our proved undeveloped reserves at December 31, 2014 were scheduled to be developed on a date more than five years from the date the reserves were initially booked as proved undeveloped.

 

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Qualifications of Technical Persons and Internal Controls Over Reserves Estimation Process

In accordance with the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers and guidelines established by the SEC, Netherland, Sewell & Associates, Inc. (“NSAI”), our independent reserve engineers, estimated 100% of our proved reserve information as of December 31, 2014, 2013 and 2012. As discussed in their biographical information and qualifications provided below, the technical persons responsible for preparing the reserves estimates presented herein meet or exceed the education, training, and experience requirements set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers; both are proficient in judiciously applying industry standard practices to engineering and geoscience evaluations as well as applying SEC and other industry reserves definitions and guidelines.

NSAI Engineers

Within NSAI, the technical persons primarily responsible for preparing the estimates set forth in the NSAI reserves report are Mr. Connor B. Riseden and Mr. Mike K. Norton.

Mr. Riseden, a Licensed Professional Engineer in the State of Texas (No. 100566), has been practicing consulting petroleum engineering at NSAI since 2006 and has over 4 years of prior industry experience. He graduated from Texas A&M University in 2001 with a Bachelor of Science Degree in Petroleum Engineering and from Tulane University in 2005 with a Master of Business Administration Degree.

Mr. Norton, a Licensed Professional Geoscientist in the State of Texas, Geology (No. 441), has been practicing consulting petroleum geoscience at NSAI since 1989 and has over 10 years of prior industry experience. He graduated from Texas A&M University in 1978 with a Bachelor of Science Degree in Geology.

Internal Engineers

We maintain an internal staff of petroleum engineers and geoscience professionals who work closely with our independent reserve engineers to ensure the integrity, accuracy and timeliness of data furnished to NSAI in their reserves estimation process. Our technical team meets regularly with representatives of NSAI to review properties and discuss methods and assumptions used in NSAI’s preparation of the year-end reserves estimates. The NSAI reserve report is reviewed with representatives of NSAI and our internal technical staff before dissemination of the information. Additionally, members of our management team review the NSAI reserve report with senior reservoir engineering staff and other members of our technical staff.

Martin Dobson, our Director of Reserves and Technology, is the technical person primarily responsible for overseeing the preparation of the Company’s reserves estimates by NSAI. He has over 31 years of industry experience, including approximately 20 years of experience in the estimation and evaluation of reserves. His work experience includes well and field reserve estimation for SEC qualification, Acquisition/Disposition and field optimization for gas fields, oil fields, and water floods. He has provided expert witness testimony before the Wyoming Oil and Gas Conservation Commission and is the primary author of multiple SPE papers focused on probabilistic reserve booking and from which key principles were used in the SPEE Monograph 3 of the same subject. He has a Bachelor of Science degree in Biology from Weber State University and a Master of Science degree from Brigham Young University and is a member of the Society of Petroleum Engineers. Our Director of Reserves and Technology reports directly to our Executive Vice President and Chief Operating Officer. Reserves estimates are reviewed and approved by the Director of Reserves and Technology, with final approval by our Executive Vice President and Chief Operating Officer.

Productive Wells

The following table sets forth the number of productive wells in which we owned a working interest at December 31, 2014. Productive wells consist of producing wells and wells capable of producing, including

 

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natural gas wells awaiting pipeline connections to commence deliveries and oil wells awaiting connection to production facilities. “Gross” wells are the total number of productive wells in which we have working interests, and “net” wells are the sum of our fractional working interests owned in gross wells. Each gross well completed in more than one producing zone is counted as a single well. As of December 31, 2014, approximately 86% of our total gross productive wells and 89% of total net productive wells were classified as natural gas wells (in which natural gas is the primary product).

 

     Oil      Natural Gas      Total  
     Gross      Net      Gross      Net      Gross      Net  

West Division Business Units:

                 

Williston

     209         81         —           —           209         81   

Powder River

     189         103         179         25         368         128   

Greater Green River

     11         6         447         138         458         144   

San Juan

     1         —           328         267         329         267   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total West Division

  410      190      954      430      1,364      620   

East Division Business Units:

Mid-Continent West

  131      43      1,244      580      1,375      623   

Mid-Continent East

  414      102      2,223      539      2,637      641   

East Texas

  56      37      1,909      1,362      1,965      1,399   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total East Division

  601      182      5,376      2,481      5,977      2,663   

Other(1)

  3      1      10      5      13      6   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total Productive Wells

  1,014      373      6,340      2,916      7,354      3,289   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

 

(1) Other reflects our interests in certain non-core assets located throughout the continental United States.

Drilling Activities

The table below sets forth the results of the drilling activities for the periods indicated. The information should not be considered indicative of future performance, nor should it be assumed that there is necessarily any correlation between the number of productive wells drilled, quantities of reserves found or economic value. The information presented below includes our drilling activities with respect to assets divested subsequent to the periods indicated.

 

     Year Ended
December 31,
2014
     Year Ended
December 31,
2013
     Year Ended
December 31,
2012
 
     Gross      Net      Gross      Net      Gross      Net  

Exploratory Wells

                 

Productive(1)

     14         10         11         7         8         6   

Dry

     —           —           —           —           1         1   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total Exploratory

  14      10      11      7      9      7   

Development Wells

Productive(1)

  176      76      238      71      395      114   

Dry

  5      2      1      —        3      2   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total Development

  181      78      239      71      398      116   

Total Wells

Productive(1)

  190      86      249      78      403      120   

Dry

  5      2      1      —        4      3   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total Development and Exploratory Wells

  195      88      250      78      407      123   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

 

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(1) Although a well may be classified as productive upon completion, future changes in oil and natural gas prices, operating costs and production may result in the well becoming uneconomical, particularly with respect to exploratory wells where there is no production history.

As of December 31, 2014, we had 43 gross (19 net) wells in the process of drilling, completing or waiting on completion and 23 gross (17 net) operated wells in the process of drilling, completing or waiting on completion.

Developed and Undeveloped Acreage

The following table sets forth as of December 31, 2014 our approximate gross and net developed and undeveloped oil and natural gas leasehold and fee mineral acreage. “Gross” acres are the total number of acres in which we own a working interest. “Net” acres refer to gross acres multiplied by our fractional working interest.

 

     Developed
Leasehold
Acreage
     Undeveloped
Leasehold
Acreage
     Fee
Minerals
     Total
Acreage
 
     (acreage in thousands)  
     Gross      Net      Gross      Net      Gross      Net      Gross      Net  

West Division Business Units:

                       

Williston

     143         59         85         39         1         —           229         98   

Powder River

     258         135         193         157         2         —           453         292   

Greater Green River

     227         120         105         91         1         —           333         211   

San Juan

     41         29         31         26         —           —           72         55   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total West Division

  669      343      414      313      4      —        1,087      656   

East Division Business Units:

Mid-Continent West

  326      159      4      4      27      10      357      173   

Mid-Continent East

  635      247      33      16      51      15      719      278   

East Texas

  347      284      23      8      392      68      762      360   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total East Division

  1,308      690      60      28      470      93      1,838      811   

Other(1)

  20      7      116      77      12      17      148      101   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total Acreage

  1,997      1,040      590      418      486      110      3,073      1,568   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

 

(1) Other reflects our interests in certain non-core assets located throughout the continental United States.

The following table sets forth the number of gross and net undeveloped acres as of December 31, 2014 that will expire during the years indicated if production is not established or if we take no other action to extend the terms of the leases or concessions (other than the payment of delay rentals during the primary term of the applicable lease).

 

2015

   2016    2017

Gross

   Net    Gross    Net    Gross    Net

179,803

   99,528    119,172    73,928    82,552    73,963

As of December 31, 2014, less than 1% of our net acres related to proved undeveloped reserves had a lease expiration date preceding the scheduled initial drill date and a portion of such acreage is subject to leasehold extension rights. We intend to exercise such extension rights where applicable, pursue lease renewals and engage in other leasehold management efforts in order to preserve our leasehold interests with respect to such proved undeveloped reserves.

 

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Production, Revenues and Price History

Oil and natural gas are commodities and, as a result, the prices that we receive for our production can fluctuate widely due to changes in market supply and demand. Commodity prices have historically been volatile, including recently where oil and natural gas prices have declined significantly in the last half of 2014 with continued weakness in 2015. A further decline or sustained depression in oil or natural gas prices could have a material adverse effect on our business, results of operations, financial condition, access to capital and ability to meet our financial commitments and other obligations. For additional information on commodity price volatility and related risks, see Part I, Item 1A—“Risk Factors.”

The following table sets forth information regarding our net production of oil and natural gas and certain price and cost information for each of the periods indicated. The information presented below includes production data with respect to assets divested subsequent to the periods indicated. For additional information on price calculations, see the information set forth in Part II, Item 7—“Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

 

     Year Ended December 31,  
   2014      2013      2012  

Production data:

        

Natural gas (Bcf)

     135.2         150.9         178.8   

Oil (MMBbls)

     5.0         5.3         6.2   

NGLs (MMBbls)

     4.7         4.7         4.0   

Combined production (Bcfe)(1)

     193.2         210.8         240.0   

Average combined daily production (Bcfe/d)(1)

     530         578         657   

Average sales prices before effects of hedges:(2)

        

Natural gas (Mcf)

   $ 3.87       $ 3.28       $ 2.17   

Oil (Bbl)

     85.63         92.38         83.92   

NGL (Bbl)

     31.11         32.30         35.03   

Mcfe

     5.68         5.40         4.37   

Average sales prices after effects of realized hedges:(2)

        

Natural gas (Mcf)

   $ 3.65       $ 3.37       $ 3.01   

Oil (Bbl)

     82.35         86.30         81.93   

NGL (Bbl)

     31.03         32.67         35.85   

Mcfe

     5.43         5.32         4.95   

Average unit cost per Mcfe:

        

Production costs:

        

Lease operating expenses

   $ 1.09       $ 0.93       $ 0.93   

Production taxes

     0.41         0.36         0.34   

Total

   $ 1.50       $ 1.29       $ 1.27   

Depreciation, depletion and amortization

     2.48         2.65         2.84   

General and administrative expenses

     0.91         0.62         0.63   

 

(1) Oil is converted to Mcfe using the industry standard conversion rate of one barrel of oil to six thousand cubic feet of natural gas.
(2) Average prices shown in the table reflect prices both before and after the effects of our realized economic commodity hedging transactions. Our calculation of such effects includes realized gains or losses on cash settlements for commodity derivatives.

Our Oil and Natural Gas Properties

We operate our business and properties under two major divisions, which we refer to as our West Division and our East Division. As of December 31, 2014 and as of all applicable dates presented, we did not have any individual

 

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fields containing 15% or more of our total estimated proved reserves. Our historical daily production volumes for each business unit in our West and East divisions are summarized in Part II, Item 7—“Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

West Division

Our West Division is primarily situated in the Rocky Mountains region and encompasses several major basins. Our West Division accounted for approximately 30% of our proved reserves as of December 31, 2014. As of December 31, 2014, we had approximately 656,000 net acres in our West Division, of which 52% was held by production. As of December 31, 2014, we had interests in approximately 1,364 gross (620 net) productive wells in our West Division and operated approximately 51% of these wells and approximately 89% of our net production. Our West Division is divided into four distinct business units, which are primarily focused on the Williston, Powder River, Greater Green River and San Juan basins, respectively.

Williston Business Unit. Our Williston business unit consists of our assets in North Dakota, Montana and South Dakota. As of December 31, 2014, our Williston business unit had approximately 98,000 net acres, including approximately 67,000 net acres in North Dakota, which represents our core operating position in the Williston Basin. We operated approximately 29,000 net acres, or approximately 43% of our core Williston Basin position as of December 31, 2014. As of December 31, 2014, we had approximately 209 gross (81 net) productive wells in the Williston business unit. The Williston Basin produces from numerous hydrocarbon bearing horizons, including the Madison, Bakken, Three Forks and Red River formations. Within our operating area, we primarily produce from the Middle Bakken and Three Forks formations. During 2014, our Williston business unit completed 18 gross (eight net) operated wells.

Powder River Business Unit. Our Powder River business unit primarily includes our properties in the Powder River Basin in Wyoming as well as certain non-core assets in Eastern Colorado. We had approximately 292,000 net acres and approximately 368 gross (128 net) productive wells in the Powder River business unit as of December 31, 2014. Our properties in the Powder River Basin have exposure to various oil producing horizons, including the Parkman, Sussex, Shannon, Niobrara, Frontier and Mowry formations. Within our operating area, we have primarily focused on the Shannon and Sussex formations. Our Powder River business unit completed 25 gross (20 net) operated horizontal wells during 2014.

Greater Green River Business Unit. As of December 31, 2014, we had approximately 211,000 net acres and approximately 458 gross (144 net) productive wells in the Greater Green River business unit, which includes our Greater Green River Basin properties in Wyoming and certain other assets located in Eastern Utah and Western Colorado. Our properties in the Greater Green River business unit include mature, producing assets in the Wamsutter Field as well a position in the Cepo Field, where we have exposure to the liquids-rich Fort Union reservoir. During 2014, our Greater Green River business unit completed five gross (four net) operated wells.

San Juan Business Unit. Our San Juan business unit consists of our assets in Southern Colorado and Northwestern New Mexico in the San Juan Basin as well as non-core properties in Southeastern Utah. We had approximately 55,000 net acres and approximately 329 gross (267 net) productive wells in our San Juan business unit as of December 31, 2014. Our San Juan business unit operates a large, mature production base in the San Juan Basin that produces primarily from the Fruitland coal formation. During 2014, our San Juan business unit completed four gross (four net) operated wells.

East Division

Our East Division primarily consists of our assets in the Mid-Continent and East Texas regions and includes several major basins, including the Anadarko and East Texas basins. Our East Division accounted for approximately 70% of our proved reserves as of December 31, 2014. As of December 31, 2014, we had 811,000 net acres in our East Division, of which 97% was held by production. As of December 31, 2014, we had interests in approximately 5,977 gross (2,663 net) productive wells in our East Division and operated 46% of these wells

 

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and 76% of our net production. Our East Division is divided into three distinct business units, which are primarily focused on the Mid-Continent West, the Mid-Continent East and the East Texas regions, respectively.

Mid-Continent West Business Unit. Our Mid-Continent West business unit includes our assets in the Texas and Oklahoma Panhandles as well as Kansas. As of December 31, 2014, we held approximately 173,000 net acres and approximately 1,375 gross (623 net) productive wells in the Mid-Continent West business unit. Our properties in the Mid-Continent West business unit have exposure to the Cleveland, Granite Wash and Douglas formations. During 2014, our Mid-Continent West business unit completed 13 gross (10 net) operated wells.

Mid-Continent East Business Unit. Our Mid-Continent East business unit includes our assets in the Anadarko Basin in Central and Western Oklahoma (excluding the Oklahoma Panhandle region) as well as our properties in Eastern Oklahoma and Northern Arkansas. As of December 31, 2014, we had approximately 278,000 net acres and approximately 2,637 gross (641 net) productive wells in the Mid-Continent East business unit. There are numerous hydrocarbon bearing formations across our Anadarko Basin properties in the Mid-Continent East business unit, including the Marmaton, Mississippi Solid, Cana Woodford and Tonkawa formations. In March 2015, we divested a substantial portion of our Arkoma Basin assets in Eastern Oklahoma for approximately $48.0 million, subject to customary post-closing purchase price adjustments. During 2014, our Mid-Continent East business unit completed 17 gross (13 net) operated wells.

East Texas Business Unit. Our East Texas business unit had 360,000 net acres and approximately 1,965 gross (1,399 net) productive wells as of December 31, 2014 and is comprised of our properties in East Texas, Northern Louisiana, Southern Arkansas and the Permian Basin. Our East Texas business unit includes significant positions in the Cotton Valley Sand and Haynesville Shale formations. In December 2014, we completed the acquisition of approximately 37,000 net acres in East Texas for approximately $57.6 million, subject to customary post-closing purchase price adjustments, to increase our existing Cotton Valley position in our East Texas business unit. During 2014, our East Texas business unit completed 25 gross (21 net) operated wells.

Other

In addition to the properties described above, we also own interests in certain non-core assets located throughout the continental United States. As of December 31, 2014, we held approximately 101,000 net acres in these non-core areas, and these assets accounted for less than one percent of our total production during the year ended December 31, 2014. We had approximately 13 gross (6 net) productive wells in these non-core areas as of December 31, 2014.

Title to Properties

As is customary in the oil and natural gas industry, we initially conduct a limited review of the title to our properties on which we do not have proved reserves. Prior to the commencement of drilling operations on those properties, however, we conduct a more thorough title examination and perform curative work with respect to material defects. To the extent title opinions or other investigations reflect title defects on those properties, we are typically responsible for curing or resolving such title defects at our expense. We generally will not commence drilling operations on a property until we have cured any material title defects on the property. In addition, prior to completing an acquisition of producing oil and natural gas leases, we generally perform title reviews on the most significant leases, and depending on the materiality of properties, we may obtain an attorney’s title opinion or review previously obtained title opinions. Based on the foregoing, we believe that we have satisfactory title to our producing properties in accordance with standards generally accepted in the oil and natural gas industry. Our oil and natural gas properties are subject to customary royalty and other interests, liens under the credit agreements governing the RBL Revolver and Second Lien Term Loan, liens for current taxes and other burdens which we believe do not materially interfere with the use of, or affect our carrying value of, the properties.

 

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Office Facilities

In addition to our oil and natural gas properties discussed above, we lease corporate office space in Tulsa, Oklahoma, Denver, Colorado and Houston, Texas, and we also maintain a number of field office locations. We believe that our existing office facilities are adequate to meet our needs for the immediate future, and that additional facilities will be available on commercially reasonable terms as needed.

Risk Management

We use derivative financial instruments to provide partial protection against declines in oil, natural gas and natural gas liquids prices by reducing the risk of price volatility and the effect it could have on our operations and our ability to finance our capital budget and operations. Our decision on the quantity and price at which we choose to hedge our production is based on our view of existing and forecasted oil, natural gas and natural gas liquids production volumes, planned drilling projects and current and future market conditions. While there are many different types of derivatives available, we typically use fixed price swaps, collars (put and call options) and occasionally basis swap agreements to attempt to manage price risk more effectively. The swaps call for payments to, or receipts from, counterparties based on whether the market price of oil, natural gas or natural gas liquids for the period is greater or less than the fixed price established for that period when the swap is put in place. The collar arrangements are put and call options used to establish a fixed price floor and a fixed price ceiling for a specified period of time. The purchaser of a put option will collect payment when the market price settles lower than the put exercise prices and the purchaser of a call option will collect payment when the market price settles greater than the call exercise price. For additional information on our derivative financial instruments, see in Part II, Item 7—“Management’s Discussion and Analysis of Financial Condition and Results of Operations” and Note 8 to our audited consolidated financial statements included in Part II, Item 8—“Financial Statements and Supplementary Data” of this report.

Competition

The oil and natural gas industry is intensely competitive, and we compete with other companies that possess and employ financial, technical and personnel resources that are substantially greater than ours. 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. 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. Our competitors 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 personnel resources permit. Such competition can also drive up the costs to acquire oil and natural gas leases, properties and prospects in areas where we are already conducting business and operations.

In addition, because of our significant indebtedness and debt service costs, many of our competitors have a greater ability than us to continue exploration and development activities during periods of low oil and natural gas market prices. The more favorable capital structure of these companies may also give them better access to capital and on better terms, which could give such companies an advantage in the financing and execution of acquisitions and their drilling programs.

There is also competition between oil and natural gas producers and other industries producing energy and fuel. Furthermore, competitive conditions may be substantially affected by various forms of energy legislation and/or regulation considered from time to time by federal, state or local governments. It is not possible to predict the nature of any such legislation or regulation which 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, local and other laws and regulations more easily than we can, which would adversely affect our competitive position.

 

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Marketing and Significant Customers

We market the oil and natural gas production from properties we operate for both our account and the account of many of the other working interest owners in these properties. We sell our production to a variety of purchasers under market-based contracts with terms ranging from one day to eighteen years.

During the year ended December 31, 2014, we had no purchasers that accounted for more than 10% of our total crude oil and natural gas revenues. We do not believe that the loss of any of the customers or entities to which we have exposure would result in a material adverse effect on our ability to market our oil and natural gas production.

Delivery Commitments

A portion of our production is sold under certain contractual arrangements that specify the delivery of a fixed and determinable quantity. As of December 31, 2014, we were committed to deliver the following fixed quantities of production.

 

     Total      Less than
1 Year
     1-3
Years
     3-5
Years
     More than
5 Years
 

Natural Gas (Bcf)

     20.3        20.3        —          —          —    

Oil (MMbbl)

     —          —          —          —          —    

We expect to fulfill our delivery commitments with production from our proved developed reserves and the production of others who market with us. However, should these sources not be sufficient to satisfy our delivery commitments, we can and may use spot market purchases to fulfill these commitments.

In addition, we have entered into marketing agreements with various midstream service providers and pipeline carriers to facilitate the delivery of our production to market. Certain of these agreements include firm transportation or throughput commitments. Firm transportation commitments require us to pay reservation charges for specified quantities regardless of the amount of pipeline capacity used, and throughput commitments require us to deliver specified volumes or pay certain fees for any shortfalls. For additional information on our obligations under such arrangements, see Part II, Item 7—“Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Contractual Obligations.”

Seasonality of Business

Weather conditions affect the demand for, and prices of, natural gas and can also delay drilling and production activities, disrupting our overall business plans. Due to these seasonal fluctuations, results of operations for individual quarterly periods may not be indicative of the results that may be realized on an annual basis.

In addition, current lease terms, permit conditions and stipulations and other governmental regulatory conditions restrict drilling operations and certain other activities during certain times of the year on a significant portion of our properties in the Greater Green River and Powder River basins due to wildlife activity and/or habitat. We have worked with federal and state officials in Wyoming to obtain approval for limited winter-drilling activities on these assets and have developed measures, such as drilling multiple wells from a single pad location, to minimize the impact of our activities on wildlife and wildlife habitat.

Governmental Regulation

Regulation of Production of Oil and Natural Gas

Our operations are substantially affected by federal, state, tribal, local and other laws, regulations and agency actions and rule making. In particular, natural gas production and related operations are, or have been,

 

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subject to price controls, taxes and numerous other laws, regulations and agency actions. All of the jurisdictions in which we own or operate producing oil and natural gas properties have statutory provisions regulating the exploration for and production of oil and natural gas, including provisions related to permits for the drilling of wells, drilling or operating bonds, reports concerning operations, the location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled, sourcing and disposal of water used in the drilling and completion process and the plugging and abandonment of wells. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of oil and natural gas within its jurisdiction.

Our operations are also subject to various oil and natural gas conservation laws and regulations. These include the regulation of the size of drilling and spacing units or proration units, the number of wells which may be drilled in an area, the unitization or pooling of oil or natural gas properties and prohibitions or limits on the venting or flaring of natural gas. In addition, these regulations may establish maximum rates of production from oil and natural gas wells and impose certain requirements regarding the ratability or fair apportionment of production from fields and individual wells. The effect of these regulations is to limit the amount of oil and natural gas that we can produce from our wells and to limit the number of wells, the vertical deviation of such wells or the locations at which we can drill, although we can apply for exceptions to such regulations or to have reductions or expansions in well spacing. Furthermore, some states have become concerned that the disposal of produced water could under certain circumstances contribute to seismicity, and therefore, they have adopted or are considering adopting additional regulations governing such disposal.

Failure to comply with applicable laws and regulations can result in substantial penalties. The regulatory burden on the industry increases the cost of doing business and affects profitability. In addition, such laws and regulations are frequently amended or reinterpreted and, as a result, we are unable to predict the future costs or impact of compliance. Additional proposals and proceedings that affect the oil and natural gas industry are regularly considered by federal, state and local governments, courts and agencies. We cannot predict when or whether any such proposals may become effective.

We believe we are in material compliance with currently applicable laws and regulations and that continued material compliance with existing requirements will not have a material adverse effect on our financial position, cash flows or results of operations. However, current regulatory requirements may change, currently unforeseen environmental incidents may occur or past non-compliance with environmental laws or regulations may be discovered.

Regulation of Transportation and Sales of Natural Gas

Historically, the transportation and sale for resale of natural gas in interstate commerce have been regulated by agencies of the U.S. federal government, primarily the Federal Energy Regulatory Commission (“FERC”). FERC regulates interstate natural gas transportation rates and service conditions, which affects the marketing of natural gas that we produce, as well as the revenues we receive for sales of our natural gas. Since 1985, FERC has endeavored to make natural gas transportation more accessible to natural gas buyers and sellers on an open and non-discriminatory basis. FERC has stated that open access policies are necessary to improve the competitive structure of the interstate natural gas pipeline industry and to create a regulatory framework that will put natural gas sellers into more direct contractual relations with natural gas buyers by, among other things, unbundling the sale of natural gas from the sale of transportation and storage services.

In the past, the federal government regulated the prices at which natural gas could be sold. While sales by producers of natural gas can currently be made at competitive market prices, Congress could reenact price controls in the future. Deregulation of wellhead natural gas sales began with the enactment of the Natural Gas Policy Act (“NGPA”) and culminated in adoption of the Natural Gas Wellhead Decontrol Act which removed controls affecting wellhead sales of natural gas effective January 1, 1993. The transportation and sale for resale of natural gas in interstate commerce is regulated primarily under the Natural Gas Act of 1938 (the “NGA”) and by regulations and orders promulgated under the NGA by FERC. In certain limited circumstances, intrastate

 

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transportation and wholesale sales of natural gas may also be affected directly or indirectly by laws enacted by Congress and by FERC regulations.

Beginning in 1992, FERC issued a series of orders to implement its open access policies. As a result, the interstate pipelines’ traditional role as wholesalers of natural gas has been eliminated and replaced by a structure under which pipelines provide transportation and storage service on an open access basis to others who buy and sell natural gas. Although FERC’s orders do not directly regulate natural gas producers, they are intended to foster increased competition within all phases of the natural gas industry.

The Energy Policy Act of 2005 (“EP Act 2005”) is a comprehensive compilation of tax incentives, authorized appropriations for grants and guaranteed loans, and significant changes to the statutory policy that affects all segments of the energy industry. Among other matters, EP Act 2005 amends the NGA to add an anti-market manipulation provision which makes it unlawful for any entity to engage in prohibited behavior to be prescribed by FERC, and furthermore provides FERC with additional civil penalty authority. The EP Act 2005 provides FERC with the power to assess civil penalties of up to $1.0 million per day for violations of the NGA and increases FERC’s civil penalty authority under the NGPA from $5,000 per violation per day to $1.0 million per violation per day. The civil penalty provisions are applicable to entities that engage in the sale of natural gas for resale in interstate commerce. On January 19, 2006, FERC issued Order No. 670, a rule implementing the anti-market manipulation provision of EP Act 2005, and subsequently denied rehearing. The rules make it unlawful to: (1) in connection with the purchase or sale of natural gas subject to the jurisdiction of FERC, or the purchase or sale of transportation services subject to the jurisdiction of FERC, for any entity, directly or indirectly, to use or employ any device, scheme or artifice to defraud; (2) to make any untrue statement of material fact or omit to make any such statement necessary to make the statements made not misleading or (3) to engage in any act or practice that operates as a fraud or deceit upon any person. The new anti-market manipulation rule does not apply to activities that relate only to intrastate or other non-jurisdictional sales or gathering, but does apply to activities of gas pipelines and storage companies that provide interstate services, as well as otherwise non-jurisdictional entities to the extent the activities are conducted “in connection with” gas sales, purchases or transportation subject to FERC jurisdiction, which now includes the annual reporting requirements under Order 704. The anti-market manipulation rule and enhanced civil penalty authority reflect an expansion of FERC’s NGA enforcement authority.

On December 26, 2007, FERC issued Order 704, a final rule on the annual natural gas transaction reporting requirements, as amended by subsequent orders on rehearing. Under Order 704, wholesale buyers and sellers of more than 2.2 million MMBtus of physical natural gas in the previous calendar year, including natural gas gatherers and marketers, are now required to report, on May 1 or such other time as directed by FERC each year, aggregate volumes of natural gas purchased or sold at wholesale in the prior calendar year to the extent such transactions utilize, contribute to, or may contribute to the formation of price indices. It is the responsibility of the reporting entity to determine which individual transactions should be reported based on the guidance of Order 704. Order 704 also requires market participants to indicate whether they report prices to any index publishers, and if so, whether their reporting complies with FERC’s policy statement on price reporting.

On November 20, 2008, FERC issued Order 720, a final rule on the daily scheduled flow and capacity posting requirements. Under Order 720, major non-interstate pipelines, defined as certain non-interstate pipelines delivering, on an annual basis, more than an average of 50 million MMBtus of gas over the previous three calendar years, are required to post daily certain information regarding the pipelines’ capacity and scheduled flows for each receipt and delivery point that has a design capacity equal to or greater than 15,000 MMBtu per day and may also require posting or reporting of rates associated with services on those pipelines. Requests for clarification and rehearing of Order 720 have been filed at FERC and a decision on those requests is pending.

We cannot accurately predict whether FERC’s actions will achieve the goal of increasing competition in markets in which our natural gas is sold. Additional proposals and proceedings that might affect the natural gas industry are pending before FERC and the courts. The natural gas industry historically has been very heavily regulated. Therefore, we cannot provide any assurance that the less stringent regulatory approach recently

 

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established by FERC will continue. However, we currently have no reason to believe that any action taken will affect us in a way that materially differs from the way it affects other natural gas producers.

Gathering service, which occurs upstream of jurisdictional transmission services, is regulated by the states onshore and in state waters. Although its policy is still in flux, FERC has reclassified certain jurisdictional transmission facilities as non-jurisdictional gathering facilities, which has the tendency to increase our costs of getting gas to point of sale locations. State regulation of natural gas gathering facilities generally include various safety, environmental and, in some circumstances, nondiscriminatory-take requirements. Although such regulation has not generally been affirmatively applied by state agencies, natural gas gathering may receive greater regulatory scrutiny in the future.

Section 1(b) of the NGA exempts natural gas gathering facilities from regulation by FERC as a natural gas company under the NGA. We believe that the natural gas pipelines in our gathering systems meet the traditional tests FERC has used to establish a pipeline’s status as a gatherer not subject to regulation as a natural gas company. However, the distinction between FERC-regulated transmission services and federally unregulated gathering services is the subject of on-going litigation, so the classification or reclassification and regulation of our gathering facilities are subject to change based on future determinations by FERC, the courts or the U.S. Congress.

Our sales of natural gas are also subject to requirements under the Commodity Exchange Act (“CEA”) and regulations promulgated thereunder by the Commodity Futures Trading Commission (“CFTC”). The CEA prohibits any person from manipulating or attempting to manipulate the price of any commodity in interstate commerce or futures on such commodity. The CEA also prohibits knowingly delivering or causing to be delivered false or misleading or knowingly inaccurate reports concerning market information or conditions that affect or tend to affect the price of a commodity.

Intrastate natural gas transportation is also subject to regulation by state regulatory agencies. The basis for intrastate regulation of natural gas transportation and the degree of state regulatory oversight and scrutiny given to intrastate natural gas pipeline rates and services varies from state to state. Insofar as such regulation within a particular state will generally affect all intrastate natural gas shippers within the state on a comparable basis, we believe that the regulation of similarly situated intrastate natural gas transportation in any states in which we operate and ship natural gas on an intrastate basis should not affect our operations in any way that is of material difference from those of our competitors. Like the regulation of interstate transportation rates, the regulation of intrastate transportation rates affects the marketing of natural gas that we produce, as well as the revenues we receive for sales of our natural gas.

Changes in law and to FERC policies and regulations may adversely affect the availability and reliability of firm and/or interruptible transportation service on interstate pipelines and certain interstate pipelines, and we cannot predict what future action FERC will take, if any. We currently have no reason to believe, however, that any regulatory changes will affect us in a way that materially differs from the way they will affect other natural gas producers, gatherers and marketers with which we compete.

Environmental Matters

Our operations are subject to extensive and increasingly stringent federal, state and local laws, as well as agency actions and rule making, pertaining to the protection of the environment and human health and safety. These include requirements governing the release, emission or discharge of materials into the environment, the generation, storage, transportation, handling and disposal of materials (including solid and hazardous wastes), or otherwise relating to pollution or protection of the environment, natural resources, or human health and safety. Wellbore integrity regulations have also been enacted and are being considered by a number of regulatory bodies. Numerous governmental agencies, such as the U.S. Environmental Protection Agency (“EPA”) and state environmental regulatory authorities, have the authority to prescribe and implement environmental, health and

 

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safety regulations governing various aspects of oil and natural gas production. We must take into account the timing and cost of complying with, and in many cases applying for permits under, such laws and regulations in planning, designing, constructing, drilling, operating and abandoning wells and related surface facilities, including gathering, transportation, and waste treatment, storage and disposal facilities. If we fail to comply with these laws and regulations, we could be assessed administrative, civil and criminal penalties, as well as be issued injunctions requiring remediation or limiting or prohibiting our activities.

Environmental regulatory programs typically regulate the handling and disposal of drilling and production materials and wastes, human health and safety practices, and the protection of land, water, air and various wildlife, including threatened and endangered species. We may be required to obtain permits for, among other things, air emissions, the construction and operation of surface pits to contain drilling muds and other wastes resulting from drilling and production activities, the construction and operation of underground injection wells to use for disposal of produced water and other oilfield wastes, and the construction of facilities on Indian lands or in environmentally sensitive areas such as wetlands and wilderness areas. Many factors, including public perception, government policy and agency funding can materially impact the ability to secure environmental construction or operations permits.

We have made and will continue to make expenditures to comply with environmental, health and safety laws and regulations. These are necessary business costs in the oil and natural gas industry. We believe that we are in material compliance with currently applicable environmental, health and safety laws and regulations and that the cost of maintaining material compliance with these existing regulations will not have a material adverse effect on our business, financial position and results of operations. It is possible that developments, such as the imposition of stricter and more comprehensive environmental, health and safety laws and regulations or changes in the way existing requirements are interpreted or enforced, as well as the discovery of past non-compliance with environmental laws and regulations, the occurrence of currently unforeseen environmental incidents or receipt of claims for damages to property or persons resulting from company operations, could result in substantial costs and liabilities, including civil and criminal penalties and remediation costs, and could adversely affect our ability to continue our business as presently conducted.

Solid and Hazardous Waste

Federal, state and local laws may require us to remove or remediate disposed wastes, including wastes disposed of or released by us or prior owners or operators in accordance with laws or otherwise, to suspend or cease operations at contaminated areas, or to perform remedial well plugging operations or response actions to reduce the risk of future contamination or threats to public health or the environment. Federal laws, including the Comprehensive Environmental Response, Compensation, and Liability Act, referred to as “CERCLA” or the Superfund law, and comparable state laws may impose strict, and in certain cases joint and several, liability, without regard to fault, on specified potentially responsible parties, including current or prior owners or operators of contaminated sites or parties that arranged for the disposal of hazardous substances at contaminated sites, for the costs of investigating and cleaning up hazardous substances, as well as liability for damages to natural resources. Other federal and state laws, in particular the federal Resource Conservation and Recovery Act (“RCRA”), regulate hazardous and non-hazardous wastes. Under a longstanding legal framework, certain wastes generated by our oil and natural gas operations are not currently subject to RCRA regulations governing hazardous wastes, though they are generally subject to RCRA regulations governing non-hazardous wastes and may be regulated under other federal laws. Many states also have specific regulations governing wastes generated by oil and natural gas operations. These wastes may in the future be designated as hazardous wastes under RCRA or may otherwise become subject to more rigorous and costly compliance and disposal requirements.

From time to time, releases of materials or wastes have occurred at locations we own or at which we have operations. In some cases we have acquired properties or businesses with a history of on-site contamination. In addition, some of our owned and leased properties have been used for oil and natural gas exploration, production and related activities for a number of years, often by third parties not under our control. We and/or other owners

 

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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. Under applicable federal, state and local laws, we have been and continue to be required to address contamination at a number of locations and, to the extent new spills or releases occur or previously unknown contamination is discovered, we may be required to do so again in the future. We are currently addressing contamination at several locations, in some instances in consultation with regulatory authorities and also have received “potentially responsible party” notices alleging potential liability for cleanup of a certain off-site waste disposal site which has been primarily covered by a site specific insurance policy. While we do not anticipate at this time that these matters or any other contamination or remediation matters are likely to have a material adverse effect on our business, financial position or results of operations, we cannot predict with certainty whether the occurrence of new spills or releases, or the discovery of previously unknown contamination, might result in significant future liabilities.

In addition, we have been subject to lawsuits brought by third parties alleging damages as a result of our operations, and such suits are currently pending against us regarding several locations. While we do not anticipate at this time that resolution of any of these lawsuits is likely to have a material adverse effect on our business, financial position or results of operations, we cannot predict with certainty how liabilities will be allocated in pending matters, or whether new claims may be made against us as a result of the occurrence of new spills or releases, or the discovery of previously unknown contamination.

Groundwater Protection

It is customary in the oil and natural gas industry to manage, store and dispose of produced water and drilling wastes in pits and underground injection wells, and to use enhanced recovery techniques in unconventional and tight oil and natural gas formations, and we or our operators or contractors use these techniques at some of our locations. Should such techniques result in groundwater contamination, we could be subject to fines, penalties and remediation costs under federal laws, including the Safe Drinking Water Act (“SDWA”), and state laws. In addition, landowners and other parties may file claims for personal injury, property and natural resource damages and the cost of providing alternative water supplies.

Most of our recent drilling operations have been in tight and unconventional oil and natural gas formations, which are drilled using hydraulic fracturing. Hydraulic fracturing involves the injection of water, sand and chemicals under pressure into rock formations to stimulate oil and natural gas production. Sponsors of bills proposed in the U.S. Congress have asserted that chemicals used in the fracturing process may be adversely impacting drinking water supplies. Proposed federal legislation would amend the federal SDWA to repeal the general exemption for hydraulic fracturing from the SDWA, thus requiring the permitting of each and every hydraulic fracturing project, and require the disclosure of chemicals used in the hydraulic fracturing process. This could 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 are impairing groundwater or causing other damage. Such bills, if adopted, could establish an additional level of regulation at the federal or state level that could lead to operational delays or increased operating costs and could result in additional regulatory burdens that could make it more difficult to perform hydraulic fracturing and increase our costs of compliance and doing business.

There have been several recent federal initiatives related to hydraulic fracturing. In April 2012, the White House issued an executive order creating a multi-agency task force to coordinate federal oversight of hydraulic fracturing. In February 2014, EPA issued an interpretive memorandum to clarify underground injection control (“UIC”) requirements under the SDWA for use of diesel fuels in hydraulic fracturing, and a technical guidance containing recommendations for EPA permit writers to consider in implementing these UIC requirements. These documents clarified that any owner or operator who injects diesel fuels in hydraulic fracturing for oil or gas extraction must obtain a UIC permit before injection. EPA has also announced plans to propose effluent limitations for the treatment and discharge of wastewater resulting from hydraulic fracturing activities in 2015. In

 

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addition, the federal Bureau of Land Management proposed and is in the process of reconsidering regulations requiring disclosure of chemicals used in the hydraulic fracturing process both before and after any drilling on federal public land.

Other EPA initiatives have focused on studies related to hydraulic fracturing’s potential impact on drinking water. At the request of the U.S. Congress, EPA is undertaking a national study to understand the potential impact of hydraulic fracturing on drinking water resources. The study has included a review of published literature, analysis of existing data, scenario evaluation and modeling, laboratory studies, and case studies. EPA issued a progress report in December 2012 detailing the steps being undertaken in the study, and expects to release a final draft report for peer review and comment in 2015. In December 2011, EPA published a draft report finding that hydraulic fracturing is a likely cause of drinking water contamination in the vicinity of Pavillion, Wyoming; however, in September 2013, EPA announced that it does not plan to finalize or seek peer review of the report, and that it will continue to support the State of Wyoming in the State’s investigation of the groundwater contamination. EPA’s testing results were confirmed by a second round of well tests in October 2012; however, the conclusions to be drawn from the testing results remain controversial and the findings relate only to wellbore integrity for the specific shallow gas wells that were a part of the State’s investigation. Findings such as this could increase public pressure on governmental authorities to implement new regulations regarding hydraulic fracturing.

Many states and cities have adopted, or are considering, regulations regarding hydraulic fracturing, including requiring the disclosure of chemicals injected during hydraulic fracturing. Vermont banned hydraulic fracturing in the state in 2012 and certain states such as New York and New Jersey issued moratoriums on hydraulic fracturing while they considered studies of and regulations regarding hydraulic fracturing, although New York announced in December 2014 that it will move to ban hydraulic fracturing in the state in 2015 and New Jersey’s moratorium expired in 2013. In some areas hydraulic fracturing has also been the subject of local ordinances attempting to ban or limit the practice; court challenges to such ordinances have had varied outcomes to date. If new state or local laws or regulations are adopted that significantly increase the risk of legal challenges to, or restrict the use of, hydraulic fracturing, such legal requirements could make it more difficult or costly for us to perform fracturing and increase our costs of compliance and doing business.

We voluntarily participate in FracFocus, a national publicly accessible Internet-based registry developed by the Ground Water Protection Council and the Interstate Oil and Gas Compact Commission. This registry, located at www.fracfocus.org, provides our industry with an avenue to voluntarily disclose additives used in the hydraulic fracturing process. The information included on or accessible through this website is not incorporated by reference in this report.

Based on increased regulation and attention given to the hydraulic fracturing process from federal, state and various local governments and increased public scrutiny, greater opposition and litigation toward oil and natural gas production utilizing hydraulic fracturing techniques is anticipated. Additional legislation or regulation could lead to operational delays, increased operating costs or a decrease in completion of new oil and natural gas wells all of which could adversely affect our financial position, operations and cash flows.

Air Emissions

Our operations produce air emissions through the use of equipment such as compressor engines, condensate and produced water tanks, dehydrators, and heater treaters, and the production of fugitive and loading emissions and flares. The federal Clean Air Act and comparable state laws regulate emissions of various air pollutants through requirements such as New Source Performance Standards (“NSPS”) and National Emissions Standards for Hazardous Air Pollutants (“NESHAP”). We, and/or contractors that we employ, are required to obtain federal or state air permits prior to operating certain equipment, and must comply with limits on the emissions of certain pollutants. If we fail to comply with such requirements, we may be subject to administrative, civil and criminal penalties. On April 17, 2012, EPA issued a final rule setting forth new NSPS and NESHAP standards for the oil

 

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and natural gas sector. The new rule will be fully implemented in 2015. We are continuing to evaluate the effect of this rule on our business, but we do not expect these requirements to materially adversely affect our business, financial condition or results of operations. Because of the subjectivity in the assumptions underlying our estimated compliance costs with respect to this rule, however, the costs to ultimately comply with the rule may vary significantly from our estimates, which could materially adversely affect our business, financial condition and results of operations.

Climate Change and Greenhouse Gas Regulation

Global climate change continues to attract considerable public, scientific and regulatory attention, and greenhouse gas (“GHG”) emission regulation is becoming more stringent. EPA has taken a number of steps towards regulating GHG emissions under the Clean Air Act, including its Mandatory Reporting of Greenhouse Gases Rule published in October 2009, and expanded in November 2010 to include onshore oil and natural gas production activities, its “endangerment” and “cause or contribute” findings under Section 202(a) of the Clean Air Act published in December 2009, and its so-called “Tailoring Rule” concerning regulation of large emitters of GHGs under the Clean Air Act’s Prevention of Significant Deterioration (“PSD”) Program and Title V program issued in May 2010, which has been subject to litigation. These and future EPA rulemakings regarding GHG emissions could adversely affect our operations and restrict or delay our ability to obtain air permits for new or modified facilities.

Under the Mandatory Reporting of Greenhouse Gases Rule, we are currently required to report annual GHG emissions from some of our operations. For reporting year 2010, we were required to report emissions from general combustion sources with GHG emissions greater than 25,000 metric tons CO2 equivalent, and only three of our large compressor stations triggered this requirement. For reporting year 2011 and thereafter, we became subject to additional GHG reporting requirements applicable to the oil and natural gas sector, which require estimation of routine and episodic releases of GHGs (primarily methane) from a wide range of equipment such as gas-driven pneumatic equipment, well venting for work overs and completions, storage tanks, dehydrators and compressors (including fugitive leaks from valves, flanges, etc.) across our entire system. These reporting requirements are being phased in over a number of years and, although we cannot determine with accuracy what our additional costs will be to implement the new requirements, we do not expect these new requirements to materially adversely affect our business, financial condition or results of operations.

Additional GHG emission-related requirements that are in various stages of development may also affect our operations. In response to the U.S. President’s June 2013 Climate Action Plan, EPA issued a Clean Power Plan designed to cut GHG emissions from existing fossil-fuel fired power plants in June 2014, proposed standards for modified and reconstructed fossil-fuel fired power plants in June 2014, and issued a revised proposal with standards for new fossil fuel-fired plants in September 2013. In March 2014, the Obama administration announced a strategy to reduce methane emissions, which was followed by the administration’s January 2015 announcement of a goal to cut methane emissions from the oil and gas sector by 40-45 percent from 2012 levels by 2025. EPA expects to issue a proposed rule in the summer of 2015 and final rule in 2016 to reduce methane emissions. In addition to EPA initiatives, the U.S. Congress has considered legislation that would establish a nationwide cap-and-trade system for GHGs. In addition, a number of states have begun taking action on their own or as part of a multi-state program to control and/or reduce GHG emissions. If enacted, such laws and regulations could require us to modify existing, or obtain new, permits, implement additional pollution control technology, curtail operations or increase significantly our operating costs.

A number of states have begun taking action on their own or as part of a multi-state program to control and/or reduce GHG emissions. For example, California enacted the Global Warming Solutions Act of 2006 (AB 32), which led to the adoption of GHG reporting requirements in 2008 and implementation of a broad-based GHG cap-and-trade program beginning in 2013 (the program will expand in 2015). In addition, nine Northeastern and Middle Atlantic states participating in the Regional Greenhouse Gas Initiative have capped GHG emissions for fossil-fuel powered electrical generation units with a capacity of 25 or more megawatts beginning in 2014, with the cap declining annually between 2015 and 2020.

 

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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 materially adversely affect our business, reputation, operating performance and product demand. 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, and droughts, our own or our customers’ operations may be disrupted, which could result in a decrease in our available product or reduce our customers’ demand for products.

Threatened and Endangered Species

Our operations may affect wildlife, including threatened and endangered species. Current lease terms, permit conditions and stipulations and other governmental regulatory conditions restrict drilling operations and certain other activities during certain times of the year on a significant portion of our properties in the Greater Green River and Powder River basins due to wildlife activity and/or habitat. In addition, the U.S. Fish and Wildlife Service recently announced its decision to list the lesser prairie chicken as “threatened” under the U.S. Endangered Species Act. The lesser prairie chicken’s habitat overlaps certain of our properties in Western Oklahoma and the Texas Panhandle. We elected to participate in a related U.S. Fish and Wildlife endorsed conservation plan for the lessor prairie chicken that could restrict our operations and result in additional costs with respect to the affected areas. Under a 2011 settlement, the U.S. Fish and Wildlife Service is required to make a determination on the listing of more than 250 species as endangered or threatened over the next several years. The presence of other wildlife, wildlife habitats or plants, including species that are or will be protected under the U.S. Endangered Species Act, could result in additional restrictions on our ability to access and/or operate these and other properties, including with respect to our other core positions, which could materially adversely affect our business, results of operations and financial condition.

Related Insurance

We maintain insurance against claims arising from releases or contamination associated with our exploration and production activities. This insurance includes general liability, environmental, umbrella, and site specific policies. However, this insurance is generally limited to activities that occur on or result from a covered location, such as wellsites and certain key facilities, and there can be no assurance that this insurance will continue to be commercially available or that this insurance will be available at premium levels that justify its purchase by us. The occurrence of a significant event or discovery of conditions that are not fully insured or indemnified against could have a materially adverse effect on our financial condition and operations.

Employees

As of December 31, 2014, we had 997 employees. We hire independent contractors on an as needed basis. We have no collective bargaining agreements with our employees.

In March 2015, we announced a workforce reduction of approximately 30% of our employees.

Address, Internet Website and Availability of Public Filings

Our principal executive offices are located at Samson Plaza, Two West Second Street, Tulsa, Oklahoma 74114, and our telephone number is (918) 591-1791. Our website is located at www.samson.com. Our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and any amendments to those reports filed or furnished pursuant to the Exchange Act are made available through our website as soon as reasonably practical after we electronically file or furnish the reports to the SEC. Information on or accessible through our website does not constitute part of this report and is not incorporated into it.

 

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ITEM 1A. RISK FACTORS

You should carefully consider the risk factors set forth below. Any of the following risks may materially adversely affect our business, results of operations and financial condition. The risks and uncertainties described below are not the only risks and uncertainties that we face. Additional risks and uncertainties not presently known to us or that we currently deem immaterial may also materially adversely affect our business, results of operations and financial condition. In such a case, you may lose all or part of your original investment. The risks discussed below also include forward-looking statements, and our actual results may differ substantially from those discussed in these forward-looking statements. See “Cautionary Statement Regarding Forward-Looking Statements” in this report.

Our substantial indebtedness and the fact that a significant portion of our cash flow is used to make interest payments could adversely affect our ability to raise additional capital to fund our operations, increase our vulnerability to changes in the economy or our industry, including commodity price volatility, and prevent us from making debt service payments.

We are a highly leveraged company with significant debt service costs. As of December 31, 2014, we had total indebtedness of $3.9 billion (excluding the Cumulative Preferred Stock). Our substantial indebtedness and debt service costs could:

 

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

 

    limit our ability to obtain additional financing to fund future working capital, capital expenditures for both operated and outside operated properties, acquisitions, development activities or other general corporate requirements;

 

    require a substantial portion of our cash flows to be dedicated to debt service payments instead of other purposes, thereby reducing the amount of cash flows available for working capital, capital expenditures, investments or acquisitions and other general corporate purposes;

 

    increase our vulnerability to adverse changes in general economic, industry and competitive conditions, including decreased commodity prices or increased interest rates;

 

    reduce our ability to borrow additional funds if we do not replace our reserves since the collateral value of our assets is based, in part, on the value of our proved reserves; and

 

    limit our flexibility in planning for, or reacting to, changes in our business or industry in which we operate, placing us at a competitive disadvantage compared to our competitors who are less highly leveraged and who therefore may be able to take advantage of opportunities that our leverage prevents us from, including exploring for, acquiring and developing oil and natural gas properties.

Any of the foregoing could materially adversely affect our business, results of operations, financial condition, access to capital and ability to satisfy our outstanding debt obligations.

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

We may be unable to generate sufficient cash flow from operations or to obtain alternative sources of financing in an amount sufficient to fund our liquidity needs. Our operating cash inflows are typically used for capital expenditures, operating expenses, debt service costs and working capital needs. Since the Acquisition, the amount of these obligations have exceeded our operating cash flows, thereby requiring us to rely on debt financing and asset sales to fund any shortfalls.

 

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We do not expect our cash flow from operations to be sufficient to repay our indebtedness in the long term, and we expect to ultimately seek a restructuring, amendment or refinancing of our debt. We cannot predict at this time whether we will be able to secure any such transaction, even if market conditions and our financial condition improve between now and then. Even if such transactions were available to us, we may not find them suitable or at comparable interest rates to the indebtedness being refinanced or restructured and they may require us to comply with more onerous covenants, which could further restrict our operations. In addition, the terms of existing or future debt agreements may restrict us from securing such a transaction on terms that are available to us at that time. We also may be required to dispose of material assets to meet our debt service and other obligations. We may not be able to consummate such dispositions on commercially favorable terms or at all, and any disposition of assets could negatively impact our future performance by reducing our production and reserves. Furthermore, any proceeds that we could realize from any such dispositions may not be adequate to meet our debt service obligations then due. We could also be required to reorganize the Company in its entirety. Neither the Principal Stockholders nor any of their respective affiliates has any continuing obligation to provide us with debt or equity financing.

Moreover, our business requires substantial capital expenditures to explore for and develop oil and natural gas properties. As a result of our high-level of indebtedness and the recent volatility in commodity prices, we have ceased drilling activities and have significantly reduced our planned capital spending on drilling and completion activities in 2015 as compared to prior years. This reduction in capital expenditures will curtail the development of our properties, which in turn will lead to a decline in our production and reserves. A decline in our production and reserves may further reduce our liquidity and ability to satisfy our debt obligations by negatively impacting our cash flow from operations and the value of our assets.

We have substantial debt service obligations over the next several months. In addition to monthly interest payments associated with borrowings outstanding under our RBL Revolver, we are required to pay approximately $110.0 million in interest on our Senior Notes on each February 15 and August 15 and approximately $12.5 million in interest on our Second Lien Term Loan at the end of each fiscal quarter. We will continue to evaluate whether to make such payments in light of our liquidity constraints and ongoing negotiations regarding various strategic initiatives. Any failure to make future interest payments on our Senior Notes or to cure a default within the applicable 30-day grace period may result in an “Event of Default” under the indenture governing the Senior Notes, which would entitle holders of at least 30% of the aggregate principal amount outstanding to immediately accelerate the Senior Notes and declare all outstanding principal and interest to be due and payable. If we cannot make payments on our other indebtedness, the lenders under the RBL Revolver could terminate their commitments to loan money, our secured lenders (including the lenders under the RBL Revolver and the Second Lien Term Loan) could foreclose against the assets securing their borrowings and we could be forced into bankruptcy or liquidation. As a result, if we are unable to service our debt obligations generally, and if we are unable to successfully refinance our debt obligations or effect a similar alternative transaction, we cannot assure you that the Company will continue in its current state or that your investment in the Company will retain any value.

Despite our level of indebtedness, we may still be able to incur substantially more indebtedness. This could further exacerbate the risks to our financial condition described above and prevent us from fulfilling our debt obligations.

We may be able to incur significant additional indebtedness in the future. Our debt agreements contain restrictions on the incurrence of additional indebtedness, which are subject to a number of qualifications and exceptions, and the additional indebtedness incurred in compliance with these restrictions could be substantial. Any increase in our level of indebtedness could further exacerbate the risks to our financial condition described above, including by increasing the cash requirement needed to support additional debt service costs attributable to any new debt.

 

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Due to reduced commodity prices and lower operating cash flows, coupled with substantial interest payments, there is substantial doubt about our ability to maintain adequate liquidity through 2015.

During the second half of 2014, NYMEX-WTI oil prices fell from in excess of $100 per Bbl to below $50 per Bbl, the lowest price since 2009. Our operating cash flows for 2014 declined by $201.1 million to $487.6 million, as compared to the cash flows for 2013. We have experienced continued weakness in product pricing in the first quarter of 2015. These events have caused a reduction in our available liquidity and we may not have the ability to generate sufficient cash flows from operations and, therefore, sufficient liquidity to meet our anticipated working capital, debt service and other liquidity needs. We are currently evaluating strategic alternatives to address our liquidity issues and high debt levels. These efforts include, among others, a focus on long-term recurring cost reductions and the identification of non-core assets for potential sale. We cannot assure you that any of these efforts will be successful or will result in cost reductions or additional cash flows or the timing of any such cost reductions or additional cash flows. We are currently reviewing our alternatives and may adopt other strategies that may include actions such as a refinancing or restructuring of our indebtedness or capital structure, reducing or delaying capital investments or seeking to raise additional capital through debt or equity financing. We cannot assure you that any refinancing or debt or equity restructuring would be possible or that additional equity or debt financing could be obtained on acceptable terms, if at all. Furthermore, we cannot assure you that any of our strategies will yield sufficient funds to meet our working capital or other liquidity needs, including for payments of interest and principal on our debt in the future, and any such alternative measures may be unsuccessful or may not permit us to meet scheduled debt service obligations, which could cause us to default on our obligations.

Due to uncertainty about our liquidity and our ability to comply with all of our restrictive covenants contained in our agreements governing our various credit facilities, there is substantial doubt about our ability to continue as a going concern for the next twelve months.

Absent completion of certain actions that are not solely within our control, we do not expect our forecasted cash and credit availability to be sufficient to meet our commitments as they come due over the next twelve months nor do we expect to remain in compliance with all of the restrictive covenants contained in our credit agreements throughout 2015 unless those requirements are amended further. As a result, there is substantial doubt we can continue as a going concern. The accompanying financial statements do not include any adjustments related to the recoverability and classification of recorded assets or the amounts and classification of liabilities that might result from the uncertainty associated with our ability to meet our obligations as they come due. In order to continue as a going concern, we will need to (i) sell additional assets, (ii) restructure our debt, (iii) minimize our capital expenditures, (iv) obtain waivers or amendments from our lenders, (v) effectively manage our expenses and working capital and/or (vi) improve our cash flows from operations. Completion of the foregoing actions is not solely within our control and we may be unable to successfully complete one or all of these actions. Our consolidated financial statements have been prepared on the basis of a going concern, which contemplates continuity of operations, the realization of assets and the satisfaction of liabilities in the normal course of business. If we become unable to continue as a going concern, we will need to liquidate our assets and we might receive significantly less than the values at which they are carried in our consolidated financial statements. See Note 1, (“Industry conditions, liquidity, management’s plans, and going concern”) to our consolidated financial statements included in Part II, Item 8—“Financial Statements and Supplementary Data” of this report.

Oil and natural gas prices are volatile. Low oil or natural gas prices could materially adversely affect our business, results of operations and financial condition.

Our revenues, profitability and the value of our properties substantially depend on prevailing oil and natural gas prices. Oil and natural gas are commodities and, therefore, their prices are subject to wide fluctuations in response to changes in supply and demand. Oil and natural gas prices historically have been volatile, and are likely to continue to be volatile in the future, especially given current economic and geopolitical conditions. During the second half of 2014, prompt month NYMEX-WTI oil prices fell from in excess of $100 per Bbl to the

 

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mid $50s, the lowest price since 2009 when prices briefly fell below $35 per Bbl. Thus far in 2015, commodity prices have continued to be depressed, with prompt month NYMEX natural gas prices ranging from approximately $2.60 per MMbtu to $3.20 per MMbtu and prompt month NYMEX-WTI oil prices ranging from approximately $44 per Bbl to $53 per Bbl through March 16, 2015. We expect such volatility to continue in the future. The prices for oil and natural gas are subject to a variety of factors beyond our control, such as:

 

    domestic and global economic conditions impacting the supply and demand of oil and natural gas;

 

    uncertainty in capital and commodities markets;

 

    the price and quantity of foreign imports;

 

    domestic and global political conditions, particularly in oil and natural gas producing countries or regions, such as the Middle East, Russia, the North Sea, Africa and South America;

 

    the ability of members of the Organization of Petroleum Exporting Countries and other producing countries to agree upon and maintain oil prices and production levels;

 

    the level of consumer product demand, including in emerging markets, such as China;

 

    weather conditions, force majeure events such as earthquakes and nuclear meltdowns;

 

    technological advances affecting energy consumption and the development of oil and natural gas reserves;

 

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

 

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

 

    the price and availability of alternative fuels and energy;

 

    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.

Oil and natural gas prices affect the amount of cash flow available to us to meet our financial commitments and fund capital expenditures. Moreover, because only approximately 47% and 39% of our total expected hydrocarbon production in 2015 and 2016, respectively, is hedged, a significant portion of our estimated production is particularly exposed to commodity price volatility. Oil and natural gas prices also impact our ability to borrow money and raise additional capital. For example, the amount we will be able to borrow under the RBL Revolver is subject to periodic redeterminations based, in part, on current oil and natural gas prices and on changing expectations of future prices. Lower prices may also reduce the amount of oil and natural gas that we can economically produce and have an adverse effect on the value of our reserves, which could result in material impairments to our oil and natural gas properties. As a result, if there is a further decline or sustained depression in commodity prices, we may, among other things, be unable to maintain or increase our borrowing capacity, meet our debt obligations or other financial commitments or obtain additional capital, all of which could materially adversely affect our business, results of operations and financial condition.

Our debt agreements restrict our current and future operations and if we default under our debt agreements, our lenders may act to accelerate our indebtedness, which would impact our ability to continue to conduct our business.

Our debt agreements contain a number of restrictive covenants that impose significant operating and financial restrictions on us and may limit our ability to engage in acts that may be in our best interest, including restrictions on our ability to:

 

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

 

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

 

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    prepay, redeem or repurchase certain debt;

 

    make loans, investments and other restricted payments;

 

    sell, transfer or otherwise dispose of assets;

 

    create or incur liens;

 

    enter into transactions with affiliates;

 

    alter the businesses we conduct;

 

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

 

    consolidate, merge or sell all or substantially all of our assets.

In addition, we are subject to a financial performance covenant under the credit agreement governing the RBL Revolver, which, subsequent to the March 18, 2015 amendment, requires us to maintain a ratio of consolidated first lien debt to consolidated EBITDA of not more than 2.75 to 1.0 (up from 1.5 to 1.0 previously) as of the end of each fiscal quarter beginning with the first quarter of 2015 through and including the third quarter of 2015. For the fourth quarter of 2015, we are required to maintain a ratio of consolidated first lien debt to consolidated EBITDA of not more than 1.5 to 1.0, after which, beginning with the first quarter of 2016, the credit agreement requires us to maintain a ratio of consolidated total debt to consolidated EBITDA of not more than 4.5 to 1.0 as of the end of each fiscal quarter through maturity. In addition, the March 18, 2015 amendment requires us to maintain minimum liquidity (as defined in the credit agreement) of $150.0 million on the date of, and after giving pro forma effect to, any interest payment, subsequent to July 1, 2015, in respect of certain other indebtedness, including payments in respect of our 9.75% Senior Notes due 2020 and the Second Lien Term Loan. These covenants could restrict our ability to engage in certain actions, including by potentially limiting our ability to sell assets, make future borrowings under the RBL Revolver, incur other additional indebtedness, or make certain interest payments. Our ability to meet the financial performance covenant and liquidity covenant can be affected by events beyond our control, such as changes in commodity prices, and there can be no assurance that we will be able to comply with these covenants in future periods. In addition, if we receive additional waivers or amendments to our RBL Revolver, our lenders may impose additional operating and financial restrictions on us or modify the terms of the RBL Revolver.

Our long-term debt is reflected as a current liability in our consolidated balance sheet as of December 31, 2014 due to uncertainty regarding our ability to comply with certain restrictive covenants contained in our debt agreements. A breach of the covenants under our debt agreements (including certain reporting and administrative requirements, such as, but not limited to, the form and content of the auditor’s report, providing financial statements, compliance certificates and other documents to our counterparties to the Debt Agreements under prescribed timelines) could result in an event of default under the applicable indebtedness. Such a default may allow the creditors to accelerate the related indebtedness and may result in the acceleration of any other indebtedness to which a cross-acceleration or cross-default provision applies. In addition, an event of default under the credit agreement governing the RBL Revolver would permit the lenders under the RBL Revolver to terminate all commitments to extend further credit under that facility. Furthermore, if we were unable to repay the amounts due and payable under the RBL Revolver and the Second Lien Term Loan, those lenders could proceed against the collateral granted to them to secure that indebtedness. In the event our debt holders accelerate the repayment of our borrowings, we may not have sufficient assets to repay that indebtedness and we could be forced into bankruptcy or liquidation.

 

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We may be unable to maintain compliance with the Consolidated First Lien Debt to Consolidated EBITDA Ratio in 2015, Consolidated Total Debt to Consolidated EBITDA Ratio in 2016 and $150.00 million of liquidity required of us by provisions contained in the Credit Agreement and subsequent amendments which could result in an event of default that, if not cured or waived, would have a material adverse effect on our business, financial condition and results of operations.

The credit agreement governing the RBL Revolver requires us to maintain certain financial ratios or to reduce our indebtedness if we are unable to comply with such ratios. As of December 31, 2014, we are in compliance with our financial covenants. Unless the financial performance and/or our liquidity covenant is amended further or we are successful in implementing a strategic alternative to improve our capital structure, we do not expect to remain in compliance with all of our restrictive covenants in our Credit Agreement. As a result, our long-term debt is reflected as a current liability in our consolidated balance sheet at December 31, 2014. Any failure to comply with the conditions and covenants in our Credit Agreement that is not waived by our lender or otherwise cured could lead to a termination of our Credit Agreement, acceleration of all amounts due under our Credit Agreement, or trigger cross-default provisions under other financing arrangements. These restrictions may limit our ability to obtain future financings to withstand a future downturn in our business or the economy in general, or to otherwise conduct necessary corporate activities. We may also be prevented from taking advantage of business opportunities that arise because of the limitations that the restrictive covenants under our Credit Agreement impose on us.

Oil and natural gas prices are volatile. If oil and natural gas prices remain weak or deteriorate our borrowing base may be reduced and we may be required to repay a portion of the RBL Revolver which could result in an event of default under the credit agreement governing such facility.

Our ability to access funds under the RBL Revolver 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 remain weak or deteriorate, if we have a downward revision in estimates of our proved reserves, or if we sell additional oil and natural gas reserves, our borrowing base may be reduced. Any reduction in the borrowing base will reduce our available liquidity, and, if the reduction results in the outstanding amount under the facility exceeding the borrowing base, we will be required to repay the deficiency within 30 days or in six monthly installments thereafter, at our election. We may not have the financial resources in the future to make any mandatory principal prepayments required under our revolving credit facility, which could result in an event of default.

A downgrade in our debt ratings could restrict our access to, and negatively impact the terms of, current or future financings or trade credit.

Our ability to obtain financings and trade credit and the terms of any financings or trade credit is, in part, dependent on the credit ratings assigned to our debt by independent credit rating agencies. We cannot provide assurance that any of our current ratings will remain in effect for any given period of time or that a rating will not be lowered or withdrawn entirely by a rating agency if, in its judgment, circumstances so warrant. Factors that may impact our credit ratings include debt levels, planned asset purchases or sales and near-term and long-term production growth opportunities, liquidity, asset quality, cost structure, product mix and commodity pricing levels. A ratings downgrade could adversely impact our ability to access financings or trade credit, increase our borrowing costs and potentially require us to post letters of credit for certain obligations.

We may sell or otherwise dispose of certain of our properties as a result of our evaluation of our asset portfolio and to help enhance our liquidity. Such dispositions could materially adversely affect our business, results of operations and financial condition.

Since the Acquisition, we have sold approximately $1.2 billion of assets, and we may pursue additional divestitures or other asset monetization transactions as we continue to evaluate our asset portfolio and to help enhance our liquidity. Dispositions of assets could affect our future performance by reducing our production and

 

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reserves and, for purposes of calculating compliance with the financial performance covenant under the RBL Revolver, could reduce our consolidated EBITDA on a pro forma historical basis. These transactions also have inherent risks, including possible delays in closing transactions (including potential difficulties in obtaining regulatory approvals), the risk of lower-than-expected sales proceeds for the disposed assets and potential post-closing claims for indemnification. In addition, the current commodity price environment may result in fewer potential bidders, unsuccessful sales efforts and a higher risk that buyers may seek to terminate a transaction prior to closing. In addition, we may not realize any expected cost savings from asset dispositions, in part because of revenue losses from the divested properties.

Our substantial indebtedness, liquidity issues and potential to seek protection under the federal bankruptcy laws has impacted, and may continue to impact, our business and operations.

Due to the uncertainty about our future, there is risk that, among other things:

 

    third parties’ confidence in our ability to explore and produce oil and natural gas could erode, which could impact our ability to execute on our business strategy;

 

    it may become more difficult to retain, attract or replace key employees;

 

    employees could be distracted from performance of their duties or more easily attracted to other career opportunities; and

 

    our suppliers, hedge counterparties, vendors and service providers could renegotiate the terms of our arrangements, terminate their relationship with us or require financial assurances from us.

The occurrence of certain of these events has already negatively affected our business and may have a material adverse effect on our business, results of operations and financial condition.

Drilling for and producing oil and natural gas are high risk activities with many uncertainties that could materially adversely affect our business, results of operations and financial condition.

Our operations are subject to many risks, including the risk that we will not discover commercially productive reservoirs. Drilling for oil and natural gas can be unprofitable, not only from dry holes, but from productive wells that do not produce sufficient revenue to return a profit. 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, as well as 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, and our operations may involve the use of recently-developed drilling and completion techniques. Our cost of drilling, completing, equipping and operating wells is often uncertain before drilling commences. Declines in commodity prices and overruns in budgeted expenditures are common risks that can make a particular project uneconomic or less economic than forecasted. Further, many factors may curtail, delay or cancel drilling and completion projects, including the following:

 

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

 

    delays in receiving governmental permits, orders or approvals;

 

    differing pressure than anticipated or irregularities in geological formations;

 

    equipment failures or accidents;

 

    adverse weather conditions;

 

    surface access restrictions;

 

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    loss of title or other title related issues;

 

    shortages or delays in the availability of, increases in the cost of, or increased competition for, drilling rigs and crews, fracture stimulation crews and equipment, pipe, chemicals and supplies; and

 

    restrictions in access to or disposal of water resources used in drilling and completion operations.

Historically, there have been shortages of drilling and workover rigs, pipe and other oilfield equipment and skilled personnel as demand for rigs, equipment and personnel has increased along with the number of wells being drilled. These factors may, among other things, cause significant increases in costs for equipment, services and/or personnel. Such shortages or increases in costs could significantly decrease our profit margin, cash flow and operating results, or restrict our operations in the future.

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, 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.

Estimates of proved reserves and future net cash flows are not precise. The actual quantities of our proved reserves and our future net cash flows may prove to be lower than estimated.

Numerous uncertainties exist in estimating quantities of proved reserves and future net cash flows therefrom. Our estimates of proved reserves and related future net cash flows are based on various assumptions, which may ultimately prove to be inaccurate, including, but not limited to, future commodity prices, the quantities of oil and natural gas that are ultimately recovered, future operating and development costs, future taxes (such as severance, ad valorem, excise and other similar taxes) and the effect of governmental regulations. Because all reserve estimates are to some degree subjective, the actual results of certain items may differ materially from those assumed in estimating reserves. Furthermore, different reserve engineers may make different estimates of reserves and cash flows based on the same data. Our actual production, revenue and expenditures with respect to reserves will likely be different from estimates and the differences may be material.

The standardized measure of discounted future net cash flows (the “Standardized Measure”) included in this report should not be considered as the current market value of the estimated oil and natural gas reserves attributable to our properties. The prices used in calculating the Standardized Measure and in estimating our quantities of proved reserves are, in accordance with SEC requirements, calculated by determining the unweighted arithmetic average of the first-day-of-the-month commodity prices for the preceding 12 months. For the 12-months ended December 31, 2014, average prices used to calculate our Standardized Measure and in estimating our quantities of proved reserves were $94.99 per Bbl for crude oil and $4.35 per MMBtu for natural gas (before differentials). Commodity prices declined significantly in the fourth quarter of 2014 and continued this trend in early 2015. If commodity prices remain at current levels, our future calculations of the Standardized Measure and estimated quantities of proved reserves will be based on these lower commodity prices, which would result in the removal of non-economic reserves from our proved reserves in future periods. Holding all other factors constant, if commodity prices used in our year-end reserve estimates were decreased to forward pricing at February 3, 2015, the discounted net future cash flows of our proved reserves at December 31, 2014 would decrease by approximately 45%.

Actual future net cash flows also will be affected by other factors, including:

 

    the amount and timing of actual production;

 

    levels of future capital spending;

 

    increases or decreases in the supply of, or demand for, oil and natural gas; and

 

    changes in governmental regulations or taxation.

 

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Accordingly, our estimates of future net cash flows may be materially different from the future net cash flows that are ultimately received. In addition, the ten percent discount factor mandated by the rules and regulations of the SEC to be used in calculating discounted future net cash flows may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the oil and natural gas industry in general. Therefore, the estimates of our discounted future net cash flows should not be construed as accurate estimates of the current market value of our proved reserves. Should our actual proved reserves and related net cash flows differ from our estimates, it may materially adversely affect our business, results of operations and financial condition.

The development of our estimated proved undeveloped reserves may take longer and may require higher levels of capital expenditures than we currently anticipate and are dependent upon economically viable commodity prices to justify development. Therefore, our estimated proved undeveloped reserves may not ultimately be developed or produced.

Approximately 16.1% of our total estimated proved reserves were classified as proved undeveloped as of December 31, 2014. Development of these proved undeveloped reserves may take longer and require higher levels of capital expenditures than we currently anticipate. Delays in the development of these reserves, increases in costs to drill and develop such reserves or decreases in commodity prices will reduce the discounted future cash flows of our estimated proved undeveloped reserves and future net cash flows estimated for such reserves and may result in some projects becoming uneconomic. In addition, 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. Accordingly, delays in the development of such reserves, increases in capital expenditures required to develop such reserves and changes in commodity prices could cause us to have to reclassify our proved undeveloped reserves as unproved reserves, which may materially adversely affect our business, results of operations and financial condition.

Our business requires substantial capital expenditures, and any inability to obtain needed capital or financing on satisfactory terms or at all, or any negative developments in the capital markets, could have a material adverse effect on our business.

The oil and natural gas industry is capital intensive. We have historically financed our capital expenditures through cash flows from operations, borrowings under our RBL Revolver and the sale of assets. Our cash flow from operations and access to capital are subject to a number of variables, including:

 

    our proved reserves;

 

    the level of oil and natural gas we are able to produce from existing wells;

 

    the prices at which we are able to sell oil and natural gas;

 

    our ability to acquire, locate and produce new reserves;

 

    global credit and securities markets; and

 

    the ability and willingness of lenders and investors to provide capital and the cost of that capital.

Because of these factors, we may not be able to adequately finance capital expenditures at a level to grow our business.

Moreover, as a result of our significant indebtedness and the recently volatility in commodity prices, we have significantly reduced our planned capital spending on drilling and completion activities in 2015 as compared to prior years. This reduction in capital expenditures may curtail the development of our properties, which in turn could lead to a decline in our production and reserves and could materially adversely affect our business, results of operations and financial condition.

 

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Our future drilling activities are scheduled over an extended time period, making them susceptible to uncertainties that could materially alter the occurrence or timing of such drilling.

We have identified certain potential drilling locations as an estimation of our future drilling activities on our existing acreage. Our ability to drill and develop these potential drilling locations depends on a number of uncertainties, including: (i) our ability to timely drill wells on lands subject to complex development terms and circumstances; (ii) the availability and cost of capital, equipment, services and personnel; (iii) seasonal conditions; (iv) regulatory and third-party permits, orders and approvals; (v) oil and natural gas prices; (vi) drilling and completion costs; and (vii) and well results. Because of these uncertainties, we do not know if such potential drilling locations will ever be drilled or if we will be able to produce oil and/or natural gas from these or any other potential drilling locations. Moreover, unless production is established or other operations are conducted on a timely basis with respect to the undeveloped acres on which some of our potential drilling locations are located, the leases for such acreage may expire. If we are not able to renew or otherwise maintain leases before they expire, any proved undeveloped reserves associated with such leases will be removed from our proved reserves. Therefore, our actual drilling activities may materially differ from those presently estimated, which could materially adversely affect our business, results of operations and financial condition.

Unless we replace our oil and natural gas reserves, our reserves and production will decline, which would materially adversely affect our business, results of operations and financial condition.

Producing oil and natural gas reservoirs are generally characterized by declining production rates that vary depending upon reservoir characteristics and other factors. Unless we conduct successful development, exploitation and exploration activities or acquire properties containing proved reserves, our proved reserves will decline as those reserves are produced. The rate of decline will change if production from our existing wells declines in a different manner than we have estimated and can also change under other circumstances, many of which are outside of our control. 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. Moreover, we have significantly reduced our planned capital spending on drilling and completion activities in 2015 as compared to prior years, which could curtail the development of our properties and result in a decline in our production and reserves for future periods. Further, a significant delay between when we discontinue drilling activities and when we restart our drilling program could negatively impact our ability to restart such activities when conditions warrant in the future. If we are unable to replace our current and future production, the value of our reserves could decrease, and our business, results of operations and financial condition would be materially adversely affected.

Full cost accounting rules may require us to record certain non-cash asset write-downs in the future, which could materially adversely affect our results of operations.

We utilize the full cost method of accounting for oil and natural gas activities. Under full cost accounting, we are required to perform a ceiling test each quarter. The ceiling test is an impairment test and generally establishes a maximum, or “ceiling,” of the book value of oil and natural gas properties. To the extent that the book value of our oil and natural gas properties exceed the ceiling, a non-cash impairment charge is recorded. The impairment charge may not be reversed in future periods even if the calculated ceiling increases. The mechanics of the ceiling test are described in Part II, Item 8—“Financial Statements and Supplementary Data.”

As of December 31, 2014 and 2013, we had approximately $2.2 billion and $3.9 billion, respectively, of costs that were excluded from amortization. These costs relate to the amounts associated with unproved properties and wells in progress. Costs associated with unproved properties are assessed at least annually to ascertain whether impairment has occurred. In addition, impairment assessments are made for interim reporting periods if facts and circumstances exist that suggest impairment has occurred. The facts and circumstances included in our impairment assessment are described in Part II, Item 8—“Financial Statements and

 

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Supplementary Data.” During any period in which impairment is indicated, some or all of the accumulated costs incurred to date for the impaired property become part of our amortization base and are then subject to depletion and the full cost ceiling limitation. Accordingly, a significant change in the factors considered for impairment, many of which are beyond our control, may shift a significant amount of cost from unproved properties into our amortization base and negatively impact the results of our full cost ceiling test. During the years ended December 31, 2014, 2013 and 2012, we recorded approximately $1.7 billion, $1.6 billion and $1.3 billion, respectively, of impairments associated with our unproved property.

During the years ended December 31, 2014, 2013 and 2012, we recorded full cost ceiling test impairments of approximately $2.3 billion, $1.8 billion and $2.3 billion, respectively, as a result of our quarterly ceiling tests. We could incur additional material write-downs in the future, particularly as a result of a decline of oil and natural gas prices, impairments of costs associated with unproved properties or changes in reserve estimates. If product prices remain at current levels, impairment expense in 2015 will be material.

We may incur substantial losses and be subject to substantial claims as a result of our oil and natural gas operations. Additionally we may not be insured for, or our insurance may be inadequate to protect us, against these risks.

Our oil and natural gas operations are subject to all of the risks associated with exploring, drilling for and producing oil and natural gas, including the possibility of:

 

    environmental hazards, such as uncontrollable flows of oil, natural gas, brine, well fluids, toxic gas or other pollution into the environment, including soil or groundwater contamination;

 

    abnormally pressured formations;

 

    mechanical failures and difficulties, such as stuck oilfield drilling and service tools and casing collapse;

 

    fires, explosions and ruptures of pipelines;

 

    fires and explosions at well locations or involving associated equipment;

 

    personal injuries and death;

 

    natural disasters; and

 

    terrorist attacks targeting oil and natural gas related facilities and infrastructure.

It is impossible for us to predict the magnitude of any such event and whether our contingency plans would be sufficient to allow us to successfully respond to such an event in a way that would prevent a material interruption in our business operations. Any of these risks could materially adversely affect our ability to conduct operations or result in substantial damages and losses to us as a result of, or claims for, personal injury or loss of life, damage to property or the environment, regulatory investigations or penalties, suspension of our operations or repair and remediation costs.

We do not insure fully against all risks associated with our business either because such insurance is not available or because we believe that the cost of available insurance is excessive relative to the risks presented. In addition, our insurance policies have materiality deductibles, self-insurance levels and limits on our maximum recovery, and the amount of our insurance coverage for a particular risk may be insufficient to compensate us for any losses that we may actually incur. A loss not covered or not fully covered by insurance could materially adversely affect our business, results of operations and financial condition.

 

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The success of our operations depends, in part, on other parties, particularly with respect to properties we do not operate, which could reduce our production and revenue or could result in increased liabilities for environmental or safety related incidents.

A significant portion of our properties are operated by other parties. With respect to such properties, we have limited ability to influence or control day-to-day operations, including those relating to compliance with environmental, safety and other regulations, or the amount of capital expenditures that we are required to fund with respect to such properties. As a result, the success and timing of drilling and development activities on such properties depend upon factors outside of our control, including the operator’s compliance with the applicable operating or similar agreement, the timing and amount of capital expenditures, the operator’s expertise and financial resources, the inclusion of other participants in drilling wells and the use of technology. Furthermore, we may not be able to remove the operator of our non-operated properties in the event of poor performance. In addition, even with respect to our operated properties, we may depend upon third-party working interest owners to fund their respective share of capital expenditures to successfully execute a project. Such limitations and dependence on other parties could cause us to incur unexpected future costs and materially adversely affect our business, results of operations and financial condition.

We rely on independent experts and technical or operational service providers over whom we may have limited control.

We use a variety of independent contractors to provide us with certain technical assistance and services. For example, we rely upon the owners and operators of rigs and drilling equipment, and upon providers of field services (including completions), to drill and complete wells within our prospects. Our limited control over the activities and business practices of these service providers, any inability on our part to maintain satisfactory commercial relationships with them or their failure to provide quality services could materially adversely affect our business, results of operations and financial condition.

There is significant competition in the oil and natural gas industry, which may materially adversely affect our ability to successfully implement our business strategies.

The oil and natural gas industry is intensely competitive, and we compete with other companies that possess and employ financial, technical and personnel resources that are substantially greater than ours. Our ability to acquire additional properties and to find and develop reserves in the future will depend on our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. Our competitors may be able to pay more for oil and natural gas leases and mineral estates, productive oil and natural gas properties and exploratory prospects or define, evaluate, bid for and purchase a greater number of oil and natural gas leases, properties and prospects than our financial or personnel resources permit. Such competition can also drive up the costs to acquire oil and natural gas leases, properties and prospects in areas where we are already conducting business and operations.

In addition, because of our significant indebtedness and liquidity constraints, many of our competitors have a greater ability than us to continue exploration and development activities during periods of low oil and natural gas prices and/or higher service costs. The more favorable capital structure of these companies may also give them better access to capital and on better terms, which could give such companies an advantage in the financing and execution of acquisitions and their drilling programs. Moreover, our larger competitors may be able to absorb the burden of present and future federal, state, local and other laws and regulations more easily than we can, which could materially adversely affect our competitive position.

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

 

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implement new technologies at a substantial cost. One or more of the technologies that we currently use or that we may implement in the future may become obsolete. We may not 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.

The loss of officers or other key personnel could materially adversely affect our business.

Our ability to hire and retain our officers and other key personnel, including geologists, geophysicists, engineers and other professionals, is important to our performance and operations. Competition for qualified personnel can be intense, particularly in the oil and natural gas industry, and there are a limited number of people with the requisite knowledge and experience. In addition, our substantial indebtedness may make the recruitment and retention of qualified personnel more difficult. If we are unable to retain our current officers and other key employees and/or recruit new officers and employees of comparable knowledge and experience, our business, results of operations and financial condition may be materially adversely affected.

We may not realize any or all of our projected cost savings from our recent cost-reduction efforts, including a reduction in our workforce, and those efforts could materially adversely affect our business.

In March 2015, we began implementing comprehensive cost-reduction efforts to decrease our long-term recurring expenses and to improve operational efficiencies (the “Cost Reduction Plan”). These efforts included a reduction in our workforce of approximately 30% across multiple functions throughout the Company. The Cost Reduction Plan, including the related reduction in force, and any other cost reduction measures we may take in the future, may not result in the expected cost savings and may distract management from our core business, harm our reputation or yield unanticipated consequences, such as attrition beyond the planned reduction in workforce, difficulties in attracting and hiring new employees, increased difficulties in the execution of our day-to-day operations, reduced employee productivity, inability to complete certain tasks necessary to enhance our future operations such as further development of management reporting systems and a deterioration of employee morale. In addition, we expect to have to rely more on consultants and service providers and incur additional costs to further retain remaining key employees in connection with the Cost Reduction Plan. In addition, as a result of the Cost Reduction Plan, we currently estimate that we will record restructuring charges in excess of $30.0 million, which are expected to be recorded primarily in the first quarter of 2015. Our estimated restructuring charges are based on a number of assumptions, and the actual results may differ materially from our expectations and additional charges not currently expected may be incurred in connection with, or as a result of, these reductions.

We may be unable to make attractive acquisitions or successfully integrate acquired assets or businesses, and any inability to do so may disrupt our business and hinder our ability to grow. In addition, any acquisitions we do complete will be subject to substantial risks.

In the future we may make acquisitions of assets or businesses that complement or expand our current business. If we are unable to make these acquisitions for any reason, including because we are: (i) unable to identify attractive acquisition candidates, to analyze acquisition opportunities successfully from an operational and financial point of view or to negotiate acceptable purchase contracts with them; (ii) unable to obtain financing for these acquisitions on economically acceptable terms; or (iii) outbid by competitors, then our future growth could be limited.

Furthermore, even if we do make acquisitions they may not result in an increase in our cash flow from operations or otherwise result in the benefits anticipated. Any acquisition involves potential risks that could

 

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significantly impair our ability to manage our business and materially adversely affect our business, results of operations and financial condition, including, among other things:

 

    mistaken assumptions about volumes, potential drilling locations, revenues and costs, including synergies and the overall costs of equity or debt;

 

    difficulties in integrating the operations, technologies, products and personnel of the acquired companies;

 

    difficulties in complying with regulations, such as environmental regulations, and managing risks related to an acquired business or assets;

 

    timely completion of necessary financing and required amendments, if any, to existing agreements;

 

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

 

    undiscovered, unknown and unforeseen problems, defects, liabilities or other issues related to any acquisition for which contractual protections prove inadequate, including environmental liabilities and title defects;

 

    assumption of liabilities that were not disclosed to us or that exceed our estimates;

 

    diversion of management’s and employees’ attention from normal daily operations of the business;

 

    difficulties in entering regions in which we have no or limited direct prior experience and where competitors in such regions have stronger operating positions; and

 

    potential loss of key employees.

Moreover, our reviews of acquired properties are inherently incomplete since it is generally not feasible to review in depth every individual property involved in each acquisition. Even a detailed review of records and properties may not necessarily reveal existing or potential problems, nor will it necessarily permit a buyer to become sufficiently familiar with the properties to assess fully their deficiencies and potential. Inspections may not always be performed on every well, and environmental problems, such as groundwater contamination, are not necessarily observable even when an inspection is undertaken. The inability to make future acquisitions or adequately evaluate the impact of such acquisitions could materially adversely affect our business, results of operations and financial condition.

Our business operations could be disrupted if our information technology systems fail to perform adequately.

The efficient operation of our business depends on our information technology systems. We rely on our information technology systems to effectively manage our business data, communications and other business processes. For example, we implemented a new enterprise resource planning (“ERP”) software system in 2014 to assist in the management of data across our company. The failure of our information technology systems, including the ERP software system, to perform as we anticipate could disrupt our business and result in transaction errors, processing inefficiencies and the loss of sales and customers, causing our business, results of operations and financial condition to suffer. In addition, our information technology systems may be vulnerable to damage or interruption from circumstances beyond our control, including fire, natural disasters, power outages, systems failures, security breaches and viruses. Any such damage or interruption could materially adversely affect our business, results of operations and financial condition.

Market conditions or operational impediments may hinder our access to oil and natural gas markets or delay our production.

Market or operational conditions or the unavailability of satisfactory oil and natural gas transportation and infrastructure arrangements may hinder our access to oil and natural gas markets or delay our production. The availability of a ready market for our oil and natural gas production depends on a number of factors, including

 

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the demand for and supply of oil and natural gas and the proximity of our reserves to pipelines and terminal facilities. Our ability to market our production depends in substantial part on the availability and capacity of gathering systems, transportation, fractionation systems, pipelines and processing facilities owned and operated by third parties. Our failure to obtain such services on acceptable terms could materially adversely affect our business. We may be required to curtail production from or shut in wells for a lack of a market or because of inadequacy or unavailability of pipelines, gathering system capacity, transportation or processing, treating and fractionation facilities or refinery demand. If that were to occur, we would be unable to realize revenue from those wells until other arrangements were made to deliver the products at a reasonable cost to market, which could materially adversely affect our business, results of operations and financial condition.

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

To achieve more predictable cash flows and to reduce our exposure to adverse fluctuations in commodity prices, we currently, and may in the future, enter into derivative financial instruments for a portion of our future oil and natural gas production. Such risk management activities will impact our earnings in various ways, including through the recognition of certain mark-to-market gains and losses on our financial derivative instruments, resulting from changes in the fair value of our financial derivative instruments between periods. In addition, our derivative financial instruments may limit the benefit we would otherwise receive from increases in the prices for oil or natural gas and therefore may reduce revenues in the future. Our derivative financial instruments may expose us to the risk of financial loss in certain other circumstances, including instances in which our production is less than expected or when there are issues with regard to the legal enforceability of such derivative financial instruments.

Our future risk management activities may, in some cases, require the posting of cash collateral with counterparties. If we enter into derivative financial instruments that require cash collateral and commodity prices or interest rates change in a manner adverse to us, our cash otherwise available for use in our operations would be reduced, which could limit our ability to make future capital expenditures and make payments on our indebtedness. Any such future collateral requirements will depend on arrangements with our counterparties, highly volatile oil and natural gas prices and interest rates.

Our derivative financial instruments also expose us to the risk of financial loss if a counterparty fails to perform under its respective agreement. Disruptions in the financial markets could lead to sudden decreases in a counterparty’s liquidity, which could make them unable to perform under the terms of the arrangement and, as a result, we may not be able to realize the benefit of the related derivative financial instrument. Any default by the counterparty under our derivative financial instruments when they become due could materially adversely affect our business, results of operations and financial condition.

We are subject to federal, state, local and other laws, regulations and administrative actions and rule making that could increase our costs, reduce our revenues, cash flows or liquidity, or otherwise alter the way we do business.

The exploration, development, production and sale of oil and natural gas in the United States is subject to extensive federal, state, tribal, local and other laws, regulations and agency actions, including those pertaining to environmental, health and safety, wildlife conservation, gathering and transportation of oil and natural gas, conservation policies, reporting obligations, royalty payments, unclaimed property and the imposition of taxes. Such regulations include requirements for permits to drill and to conduct other operations and for provision of financial assurances (such as bonds) covering drilling and well operations. 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. In addition, we may be required to make large expenditures to comply with applicable governmental rules, regulations, permits or orders. For example, certain regulations require the plugging and abandonment of wells, which may result in significant costs associated with the removal of tangible equipment and other restorative actions at the end of oil and natural gas production operations. Because of the subjectivity in

 

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the assumptions underlying our estimated compliance costs with respect to these requirements and the relatively long lives of most of our wells, the costs to ultimately comply with plugging and abandonment obligations may vary significantly from our estimates, which could materially adversely affect our business, financial condition and results of operations.

Activities subject to regulation include, but are not limited to:

 

    the location of wells and the methods of drilling and completing wells;

 

    disposal of fluids used and wastes generated in connection with drilling, completion and production operations;

 

    access to, and surface use and restoration of, surface locations to be used for wells and/or related facilities;

 

    plugging and abandoning of wells;

 

    air quality, water quality, wetlands, noise levels and related permits;

 

    gathering, transporting and marketing of oil and natural gas;

 

    taxation; and

 

    access to the water resources used in drilling and completion operations.

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 affect the timing of our operations, the ability to execute our operations as originally planned and limit the quantity of oil and natural gas we may produce and sell. We generally need to obtain drilling permits from federal, state, local and other governmental authorities. Delays in obtaining regulatory approvals or drilling 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 adverse effect on our ability to explore on or develop our properties. Failure to comply with such requirements may result in the suspension or termination of operations and subject us to criminal as well as civil and administrative penalties. Compliance costs can be significant. Moreover, the enactment of additional requirements in the future or a change in the interpretation or the enforcement of existing requirements could substantially increase our costs of doing business. Any such liabilities, penalties, suspensions, terminations or regulatory changes could materially adversely affect our business, results of operations and financial condition.

Our operations may be exposed to significant delays, costs and liabilities as a result of environmental, health and safety laws and regulations, as well as administrative actions and rule making, applicable to our business.

Our oil and natural gas exploration and production operations are subject to extensive and increasingly stringent federal, state, local and other laws and regulations, as well as administrative actions and rule making, pertaining to the protection of the environment, including those governing the release, emission or discharge of materials into the environment, the generation, storage, transportation, handling and disposal of materials (including solid and hazardous wastes), the safety of employees, or otherwise relating to pollution or protection of the environment, human health and safety and natural resources. Wellbore integrity regulations have also been enacted and are being considered by a number of regulatory bodies. We may incur significant costs, delays and liabilities as a result of these requirements. 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, and waste treatment, storage and disposal facilities. The regulatory frameworks govern, and often require permits for, the handling of drilling and production materials, water withdrawal, disposal of drilling, completion and production wastes, operation of air emissions sources, and drilling activities, including those conducted on lands lying within wilderness, wetlands, Federal and Indian lands

 

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and other protected areas. Numerous governmental authorities, such as EPA and analogous state agencies, have the power to enforce compliance with these laws and regulations and the permits issued under them. Failure to comply with these laws and regulations may result in the assessment of administrative, civil or criminal penalties; the imposition of investigatory or remedial obligations; and the issuance of injunctions requiring remediation or limiting or preventing some or all of our operations. Liabilities, penalties, suspensions, terminations or increased costs resulting from any failure to comply with existing environmental, health or safety requirements, or from the enactment of additional requirements in the future or a change in the interpretation or the enforcement of existing requirements, could materially adversely affect our business, results of operations and financial condition.

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. The age and condition of some of our assets increases the likelihood that we will incur higher levels of costs associated with environmental, health and safety matters. We and/or other owners and operators of these facilities may have generated or disposed of wastes that allegedly 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, natural resource and property damage (including site clean-up and restoration costs) related to the environmental, health or safety impact of our oil and natural gas production activities, and we have been named from time to time as, and currently are, a defendant in litigation related to such matters. Under certain laws, in particular CERCLA, 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, and even if the operations were in compliance with all applicable laws at the time the contamination occurred. Private parties, including the owners of properties upon which our wells are drilled and facilities where our petroleum hydrocarbons or wastes are taken for reclamation or disposal, may also have the right to pursue legal actions to enforce compliance, as well as to seek damages for noncompliance with environmental laws and regulations or for personal injury or property damage (including remediation costs). We have been and continue to be responsible for remediating contamination, including at some of our current and former facilities. Future costs of newly discovered or new contamination may result in a materially adverse impact on our business or operations.

In addition, EPA issued a final rule on April 17, 2012, setting forth new NSPS and NESHAP standards for the oil and natural gas sector. The new rule will be fully implemented in 2015. We are continuing to evaluate the effect of this rule on our business, but we do not currently expect these requirements to materially adversely affect our business, financial condition or results of operations. Because of the subjectivity in the assumptions underlying our estimated compliance costs with respect to this rule, however, the costs to ultimately comply with the rule may vary significantly from our estimates, which could materially adversely affect our business, financial condition and results of operations.

Moreover, current lease terms, permit conditions and stipulations and other governmental regulatory conditions restrict drilling operations and certain other activities during certain times of the year on a significant portion of our properties in the Greater Green River and Powder River basins due to wildlife activity and/or habitat. In addition, the U.S. Fish and Wildlife Service recently announced its decision to list the lesser prairie chicken as “threatened” under the U.S. Endangered Species Act. The lesser prairie chicken’s habitat overlaps certain of our properties in Western Oklahoma and the Texas Panhandle. We elected to participate in a related U.S. Fish and Wildlife endorsed conservation plan for the lessor prairie chicken that could restrict our operations and result in additional costs with respect to the affected areas. Under a 2011 settlement, the U.S. Fish and Wildlife Service is required to make a determination on the listing of more than 250 species as endangered or threatened over the next several years. The presence of other wildlife, wildlife habitats or plants, including species that are or will be protected under the U.S. Endangered Species Act, could result in additional restrictions

 

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on our ability to access and/or operate these and other properties, including with respect to our other core positions, which could materially adversely affect our business, results of operations and financial condition.

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

Most of our recent drilling operations have been in tight and unconventional oil and natural gas formations, which are completed using hydraulic fracturing. Hydraulic fracturing involves the high-pressure injection of water, sand and additives into rock formations to stimulate crude oil and natural gas production. Recently there has been increased public concern regarding an alleged potential for hydraulic fracturing to adversely affect drinking water supplies and increase the potential for earthquakes. As a result, several federal and state agencies are considering legislation that would increase the regulatory burden imposed on hydraulic fracturing.

Legislation has been proposed in the U.S. Congress to regulate hydraulic fracturing, including proposals to amend the SDWA to require the permitting of every hydraulic fracturing project and the reporting and public disclosure of chemicals used in the fracturing process, which could 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 are impairing groundwater or causing other damage. Such bills, if enacted, could establish an additional level of regulation at the federal or state level that could lead to operational delays or increased operating costs and could result in additional regulatory burdens that could make it more difficult to perform hydraulic fracturing and increase our costs of compliance and doing business.

There have been several recent federal initiatives related to hydraulic fracturing. In April 2012, the White House issued an executive order creating a multi-agency task force to coordinate federal oversight of hydraulic fracturing. In February 2014, EPA issued an interpretive memorandum to clarify UIC requirements under the SDWA for use of diesel fuels in hydraulic fracturing, and a technical guidance containing recommendations for EPA permit writers to consider in implementing these UIC requirements. These documents clarified that any owner or operator who injects diesel fuels in hydraulic fracturing for oil or gas extraction must obtain a UIC permit before injection. EPA has also announced plans to propose effluent limitations for the treatment and discharge of wastewater resulting from hydraulic-fracturing activities in 2015. In addition, the federal Bureau of Land Management proposed and is in the process of reconsidering regulations requiring disclosure of chemicals used in the hydraulic fracturing process both before and after any drilling on federal public land.

Other EPA initiatives have focused on studies related to hydraulic fracturing’s potential impact on drinking water. At the request of the U.S. Congress, EPA is undertaking a national study to understand the potential impacts of hydraulic fracturing on drinking water resources. The study has included a review of published literature, analysis of existing data, scenario evaluation and modeling, laboratory studies, and case studies. EPA issued a progress report in December 2012 detailing the steps being undertaken in the study, and it expects to release a final draft report for peer review and comment in 2015. In December 2011, the EPA published a draft report finding that hydraulic fracturing is a likely cause of drinking water contamination in the vicinity of Pavillion, Wyoming; however, in September 2013, the EPA announced that it does not plan to finalize or seek peer review of the report, and that it will continue to support the State of Wyoming in the State’s investigation of the groundwater contamination. Findings such as this could increase public pressure on governmental authorities to implement new regulations regarding hydraulic fracturing.

Many states have adopted or are considering regulations regarding hydraulic fracturing, including requiring the disclosure of chemicals injected during hydraulic fracturing. Vermont banned hydraulic fracturing in the state in 2012 and certain states such as New York and New Jersey issued moratoriums on hydraulic fracturing while they considered studies of and regulations regarding hydraulic fracturing, although New York announced in December 2014 that it will move to ban hydraulic fracturing in the state in 2015 and New Jersey’s moratorium expired in 2013. In some areas hydraulic fracturing has also been the subject of local ordinances attempting to ban or limit the practice; court challenges to such ordinances have had varied outcomes to date. If new federal or state laws or regulations are adopted that significantly increase the risk of legal challenges to, or restrict the use

 

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of, hydraulic fracturing, such legal requirements could make it more difficult or costly for us to perform hydraulic fracturing and increase our costs of compliance and doing business.

Based on increased regulation and attention given to the hydraulic fracturing process from federal, state and various local governments and increased public scrutiny, greater opposition and litigation toward oil and natural gas production utilizing hydraulic fracturing techniques is anticipated. Additional legislation or regulation could lead to operational delays, increased operating costs or a decrease in completion of new oil and natural gas wells all of which could adversely affect our business, results of operations and financial condition.

Regulation and agency actions related to climate change and the emission of GHGs could result in increased operating costs and reduced demand for oil and natural gas and the physical effects of climate change could disrupt our operations.

Global climate change continues to attract considerable public, scientific and regulatory attention, and GHG emission regulation is becoming more stringent. EPA has taken a number of steps towards regulating GHG emissions under the Clean Air Act, including its Mandatory Reporting of Greenhouse Gases Rule published in October 2009, and expanded in November 2010 to include onshore oil and natural gas production activities, its “endangerment” and “cause or contribute” findings under Section 202(a) of the Clean Air Act published in December 2009, and its so-called “Tailoring Rule” concerning regulation of large emitters of GHGs under the Clean Air Act’s PSD Program and Title V program issued in May 2010, which has been subject to litigation. These and future EPA rulemakings regarding GHG emissions could adversely affect our operations and restrict or delay our ability to obtain air permits for new or modified facilities.

We are currently required to report annual GHG emissions from some of our operations, and additional federal and state GHG emission related requirements that are in various stages of development may also affect our operations. In response to the U.S. President’s June 2013 Climate Action Plan, EPA issued a Clean Power Plan designed to cut GHG emissions from existing fossil-fuel fired power plants in June 2014, proposed standards for modified and reconstructed fossil-fuel fired power plants in June 2014, and issued a revised proposal with standards for new fossil fuel-fired plants in September 2013. In March 2014, the Obama administration announced a strategy to reduce methane emissions, which was followed by the administration’s January 2015 announcement of a goal to cut methane emissions from the oil and gas sector by 40-45 percent from 2012 levels by 2025. EPA expects to issue a proposed rule in the summer of 2015 and final rule in 2016 to reduce methane emissions. In addition to the EPA initiatives, the U.S. Congress has considered, and in the future may again consider, legislation that would establish a nationwide cap-and-trade system for GHGs. A number of states have also begun taking action on their own or as part of a multi-state program to control and/or reduce GHG emissions. Such laws and regulations could require us to modify existing, or obtain new, permits, implement additional pollution control technology, curtail operations or increase significantly our operating costs.

Regulation of GHG emissions could also result in reduced demand for our products, as oil and natural gas consumers seek to reduce their own GHG emissions. Any regulation of GHG emissions, including through a cap-and-trade system, technology mandate, emissions tax, reporting requirement or other program, could materially adversely affect our business, reputation, operating performance and product demand. 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 or our customers’ operations may be disrupted, which could result in a decrease in our available product or reduce our customers’ demand for products.

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

The U.S. Congress adopted the Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd- Frank Act”) in 2010. This comprehensive financial reform legislation changes federal oversight and regulation of the over-the-counter derivatives market and entities, such as us, that participate in that market. The legislation

 

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requires the CFTC, the SEC and other regulators to promulgate regulations implementing the new legislation. Among other things, the Dodd-Frank Act and the regulations promulgated under the Dodd-Frank Act impose requirements relating to reporting and recordkeeping, position limits, margin and capital, and mandatory trading and clearing. While many of the regulations are already in effect, the implementation process is still ongoing, and we cannot yet predict the ultimate effect of the regulations on our business. The new legislation and any new regulations could significantly increase the cost of derivative contracts (including through restrictions on the types of collateral we are required to post), materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks, reduce our ability to monetize or restructure existing derivative contracts, and increase our exposure to less creditworthy counterparties, all of which could materially adversely affect our business, results of operations and financial condition.

We may incur more taxes and certain of our projects may become uneconomic if certain federal income tax preferences currently available with respect to oil and natural gas exploration and development are eliminated as a result of future legislation.

The U.S. President’s proposed budget for fiscal 2014 contains a proposal to eliminate certain key U.S. federal income tax preferences currently available to oil and natural gas exploration and production companies. These changes include, but are not limited to (i) the repeal of the percentage depletion allowance for oil and natural gas properties, (ii) the elimination of current deductions for intangible drilling and development costs and (iii) an extension of the amortization period for certain geological and geophysical expenditures. It is unclear whether any of the foregoing changes will actually be enacted or how soon any such changes could become effective. The passage of any legislation as a result of the budget proposal or any other similar change in U.S. federal income tax law could eliminate certain tax preferences that are currently available with respect to oil and natural gas exploration and development. Any such change could materially adversely impact our business, results of operations and financial condition by increasing the costs we incur which would in turn make it uneconomic to drill some locations if commodity prices are not sufficiently high, resulting in lower revenues and decreases in production and reserves.

A change in the jurisdictional characterization of some of our assets by federal, state or local regulatory agencies or a change in policy by those agencies may result in increased regulation of our assets, which may cause our revenues to decline and operating expenses to increase.

Section 1(b) of the NGA exempts natural gas gathering facilities from regulation by FERC as a natural gas company under the NGA. The distinction between FERC-regulated transmission services and federally unregulated gathering services is the subject of on-going litigation, so the classification or reclassification and regulation of our gathering facilities are subject to change based on future determinations by FERC, the courts or the U.S. Congress, which could cause our revenue to decline and operating expenses to increase, thereby materially adversely affecting our business, results of operations and financial condition.

Should we fail to comply with all applicable FERC administered statutes, rules, regulations and orders, we could be subject to substantial penalties and fines.

Under the Energy Policy Act of 2005, FERC has civil penalty authority under the NGA to impose penalties for current violations of up to $1.0 million per day for each violation and disgorgement of profits associated with any violation. While our systems have not been regulated by FERC as a natural gas company under the NGA, FERC has adopted regulations that may subject certain of our otherwise non-FERC jurisdictional facilities to FERC annual reporting and daily scheduled flow and capacity posting requirements and may possibly require the reporting of rates charged for the services provided. Additional rules and legislation pertaining to those and other matters may be considered or adopted by FERC from time to time. Failure to comply with those regulations in the future could subject us to civil penalty liability, which could materially adversely affect our business, results of operations and financial condition.

 

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If we fail to maintain effective internal controls over financial reporting at a reasonable assurance level, we may not be able to accurately report our financial results, which could have a material adverse effect on investor confidence, our business and the trading prices of our securities.

We have established internal controls over financial reporting. However, internal controls over financial reporting may not prevent or detect misstatements or omissions in our financial statements because of their inherent limitations, including the possibility of human error, the circumvention or overriding of controls or fraud. Therefore, even effective internal controls can provide only reasonable assurance with respect to the preparation and fair presentation of financial statements. If we fail to maintain the adequacy of our internal controls, we may be unable to provide financial information in a timely and reliable manner within the time periods required for our financial reporting under SEC rules and regulations and the terms of the agreements governing our indebtedness. Any such difficulties or failure could materially adversely affect our business, results of operations and financial condition.

In connection with the preparation of our financial statements for the years ended December 31, 2013 and 2012, we identified material weaknesses in our internal controls over financial reporting. A material weakness is a deficiency, or combination of deficiencies, in internal controls over financial reporting that results in a reasonable possibility that a material misstatement of our annual or interim financial statements will not be prevented or detected on a timely basis. With respect to both the 2013 and 2012 annual financial statements, we identified material weaknesses in our internal controls related to the valuation and disclosure of our estimated proved reserves due to ineffective controls associated with the review of certain underlying data and assumptions utilized in the reserve valuation process. We also identified a material weakness related to the preparation of the cash flow statement resulting from misclassifications between operating activities and investing activities of certain transactions which were corrected in our consolidated financial statements. With respect to the 2012 annual financial statements, the identified material weaknesses also included deficiencies related to ineffective controls over manual journal entries, cash flow hedge designations and information technology general controls.

In connection with management’s evaluation of disclosure controls and procedures as of December 31, 2014, we identified certain control deficiencies we considered to be significant deficiencies in our internal control over financial reporting. A significant deficiency in internal controls is a deficiency, or combination of deficiencies, in internal control over financial reporting that is less severe than a material weakness, yet important enough to merit attention by those responsible for oversight of our financial statements. The control deficiencies related to information technology general controls, insufficient documentation related to control activities performed in connection with the preparation of our year end reserve report, and controls related to the purchase and receipt of goods and services associated with certain expenditures. No financial statement adjustments were recorded as a result of the control deficiencies.

Due to a transition period established by rules of the Securities and Exchange Commission, we have not evaluated our internal controls over financial reporting, the purpose of which would be for management to report on the effectiveness of our internal controls over financial reporting that would be needed to comply with Section 404(a) of the Sarbanes Oxley Act of 2002. However, we will be required to include a report of management’s assessment regarding internal control over financial reporting in our next annual report. As we progress towards complying with the reporting requirements associated with internal controls over financial reporting as prescribed in the Sarbanes Oxley Act of 2002, we may discover other internal control deficiencies in the future and/or fail to adequately correct previously identified control deficiencies, which could materially adversely affect our business, results of operations and financial condition.

Additionally, as a result of our March 2015 workforce reduction, we expect changes to occur in our internal controls over financial reporting. The changes could relate to different employees performing internal control activities than those who have previously performed those activities or revisions to our actual control activities as we evaluate the appropriate internal control structure after our workforce reduction. A changing internal control environment increases the risk that our system of internal controls is not designed effectively or that internal control activities will not occur as designed.

 

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Actual and potential litigation could have a material adverse effect on our business, results of operations and financial condition in future periods.

We are subject to claims arising from disputes in the normal course of business, including from third-party operators, customers, former and existing employees, vendors and other third parties. These risks may result in lawsuits or other proceedings brought against us or by us. A variety of claims or causes of action have been and may be asserted in lawsuits and proceedings, including, without limitation, contract, tort, common law and equitable claims, and may include multiple plaintiffs or seek certification of a large class of plaintiffs. These risks may be difficult to assess or quantify and their existence and magnitude may remain unknown for substantial periods of time. If the plaintiffs in any suits against us were to successfully prosecute their claims, or if we were to settle such suits by making significant payments to the plaintiffs, our business, results of operations and financial condition would be harmed. Even if the outcome of a claim proves favorable to us, litigation can be time consuming and costly and may divert management resources. If any of our directors or officers were named in any lawsuit, our indemnification obligations could magnify the costs of these suits.

Audits by governmental authorities and third parties could materially adversely affect our business, results of operations and financial condition.

We are subject, from time to time, to audits and investigations by governmental and tribal authorities regarding the payment and reporting of various taxes, governmental royalties and fees as well as our compliance with unclaimed property (escheatment) requirements and other laws. Unclaimed property laws generally require us to turn over to certain governmental authorities the property of others held by us that has been unclaimed for a specified period of time. In addition, other parties with an interest in wells operated by us have the ability under various contractual agreements to perform audits of our billing practices where we receive reimbursements from these owners for their share of the costs incurred in connection with the oil and natural gas properties that we operate. An unfavorable resolution of a claim brought pursuant to any of the foregoing could materially adversely affect our business, results of operations and financial condition.

Our operations depend on the availability of water. Limitations or restrictions on our ability to obtain, use or dispose of water may have a material adverse effect on our business, results of operations and financial condition.

Water is an essential component of drilling and hydraulic fracturing processes. Limitations or restrictions on our ability to secure sufficient amounts of water, or to dispose of water after use, could adversely impact our operations. In certain areas, water may not be available from local sources because of droughts or other factors, resulting in increased operating costs. Moreover, the introduction of new environmental initiatives and regulations related to water acquisition, waste water disposal or water recycling requirements could limit our ability to obtain or dispose of water.

In addition, concerns have been raised about the potential for earthquakes to occur from the use of underground injection control wells, a predominant method for disposing of waste water from oil and gas activities. New rules and regulations may be developed to address these concerns, possibly limiting or eliminating the ability to use disposal wells in certain locations and increasing the cost of disposal in others. We operate injection wells and utilize injection wells owned by third parties to dispose of waste water associated with our operations.

Compliance with environmental regulations and permit requirements governing the withdrawal, storage, and use of water necessary for hydraulic fracturing of wells or the disposal of water may increase our operating costs or may cause us to delay, curtail or discontinue our exploration and development plans, which could have a material adverse effect on our business, financial condition, results of operations and cash flows.

 

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Affiliates of KKR, ITOCHU and the other investors own substantially all of the equity interests in us and may have conflicts of interest with us or our other stakeholders.

As a result of the Acquisition, KKR, ITOCHU and certain other co-investors, including investment funds affiliated with Crestview Partners II GP, L.P. and Natural Gas Partners IX, L.P., indirectly own substantially all of our capital stock through our Principal Stockholders, and the Principal Stockholders’ designees hold all of the seats on our board of directors. As a result, affiliates of KKR, ITOCHU and the other investors have control over our decisions to enter into any corporate transaction and have the ability to prevent any transaction that requires the approval of stockholders regardless of whether any of our other stakeholders believe that any such transactions are in their own best interests. For example, affiliates of KKR, ITOCHU and the other investors could collectively cause us to make acquisitions that increase the amount of our indebtedness or to sell assets, or could cause us to issue additional capital stock or declare dividends. So long as these investors continue to indirectly own a significant amount of the outstanding shares of our capital stock or otherwise control a majority of our Board of Directors, affiliates of KKR, ITOCHU and the other investors will continue to be able to strongly influence or effectively control our decisions. Our debt agreements permit us, under certain circumstances, to pay advisory and other fees, pay dividends and make other restricted payments to, or otherwise enter into transactions with, KKR, ITOCHU and the other investors or their respective affiliates, and KKR, ITOCHU and the other investors or their respective affiliates may have an interest in our doing so.

Additionally, KKR, ITOCHU and the other investors are in the business of making investments in companies and may from time to time acquire and hold interests in businesses that compete directly or indirectly with us or that supply us with goods and services. KKR, ITOCHU and the other investors may also pursue acquisition opportunities that may be complementary to our business and, as a result, those acquisition opportunities may not be available to us. In addition, KKR’s, ITOCHU’s and the other investors’ interests in other portfolio companies could impact our ability to pursue acquisition and divestiture opportunities. You should carefully consider that the interests of KKR, ITOCHU and the other investors may materially conflict with or differ from the interests of our other stakeholders. See Part III, Item 12—“Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters” and Item 13—“Certain Relationships and Related Transactions, and Director Independence.”

Terrorist or cyber-attacks and threats could have a material adverse effect on our business, results of operations and financial condition.

Terrorist or cyber-attacks may significantly affect the energy industry, including our operations and those of our customers, as well as general economic conditions, consumer confidence and spending and market liquidity. Strategic targets, such as energy-related assets, may be at greater risk of future attacks than other targets in the United States. Our insurance may not protect us against such occurrences. Consequently, it is possible that any of these occurrences, or a combination of them, could have a material adverse effect on our business, results of operations and financial condition.

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

Borrowings under the RBL Revolver and the Second Lien Term Loan are at variable rates of interest and expose us to interest rate risk. Assuming all revolving loans were fully drawn under the RBL Revolver as of December 31, 2014, each quarter point change in interest rates would result in a $5.0 million change in annual interest expense on indebtedness under the RBL Revolver and the Second Lien Term Loan. We have not maintained interest rate swaps with respect to our variable rate indebtedness, and any swaps we may enter into may not fully mitigate our interest rate risk, may prove disadvantageous or may create additional risks, including the risks discussed above.

 

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ITEM 1B. UNRESOLVED STAFF COMMENTS

None.

 

ITEM 2. PROPERTIES

The information called for by this item is included in Part I, Item 1—“Business” and is incorporated herein by reference.

 

ITEM 3. LEGAL PROCEEDINGS

From time to time, we are party to various legal proceedings arising in the ordinary course of business. Although we cannot predict the outcomes of any such legal proceedings, our management believes that the resolution of currently pending legal actions will not have a material adverse effect on our business, results of operations and financial condition. For additional information, see the discussion under “Litigation and Contingencies” in Note 18 to our audited consolidated financial statements included in Part II, Item 8—“Financial Statements and Supplementary Data” of this report.

 

ITEM 4. MINE SAFETY DISCLOSURES

Not applicable.

 

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PART II

 

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

There is no public trading market for shares of our common stock, and we do not have any equity securities that are registered pursuant to Section 12 of the Exchange Act.

During 2014, we awarded a total of 10.0 million shares of restricted stock, as well as 3.7 million stock options, having an exercise price of $2.50 per share. These awards were made to certain officers and other employees of the Company pursuant to the Samson Resources Corporation 2011 Stock Incentive Plan. The awards were not registered under the Securities Act in reliance upon Section 4(a)(2) of the Securities Act, as transactions not involving a public offering, and Rule 12h-1 under the Exchange Act. For additional information regarding equity incentive awards made under the 2011 Plan, see Part III, Item 11—“Executive Compensation” and Note 14 to our audited consolidated financial statements included in Part II, Item 8—“Financial Statements and Supplementary Data” of this report.

 

ITEM 6. SELECTED FINANCIAL DATA

The following table provides selected historical consolidated financial data as of and for the periods shown. The historical consolidated financial data for the periods labeled as “Successor” reflect the accounts of Samson Resources Corporation and its subsidiaries on a consolidated basis. The historical consolidated financial data for the periods labeled as “Predecessor” reflect the accounts of our Predecessor. The balance sheet data as of December 31, 2014 and 2013 and the consolidated statements of loss and cash flow data for the Successor years ended December 31, 2014, 2013 and 2012 have been derived from our audited consolidated financial statements included in this report. The balance sheet data as of December 31, 2012 and 2011 and the consolidated statements of income (loss) and cash flow data for the Successor period from inception (November 14, 2011) through December 31, 2011 have been derived from our audited consolidated financial statements not included in this report. The balance sheet data as of June 30, 2011 and 2010 and the consolidated statements of income (loss) and cash flow data for the Predecessor period from July 1, 2011 through December 21, 2011 and the Predecessor fiscal years ended June 30, 2011 and 2010 have been derived from our Predecessor’s audited consolidated financial statements not included in this report. The historical operating results of the Company and our Predecessor are not necessarily indicative of future operating results.

We have experienced many changes in our business during the periods shown in the table below, which significantly limits the comparability of the financial data. These changes and other factors affecting comparability include, but are not limited to:

 

    the formation of Samson Resources Corporation on November 14, 2011 and the Acquisition, which occurred on December 21, 2011;

 

    the reorganization transaction made in connection with the Acquisition, which allowed the selling stockholders to retain the Gulf Coast Assets of our Predecessor;

 

    the disposition by our Predecessor of a significant portion of its oil and natural gas properties located in the Permian Basin in January 2011;

 

    our divestiture of certain Bakken properties in the Williston Basin in December 2012;

 

    our restructuring plan initiated in December 2012, which resulted in the closure of our Midland, Texas office and a reduction in force of 120 employees across the Company; and

 

    we operate on a December 31 fiscal year end, while the Predecessor operated on a June 30 fiscal year end.

 

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The following selected historical financial data should be read together with the information included under Part II, Item 7—“Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the audited consolidated financial statements and the accompanying notes of the Company included in Part II, Item 8—“Financial Statements and Supplementary Data” of this report.

 

    Successor     Predecessor  

(dollars in thousands)

  Year Ended December 31,     From
Inception
(November 14,
2011) through
December 31,
2011
    July 1, 2011
through
December 21,
2011
    Year Ended June 30,  
  2014     2013     2012         2011     2010  

Statement of income (loss) data:

             

Total revenues, net

  $ 1,177,696      $ 1,083,581      $ 1,167,940      $ 54,901      $ 838,720      $ 1,302,713      $ 1,659,179   

Impairment of oil and gas properties

    2,325,346        1,817,670        2,253,527        —         —         —         —    

Total operating expenses(1)

    3,295,133        2,800,863        3,459,207        169,870        962,540        966,754        1,017,544   

Operating income (loss)

    (2,117,437     (1,717,282     (2,291,267     (114,969     (123,820     335,959        641,635   

Net income (loss) from continuing operations

    (1,420,581     (1,105,374     (1,530,029     (73,667     (118,963     205,688        401,207   

Net income (loss)

  $ (1,420,581   $ (1,105,374   $ (1,530,029   $ (73,667   $ (118,963   $ 205,688      $ 385,067   

Statement of cash flows data:

             

Net cash provided by (used in):

             

Operating activities

  $ 487,557      $ 688,627      $ 531,864      $ (553,520   $ 410,554      $ 1,426,645      $ 1,298,600   

Investing activities

    (812,301     (764,281     (489,884     (6,897,175     (924,786     (991,092     (1,055,739

Financing activities

    347,843        73,342        (165,670     7,577,424        (95,000     (157,156     (20,138

Balance sheet data (end of period):

             

Cash and cash equivalents

  $ 23,826      $ 727      $ 3,039      $ 126,729        $ 631,632      $ 353,161   

Total property, plant and equipment, net

    5,114,384        7,040,932        8,603,426        10,894,512          4,964,665        4,643,495   

Total assets

    5,608,312        7,437,686        9,036,657        11,504,279          5,945,959        5,560,379   

Total debt (including debt classified as current)(2)

    4,107,808        3,745,035        3,648,894        3,756,503          695,000        695,000   

Shareholders’ equity

    191,525        1,512,742        2,589,986        4,074,213          2,776,108        2,867,156   

Other financial data:

             

Total capital expenditures

  $ 968,883      $ 1,080,964      $ 1,119,255      $ 2,561      $ 919,648      $ 1,587,755      $ 1,120,279   

 

(1) The total operating expenses for the Successor period from inception (November 14, 2011) through December 31, 2011 includes $137.4 million in expenses related to the Acquisition or related activities.
(2) Includes Cumulative Preferred Stock for the Successor periods presented.

 

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

You should read the following discussion and analysis in conjunction with Part II, Item 6—“Selected Financial Data” and our audited consolidated financial statements and accompanying notes included in Part II, Item 8—“Financial Statements and Supplementary Data” of this report. This discussion and analysis contains forward-looking statements regarding industry outlook, our expectations regarding our future performance, liquidity and capital resources and other non-historical statements that are based on management’s current expectations, estimates and projections about our business and operations. Our actual results may differ materially from those contained in, or implied by, any forward-looking statements. These forward-looking statements are subject to numerous risks and uncertainties, including, but not limited to, the risks and uncertainties described and referenced in Part I, Item 1A—“Risk Factors” and in the “Cautionary Statement Regarding Forward-Looking Statements” section of this report.

Overview

We are an independent oil and gas company engaged in the exploration, development and production of oil and gas properties located onshore in the United States. We operate our business and properties through our West Division, which includes properties primarily in the Rocky Mountain region, and our East Division, which includes properties primarily in the Mid-Continent and East Texas regions. At December 31, 2014, we had approximately 1.6 million net acres under lease, contract or other means of ownership and control. Our assets include a number of potential growth opportunities, including a significant amount of undeveloped properties with leases held by current production that we believe contain reserves from which we could realize value in the event of future increases in oil and natural gas prices and adequate liquidity, among other factors.

Recent Developments

In 2014 our strategic focus was evaluating our asset base for the purpose of determining which assets we considered core assets capable of supporting long-term, sustainable drilling programs with acceptable returns. For noncore assets, we pursued divestiture opportunities, or other transactions to monetize the assets. We intended to use the proceeds of any divestitures to support our capital program or increase available funds for use in acquisitions of oil and gas properties that would be complimentary to existing core assets or create a new core asset. During 2014, we received approximately $146.7 million of proceeds from sales of oil and gas properties. In December 2014, we acquired developed and undeveloped oil and gas properties to complement our acreage position in East Texas for approximately $57.6 million.

In the last half of 2014, we began actively marketing larger packages of oil and gas properties for divestiture. In the first quarter of 2015, we closed a transaction to sell properties associated with the Arkoma Basin in Oklahoma for approximately $48.0 million. We have not currently entered into agreements to divest our larger packages, including our Bakken, Wamsutter, San Juan and non-core Mid-Con assets, because we perceived the value offered was less than the value of retaining those properties when economic factors and the impact to our credit position were considered. The offer prices were impacted by the rapid decline in the market price for oil, gas, and NGLs that occurred in the fourth quarter of 2014 with continued weakness in 2015.

The significant decline in oil, gas, and NGL prices will have a material impact to our cash flows, results of operations, and liquidity position. Those declines will limit our ability to comply with restrictive covenants contained in our various credit agreements. Uncertainty regarding our liquidity and our ability to comply with restrictive covenants contained in our various credit agreements, the consequences of the uncertainty, and management’s plans to address the uncertainty are described in Note 1 to our audited consolidated financial statements included in Part II, Item 8—“Financial Statements and Supplementary Data” of this report.

In March 2015, we amended the credit agreement governing the RBL Revolver to, among other things, modify the financial performance covenant and add a restrictive covenant requiring us to maintain minimum

 

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liquidity (as defined in the credit agreement) of $150.0 million on the date of, and after giving pro forma effect to, any interest payment, subsequent to July 1, 2015, in respect of certain other indebtedness, including payments in respect of our 9.75% Senior Notes due 2020 and the Second Lien Term Loan.

As a result of declining product prices and the significant uncertainty regarding our liquidity, we have adjusted our short term strategic focus. Our 2015 capital budget does not contemplate drilling and completion activities to occur subsequent to the first quarter of 2015. In addition, in March 2015, we began implementing a plan to reduce long-term recurring operating expenses which included a reduction of approximately 30% of our workforce and initiatives to reduce other recurring general and administrative expenses and lease operating expenses. Furthermore, we have engaged advisors to assist with the evaluation of our options to address our liquidity position and strategic alternatives. The strategic alternatives may include, but not be limited to, seeking a restructuring, amendment or refinancing of our outstanding debt through a private restructuring or reorganization under Chapter 11 of the Bankruptcy Code. However, there can be no assurances that the company will be able to successfully restructure its indebtedness, improve our liquidity position, complete any strategic transactions or comply with future debt covenant requirements. For additional information, see “Liquidity and Capital Resources” section of this report.

Operating Expense Reductions

We have begun implementing a plan to lower long term, recurring operating expenses. In March 2015, we announced the reduction of approximately 30% of our workforce. We are also pursuing reductions in recurring general and administrative expenses that were not compensation related and are evaluating ways to reduce production costs in an environment where we expect declining service costs in response to changing industry conditions.

While we believe our actions will better align our cost structure with our company’s financial condition in the long term, we do expect certain increases in short term, non-recurring operating expenses associated with our cost reduction plan and the strategic initiatives described above. For example, we expect significant increases in consulting costs related to strategic advisors and increases in certain costs associated with our workforce reduction, including but not limited to: severance benefits paid pursuant to our officer retention agreements and employee severance plan (described in Notes 15 and 18 to the accompanying consolidated financial statements included in Part II, Item 8—“Financial Statements and Supplementary Data” of this report) and accelerated expense recognition of cash and stock based incentive awards. We estimate that the severance benefits to be paid in connection with the March 2015 workforce reduction (excluding any accelerated expense recognition associated with previous incentive awards) will exceed $30.0 million.

2015 Capital Budget

Our 2015 capital budget is approximately $156.5 million (excluding capitalized interest and internal costs). In addition to our 2015 capital budget, we expect to pay additional capital for amounts incurred in late 2014. Approximately 60% of our 2015 capital budget, or $93.2 million, is allocated primarily to drilling and completion activities for wells where drilling began in 2014 or early 2015. We anticipate a majority of our 2015 capital budget will be incurred during the first quarter of 2015. A significant portion of our 2015 capital budget is associated with mechanical integrity, safety and environmental compliance programs. As a result, we expect production declines will not be offset with production growth from our 2015 capital program. Production will continue to decline until it is offset with production increases attributable to a new capital program. See the “Liquidity and Capital Resources” section of this report for further discussion. Consistent with our historical practice, we periodically review our capital expenditures and adjust our capital program based on liquidity, commodity prices and expected performance. Consequently, actual capital expenditures may be more or less than amounts budgeted for 2015.

 

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Basis of Presentation

The following discussion and analysis addresses significant changes in our results of operations and capital resources for the year ended December 31, 2014 as compared to the year ended December 31, 2013, and for the year ended December 31, 2013 as compared to the year ended December 31, 2012. This section should be read in conjunction with our audited consolidated financial statements and notes included in Part II, Item 8—“Financial Statements and Supplementary Data” of this report.

Industry Trends and Uncertainties

In addition to company specific factors, our performance is generally impacted by several factors present in the oil and gas industry, including:

 

    the volatility of oil, natural gas and NGL prices;

 

    transportation capacity constraints and interruptions;

 

    the level of consumer demand and overall economic activity;

 

    the use of alternative fuels;

 

    weather conditions and the impact of weather-related events;

 

    government regulations and taxes; and

 

    world geopolitical and economic events.

For more detailed information regarding these risks, please see Part I, Item 1A— “Risk Factors.”

Source of Our Revenues

We derive substantially all of our revenues from the sale of oil, natural gas and NGLs that are produced through our interests in oil and properties. As described in Note 8 to our audited consolidated financial statements included in Part II, Item 8—“Financial Statements and Supplementary Data” of this report, we may use derivative instruments to achieve more predictable cash flows and to reduce our exposure to downward price fluctuations for oil and natural gas.

Market Conditions

Prices for our products are inherently volatile and changes in product prices can significantly impact our revenue, net loss and cash flows. The following table sets forth the average market prices for natural gas and oil for the years ended December 31, 2014, 2013 and 2012 and for the two months ended February 28, 2015:

 

     Two Months Ended
February 28, 2015
     Year Ended December 31,  
        2014      2013      2012  

Average prices:

           

Natural gas (MMBtu)(a)

   $ 3.03       $ 4.42       $ 3.65       $ 2.79   

Oil (Bbl)(b)

   $ 49.03       $ 93.00       $ 97.97       $ 94.20   

NGL (Bbl) (c)

   $ 19.58       $ 35.84       $ 36.66       $ 39.22   

Average market prices for natural gas and oil decreased significantly in the last part of 2014 with continued weakness into the first quarter of 2015. If product prices remain at levels experienced during the fourth quarter of 2014 and the first quarter of 2015 throughout 2015, we expect significantly lower revenues and operating cash flows compared to historical results. In addition, lower product prices would also result in material full cost ceiling test impairment expense in future periods.

 

(a) Based on NYMEX last day settlements.
(b) Based on NYMEX calendar month average settlements.
(c) Based on Samson’s NGL component blend utilizing OPIS daily mid-point pricing for Conway and Mont Belvieu.

 

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Results of Operations

2014 Compared to 2013 and 2013 Compared to 2012

Oil, Natural Gas and NGL Revenue

Our oil, natural gas and NGL revenues are derived from the sale of oil, natural gas and NGLs and do not include the effects of the settlements of our derivative positions. Oil, natural gas and NGL revenues are impacted by the volume of product sold and our realized price. The following table sets forth information regarding our oil, natural gas, and NGL revenues for the years ended December 31, 2014, 2013 and 2012 (in thousands):

 

    Crude Oil     Natural Gas     NGLs     Total  

Revenue for the year ended December 31, 2012

  $ 517,824      $ 387,731      $ 140,947      $ 1,046,502   

Change due to volumes

    (77,242     (89,915     21,667        (145,490

Change due to price

    53,302        197,794        (10,116     240,980   
 

 

 

   

 

 

   

 

 

   

 

 

 

Revenue for the year ended December 31, 2013

$ 493,884    $ 495,610    $ 152,498    $ 1,141,992   

Change due to volumes

  (27,981   (60,801   (266   (89,048

Change due to price

  (38,522   88,928      (6,973   43,433   
 

 

 

   

 

 

   

 

 

   

 

 

 

Revenue for the year ended December 31, 2014

$ 427,381    $ 523,737    $ 145,259    $ 1,096,377   
 

 

 

   

 

 

   

 

 

   

 

 

 

Pricing

The following table sets forth information regarding average realized sales prices for the years ended December 31, 2014, 2013 and 2012:

 

     Year Ended December 31,  
     2014      Change     2013      Change     2012  

Average realized sales prices:

            

Crude oil, unhedged ($/Bbl)

   $ 85.63         (7.3 )%    $ 92.38         10.1   $ 83.92   

Natural gas, unhedged ($/Mcf)

   $ 3.87         18.0   $ 3.28         51.2   $ 2.17   

NGLs, unhedged ($/Bbl)

   $ 31.11         (3.7 )%    $ 32.30         (7.8 )%    $ 35.03   
  

 

 

    

 

 

   

 

 

    

 

 

   

 

 

 

Average realized price, unhedged ($/Mcfe)

$ 5.68      5.2 $ 5.40      23.6 $ 4.37   
  

 

 

    

 

 

   

 

 

    

 

 

   

 

 

 

Crude oil, hedged ($/Bbl)(a)

$ 82.35      (4.6 )%  $ 86.30      5.3 $ 81.93   

Natural gas, hedged ($/Mcf)(a)

$ 3.65      8.3 $ 3.37      12.0 $ 3.01   

NGLs, hedged ($/Bbl)(a)

$ 31.03      (5.0 )%  $ 32.67      (8.9 )%  $ 35.85   
  

 

 

    

 

 

   

 

 

    

 

 

   

 

 

 

Average realized price, hedged ($/Mcfe)

$ 5.43      2.1 $ 5.32      7.5 $ 4.95   
  

 

 

    

 

 

   

 

 

    

 

 

   

 

 

 

 

(a) The effects of hedges include cash settlements for both derivatives designated as cash flow hedges and those not designated as cash flow hedges.

Natural Gas Prices

Natural gas prices are subject to variances based on local supply and demand conditions as well as rapidly evolving market conditions. A significant majority of our natural gas sales contracts are based upon index pricing that varies widely as a result of many factors, such as geography. Most of our natural gas is sold on a monthly basis using a monthly index price or a daily basis using daily market prices for a given period. Our average realized natural gas price increased for the years ended December 31, 2014 and 2013 primarily as a result of higher market pricing.

 

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We primarily utilize fixed price swaps and collars, and occasionally basis swaps, to manage our exposure to fluctuations in natural gas prices. For the years ended December 31, 2014 and 2013, approximately 82% and 83%, respectively, of our natural gas production was economically hedged with financial derivatives.

Crude Oil Prices

The majority of our crude oil production is sold at prevailing market prices, which fluctuate in response to many factors that are outside of our control. These factors include supply fluctuations, changes in demand, pipeline and refinery outages, weather patterns and global events and economics. Most of our crude oil is sold on a monthly basis based upon a variable differential to NYMEX that fluctuates as a result of regional fundamentals. Our realized crude oil price decreased for the year ended December 31, 2014 and increased for the year ended December 31, 2013 primarily as a result of these market forces.

We utilize fixed price swaps to manage our exposure to crude oil prices. For the years ended December 31, 2014 and 2013, the notional amount of our crude oil hedges exceeded our actual production. For periods subsequent to December 31, 2014, we do not expect the notional amount of our crude oil hedges to exceed our actual production.

NGL Prices

Our NGLs are sold based upon published monthly average market pricing less a deduction for transportation and fractionation. Recently, there has been significant volatility in NGL pricing. That volatility has a significant impact on our realized price for NGLs. Additionally, the market price of our NGL production, which primarily consists of ethane, propane, butane, iso-butane and natural gasoline, can be impacted by local market conditions, such as fractionation availability and business conditions of the end users of such NGL products, such as chemical companies, plastic manufacturers and propane dealers. Our average realized NGL price decreased for the years ended December 31, 2014 and 2013 as a result of decrease in overall market NGL pricing.

We utilize fixed price swaps to manage our exposure to NGL pricing. For the years ended December 31, 2014 and 2013, approximately 58% and 50% of our NGL production was economically hedged with financial derivatives.

Commodity Derivatives

We utilize commodity-based derivative instruments to manage our exposure to changes in expected future cash flows from forecasted sales of oil, natural gas and NGLs. All of our derivative activity is designed to reduce our exposure to declining prices. To the extent the future commodity price outlook declines between measurement periods, we will have mark-to-market gains, and to the extent future commodity price outlook increases between measurement periods, we will have mark-to-market losses. Changes in the fair value of derivative instruments not designated as accounting hedges are recognized in commodity derivatives, net in our consolidated statements of loss and comprehensive loss in the periods in which they occur. Accordingly, our future earnings may be volatile.

We have designated a portion of our derivatives as cash flow hedges for accounting purposes. The effective portion of changes in fair values of our derivatives designated as cash flow hedges are recorded through other comprehensive income (loss) and do not impact net income (loss) until the underlying physical transaction settles. Once the underlying physical transaction settles, the cash settlement gain or loss on the related cash flow hedge is recorded as commodity derivatives, net in our consolidated statements of loss and comprehensive loss. Any change in the fair value of cash flow hedges resulting from ineffectiveness is recognized in current earnings in commodity derivatives, net.

 

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The following table sets forth the components of the composition of our commodity derivatives, net in our consolidated statements of loss and comprehensive loss (in thousands):

 

     Year Ended December 31,  
     2014      2013      2012  

Derivative settlements:

        

Natural gas derivatives

   $ (29,952    $ 13,799       $ 138,092   

Oil derivatives

     (16,389      (32,490      (14,312

NGL derivatives

     (378      1,747         3,362   
  

 

 

    

 

 

    

 

 

 

Total settlements

  (46,719   (16,944   127,142   
  

 

 

    

 

 

    

 

 

 

Total gains (losses) on derivatives:

Natural gas derivatives

  48,633      (16,996   (77,582

Oil derivatives

  53,752      (13,449   64,737   

NGL derivatives

  10,734      (11,022   5,493   
  

 

 

    

 

 

    

 

 

 

Total gains (losses) on derivatives

  113,119      (41,467   (7,352
  

 

 

    

 

 

    

 

 

 

Ineffectiveness recorded on cash flow hedges

  14,919     —        1,648   
  

 

 

    

 

 

    

 

 

 

Total commodity derivatives, net

$ 81,319    $ (58,411 $ 121,438   
  

 

 

    

 

 

    

 

 

 

Production

The following table sets forth information regarding our average net daily production for the years ended December 31, 2014, 2013 and 2012.

 

    Year Ended December 31,     Pro Forma(a)
Excluding Bakken
Divestitures
 
    2014     Change     2013     Change     2012     2012     Change  

Production volumes:

             

Natural gas (MMcf/d):

             

West Division

             

Williston

    1.9        1.4        0.5        (2.6     3.1        —          0.5   

Powder River

    2.2        (0.1     2.3        (0.6     2.9       

Greater Green River

    30.8        (15.8     46.6        3.2        43.4       

San Juan

    80.0        (12.5     92.5        (17.4     109.9       

East Division

             

Mid-Continent West

    46.7        (4.5     51.2        (11.2     62.4       

Mid-Continent East

    70.7        0.8        69.9        (5.8     75.7       

East Texas

    136.8        (11.6     148.4        (40.3     188.7       

Other(b)

    1.3        (0.7     2.0        (0.3     2.3       
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total

  370.4      (43.0   413.4      (75.0   488.4      485.5      (72.1
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Crude oil (Bbl/d):

West Division

Williston

  3,674.7      (376.4   4,051.1      (3,873.1   7,924.2      3,236.8      814.3   

Powder River

  3,878.4      685.7      3,192.7      (28.0   3,220.7   

Greater Green River

  771.7      (196.2   967.9      353.8      614.1   

San Juan

  0.5      0.2      0.3      (0.2   0.5   

East Division

Mid-Continent West

  1,784.2      (1,317.4   3,101.6      667.2      2,434.4   

Mid-Continent East

  2,269.3      313.8      1,955.5      565.9      1,389.6   

East Texas

  1,254.1      90.1      1,164.0      91.0      1,073.0   

Other(b)

  40.6      (95.0   135.6      (55.1   190.7   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total

  13,673.5      (895.2   14,568.7      (2,278.5   16,847.2      12,159.7      2,409.0   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

 

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    Year Ended December 31,     Pro Forma(a)
Excluding Bakken
Divestitures
 
    2014     Change     2013     Change     2012     2012     Change  

NGL (Bbl/d):

             

West Division

             

Williston

    214.5        151.6        62.9        (290.5     353.4        23.5        39.4   

Powder River

    189.4        (11.5     200.9        66.1        134.8       

Greater Green River

    2,873.4        (665.0     3,538.4        1,455.1        2,083.3       

San Juan

    14.6        (19.6     34.2        11.6        22.6       

East Division

             

Mid-Continent West

    3,789.5        (142.1     3,931.6        (280.4     4,212.0       

Mid-Continent East

    2,872.0        613.9        2,258.1        283.3        1,974.8       

East Texas

    2,810.8        34.3        2,776.5        576.6        2,199.9       

Other(b)

    28.1        15.0        13.1        (0.9     14.0       
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total

  12,792.3      (23.4   12,815.7      1,820.9      10,994.8      10,664.8      2,150.9   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Combined Production (Mmcfe/d):

West Division

Williston

  25      —        25      (28   53      19.7      5.3   

Powder River

  27      4      23      —        23   

Greater Green River

  53      (21   74      14      60   

San Juan

  80      (13   93      (17   110   

East Division

Mid-Continent West

  80      (13   93      (9   102   

Mid-Continent East

  102      7      95      (1   96   

East Texas

  161      (11   172      (36   208   

Other(b)

  2      (1   3      (1   4   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total

  530      (48   578      (78   656      622.4      (44.4
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

 

(a) The production from the Williston business unit for the year ended December 31, 2012 includes production attributable to the Bakken properties divested in the fourth quarter of 2012. The pro forma information presented represents 2012 production excluding these properties.
(b) Other reflects our interests in certain non-core assets located throughout the continental United States.

Natural Gas Production

Year ended December 31, 2014—Average daily natural gas production decreased 10.4% as compared to 2013. Contributing to lower daily production volumes were divestitures primarily in our Greater Green River business unit as well as non-core assets in our East Texas business unit. Additionally, production volumes were negatively impacted by declines in base production of dry gas assets, primarily in the East Texas and San Juan business units, which were partially offset by horizontal drilling activity.

Year ended December 31, 2013—Average daily natural gas production decreased 15.4% as compared to 2012. The decrease in natural gas production volumes in 2013 compared to 2012 was attributable to natural gas declines in base production of dry gas assets due to our focus on developing liquids-rich areas during 2013.

Crude Oil Production

Year ended December 31, 2014—Average daily crude oil production decreased 6.1% as compared to 2013. Reduced drilling activity during the year resulted in lower daily production volumes as declines in base production more than offset production from new wells. Declining base production accounts for decreases in our Mid-Continent West, Williston and Greater Green River business units. Also contributing to the decrease in production were divestitures of various properties, primarily in our Williston and East Texas business units. These decreases

 

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were partially offset by new production during the year resulting from our drilling program, focusing on the Shannon and Sussex formations in the Powder River business unit, the Bakken and Three Forks formations in our Williston business unit, and the Marmaton and Mississippi formations in the Mid-Continent East business unit.

Year ended December 31, 2013—Average daily crude oil production decreased 13.5% as compared to 2012 as a result of the divestiture of certain Williston properties in the fourth quarter of 2012. The production decrease from the divestiture was offset by increases in oil production from new wells completed in late 2012 and in 2013 in our Mid-Continent East, Mid-Continent West and Greater Green River business units.

NGL Production

Year ended December 31, 2014—Average daily NGL production decreased less than 1.0% as compared to 2013. The decrease was attributable to declines in base production from wells in our Greater Green River, East Texas, and Mid-Continent West business units but was offset by new production due to drilling activity in our Williston, East Texas and Mid-Continent East business units.

Year ended December 31, 2013—Average daily NGL production increased 16.6% as compared to 2012. The increase was attributable to our focus during 2013 on developing liquids-rich areas that contain wet natural gas, which allowed for higher recoveries of NGLs. NGL production increased in the Mid-Continent East, East Texas and Greater Green River business units as a result of new wells completed in late 2012 and in 2013.

Operating Expenses

The following tables set forth information regarding operating expenses for the years ended December 31, 2014, 2013 and 2012 (in thousands, except per unit data):

 

     Year Ended December 31,  
     2014      2013      2012  

Operating expenses:

        

Lease operating

   $ 210,161       $ 195,918       $ 222,597   

Production and ad valorem taxes

     78,453         76,256         82,651   

Depreciation, depletion and amortization

     478,740         554,010         677,978   

Impairment of oil and gas properties

     2,325,346         1,817,670         2,253,527   

Asset retirement obligation accretion

     4,752         4,704         4,643   

Restructuring charges

     —           —           46,643   

Related party management fee

     22,050         21,000         20,000   

General and administrative

     175,631         131,305         151,168   
  

 

 

    

 

 

    

 

 

 

Total operating expenses

$ 3,295,133    $ 2,800,863    $ 3,459,207   
  

 

 

    

 

 

    

 

 

 

 

     Year Ended December 31,  
     2014      2013      2012  

Average cost per unit of combined production ($ per Mcfe):

        

Production costs:

        

Lease operating expense(1)

   $ 1.09       $ 0.93       $ 0.93   

Production and ad valorem taxes

     0.41         0.36         0.34   
  

 

 

    

 

 

    

 

 

 

Total production cost per unit

$ 1.50    $ 1.29    $ 1.27   
  

 

 

    

 

 

    

 

 

 

Depreciation, depletion and amortization

$ 2.48    $ 2.65    $ 2.84   

General and administrative expenses(2)

$ 0.91    $ 0.62    $ 0.63   

 

(1) Includes stock based compensation expense of $0.03 and $0.02 for the years ended December 31, 2014 and 2013, respectively.
(2) Includes stock based compensation expense of $0.27, $0.12 and $0.15 for the years ended December 31, 2014, 2013 and 2012, respectively.

 

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Lease operating expenses (“LOE”). LOE increased $14.2 million in 2014 as compared to 2013. On a per unit basis, LOE per Mcfe increased $0.16 in 2014 as compared to 2013. The increase in LOE from 2013 primarily related to increased relative production in business units with higher production costs as well as increases in maintenance and workover expenses as a result of our production optimization efforts.

LOE decreased $26.7 million in 2013 as compared to 2012. On a per unit basis, there was no change in LOE per Mcfe in 2013 as compared to 2012. The decrease in LOE from 2012 was attributable to a decrease in total production of 29.1 Bcfe, which decreased lease operating expenses as we shifted our drilling focus to areas containing a higher mix of oil and natural gas liquids. The divestitures of the Bakken properties in the fourth quarter of 2012 impacted our oil production and contributed $14.3 million of the total decrease in lease operating expenses for 2013.

Production and ad valorem taxes. Production and ad valorem taxes increased $2.2 million in 2014 as compared to 2013. The increase in expense for the twelve months ended December 31, 2014 resulted from a reduction of ad valorem tax expense recorded in the first quarter of 2013 to reflect actual property tax assessments that were less than previous estimates as well as severance tax incentives received throughout the year of 2013. On a per unit basis, production and ad valorem taxes increased by $0.05 per Mcfe in 2014, as compared to 2013 primarily as a result of higher realized pricing and ad valorem tax adjustments to reflect property tax assessments.

Production and ad valorem taxes decreased $6.4 million in 2013 as compared to 2012. The decrease in expense in 2013 resulted from a reduction of ad valorem tax expense recorded in the first quarter of 2013 to reflect actual property tax assessments that were less than previous estimates. On a per unit basis, production and ad valorem taxes increased by $0.02 per Mcfe in 2013, as compared to 2012 as a result of higher realized pricing for natural gas and crude oil. Higher average realized pricing for natural gas and crude oil was offset by decreases in production of these products as compared to 2012, resulting in lower total production and ad valorem tax expense.

Depreciation, depletion and amortization expense. Depreciation, depletion and amortization expense decreased $75.3 million in 2014 as compared to 2013 and decreased $124.0 million in 2013 as compared to 2012 primarily due to ceiling test impairments recorded during 2013 and 2012 of approximately $1.8 billion and $2.3 billion, respectively. A ceiling test impairment lowers the overall depletion base for subsequent periods. The decrease in 2014 and 2013 also resulted from lower overall production as compared to the prior year end. On a per unit basis, depreciation, depletion and amortization expense decreased by $0.17 in 2014, as compared to 2013, and decreased by $0.19 in 2013, as compared to 2012, as a result of lower total proved reserve volumes as compared to the prior year end.

Impairment of oil and gas properties. We recorded pre-tax impairment expense related to our oil and gas properties for the years ended December 31, 2014, 2013 and 2012 of $2.3 billion, $1.8 billion and $2.3 billion, respectively, as a result of our full-cost ceiling test. Under the full cost method, we are subject to quarterly calculations of a ceiling or limitation on the amount of costs associated with our oil and gas properties that can be capitalized in our consolidated balance sheets. Contributing to the impairment expense for the years ended December 31, 2014, 2013 and 2012 were impairments of our unproved properties of approximately $1.7 billion, $1.6 billion and $1.3 billion, respectively, as well as changes to the value of our proved reserves used in our ceiling test calculation. For further information regarding full cost ceiling tests, refer to Note 1 to our consolidated financial statements included in Part II, Item 8—“Financial Statements and Supplementary Data” of this report and our discussions under “Critical Accounting Policies, Practices and Estimates”.

Related party management fee. We have an agreement with affiliates of our initial equity investors pursuant to which we receive management services and incur a quarterly management fee to our private equity sponsors. In accordance with the agreement, the management fee increases 5% on an annual basis. The related party management fee increased $1.1 million and $1.0 million during the years ended December 31, 2014 and 2013, respectively.

 

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Restructuring charges. Restructuring charges primarily relate to severance costs paid in December 2012 associated with a workforce reduction pursuant to employee change of control agreements. No restructuring charges were incurred during the years ended December 31, 2014 or 2013.

General and administrative expenses. The following table illustrates the changes in certain categories of general and administrative expenses for the periods presented (in thousands):

 

     Year Ended December 31,  
     2014      2013      2012  

Cash incentive compensation

   $ 7,524       $ —         $ —     

Officer retention awards

     6,431         —           —     

Other stock based compensation

     44,875         24,799         35,606   

Other general and administrative expenses

     116,801         106,506         115,562   
  

 

 

    

 

 

    

 

 

 

Total general and administrative expenses

$ 175,631    $ 131,305    $ 151,168   
  

 

 

    

 

 

    

 

 

 

During the year ended December 31, 2014, cash incentive compensation increased due to the granting of awards beginning in April 2014 and an acceleration of vesting of certain awards that occurred on September 1, 2014. The officer retention awards were approved in the third quarter of 2014. The increase in other stock based compensation during 2014 primarily relates to the modification of outstanding stock options and the issuance of new restricted stock that occurred in the first quarter of 2014, which increased stock compensation expense by $16.1 million for 2014 as compared to 2013. Other general and administrative expenses increased $10.3 million in 2014 as compared to 2013. Contributing to the increase in 2014 was an increase in expense of approximately $2.2 million related to employer contributions for 401(k) matching in the first quarter of 2014, higher compensation expenses of approximately $1.0 million associated with the repurchase of puttable common stock in the first quarter of 2014 and a decrease in certain cost recoveries associated with operated properties of approximately $5.9 million. For additional information, see Note 14 to the accompanying consolidated financial statements included in Part II, Item 8—“Financial Statements and Supplementary Data” of this report.

General and administrative expenses decreased in 2013 compared to 2012 due in part to a decrease in stock compensation expenses of $11.1 million. The decrease in stock compensation expense resulted primarily from accelerated vesting that occurred in 2012 in connection with the reduction in workforce described in Note 15 to the accompanying consolidated financial statements included in Part II, Item 8—“Financial Statements and Supplementary Data” of this report. Contributing to the decrease in other general and administrative expenses in 2013 were reduced expenses associated with certain licencing fees of approximately $4.5 million and reduced transaction costs. The decreases in other general and administrative expenses were also due to a decrease in cash compensation expense of approximately $5.7 million. The decrease in cash compensation expense related to an increase of $8.2 million of severance costs recorded as general and administrative expenses in 2013 whereas severance related costs for 2012 were recorded as restructuring charges, which was offset by decreases in wages and bonuses of approximately $13.9 million resulting from the reduction in workforce that occurred in December 2012.

Interest expense. Interest expense increased $91.9 million in 2014 as compared to 2013. Our interest expense is the difference between our total interest cost and the amount of interest we capitalize during a period. The amount of interest capitalized is based on the amount of unproved property balances that relate to ongoing development activities. Total interest cost before capitalization was $335.0 million, $341.7 million and $279.7 million for the years ended December 31, 2014, 2013 and 2012, respectively. We capitalized interest costs to unproved oil and gas properties of $243.1 million, $341.7 million and $279.7 million during the years ended December 31, 2014, 2013 and 2012, respectively. The increase in total interest cost for the years ended December 31, 2014 and 2013 was the result of additional interest on the Senior Notes, which we began to incur in May 2013 pursuant to the terms of the registration rights agreement relating to the Senior Notes. The decrease in the amount of interest capitalized in 2014 results from lower unproved property balances associated with ongoing development activities.

 

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Income tax provision. Income tax benefit was $789.5 million, $614.0 million and $805.9 million for the years ended December 31, 2014, 2013 and 2012, respectively. The decrease in the income tax benefit for the years ended December 31, 2014 and 2013 is due to the difference in pre-tax loss between the periods. The effective income tax rate for the years ended December 31, 2014 and 2013 was approximately 36% and approximately 35% for the year ended December 31, 2012. Realization of our deferred tax assets is dependent upon generating sufficient future taxable income and considers the reversing effects of our deferred tax liabilities. Although realization is not assured, we believe it is more likely than not that the deferred tax assets will be realized.

Liquidity and Capital Resources

The following table summarizes factors affecting our liquidity at (in thousands):

 

     February 28,
2015
     December 31,
2014
     December 31,
2013
     December 31,
2012
 

Cash and cash equivalents

   $ 220,704       $ 23,826       $ 727       $ 3,039   

Net working capital, including debt classified as current

   $ (4,114,052    $ (4,030,296    $ (314,974    $ (364,331

Net working capital, excluding debt classified as current

   $ 128,948       $ (125,296    $ (314,974    $ (364,331

Total long-term debt

   $ —         $ —         $ 3,554,000       $ 3,475,000   

Cumulative preferred stock subject to mandatory redemption

   $ 205,513       $ 202,808       $ 191,035       $ 173,894   

Available borrowing capacity under RBL Revolver

   $ 4,979       $ 343,384       $ 1,473,819       $ 1,553,904   

As of March 18, 2015, borrowings under our RBL Revolver were $947.0 million, excluding outstanding letters of credit, and we had no available borrowing capacity.

Short-term liquidity

We have historically funded our operations with operating cash flow, borrowings under our various credit facilities, and asset sales. Our most significant cash outlays relate to our capital program, current period operating expenses, payments under various incentive plans, severance related costs, and our debt service obligations described in Notes 10, 14, 15 and 18 in the accompanying consolidated financial statements included in Part II, Item 8—“Financial Statements and Supplementary Data” of this report.

The market price for oil, natural gas, and NGLs decreased significantly during the fourth quarter of 2014 with continued weakness into the first quarter of 2015. The decrease in the market price for our production directly reduces our revenues and operating cash flow. We use derivative financial instruments to reduce our exposure to fluctuations in the prices of oil, natural gas and NGLs. The following table summarizes our hedging position associated with 2015 and 2016 production as of December 31, 2014:

 

     Percent of estimated 2015
production hedged
    Weighted average hedged
price for existing hedges
 
     2015     2016     2015      2016  

Oil

     30     —        $ 90.91/Bbl         —     

Natural gas

     59     61   $ 4.05/MMBtu       $ 4.04/MMBtu   

NGLs

     8     —        $ 37.07/Bbl         —     

Our 2015 hedging program will reduce the potential effects of lower cash flows from operations due to decreases in product prices on the portion of production hedged for 2015.

 

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In addition, the decrease in the market price for our production indirectly impacts our other sources of potential liquidity described above. Lower market prices for our production may result in lower borrowing capacity under our revolving credit facility or higher borrowing costs from other potential sources of debt financing as our borrowing capacity and borrowing costs are generally related to the value of our estimated proved reserves. The weakness in product pricing may also impact our ability to negotiate asset sales at acceptable prices.

We also have substantial debt service obligations over the next several months. In addition to monthly interest payments associated with borrowings outstanding on our RBL Revolver, we are required to pay approximately $110.0 million in interest on our Senior Notes on each of February 15 and August 15 and approximately $12.5 million in interest on our Second Lien Term Loan at the end of each fiscal quarter.

In addition, declining industry conditions and company performance reduces the likelihood that we comply with certain restrictive covenants contained in our credit facilities, which potentially can have severe consequences to our liquidity. Violation of certain restrictive covenants can result in costly waivers or amendments to agreements governing our credit facilities or an acceleration of repayment obligations for outstanding borrowings. In March 2015, we amended the credit agreement governing the RBL Revolver to, among other things, modify the financial performance covenant to provide that we maintain a ratio of consolidated first lien debt to consolidated EBITDA of not more than 2.75 to 1.0 as of the end of each fiscal quarter beginning with the first quarter of 2015 through and including the third quarter of 2015. The consolidated first lien debt to consolidated EBITDA ratio reverts back to 1.5 to 1.0 at the end of the fourth quarter of 2015. Beginning with the first quarter of 2016, the credit agreement requires us to maintain a ratio of consolidated total debt to consolidated EBITDA of not more than 4.5 to 1.0 as of the end of each fiscal quarter through maturity. Prior to the March 2015 amendment, the financial performance covenant required us to maintain a ratio of first lien debt to consolidated EBITDA of not more than 1.50 to 1.0 for all of 2015 and a ratio of consolidated total debt to consolidated EBITDA of not more than 4.5 to 1.0 beginning with the first quarter 2016. In addition, the March 2015 amendment added a restrictive covenant requiring us to maintain, subsequent to July 1, 2015, minimum liquidity (as defined in the credit agreement) of $150.0 million on the date of, and after giving pro forma effect to, any interest payment, in respect of certain other indebtedness, including payments in respect of our 9.75% Senior Notes due in 2020 and the second lien term loan credit facility entered into by our subsidiary, Samson Investment Company and waived the restriction on the inclusion of an explanatory paragraph regarding our ability to continue as a going concern in our auditor’s report for 2014. In addition, the March 2015 amendment lowered the borrowing base of our RBL Revolver to $950.0 million and we used $46.0 million of cash on hand to repay amounts outstanding on the RBL Revolver on the amendment date. The March 2015 amendment also increased the collateral coverage minimum (as defined in the credit agreement) to at least 95% of the discounted present value of the Company’s and its restricted subsidiaries proved reserves.

Unless the financial performance covenant and/or the liquidity covenant are amended further, or we are successful in implementing one of the strategic alternatives discussed below, we do not expect to remain in compliance with all of our restrictive covenants contained in agreements governing our credit facilities for all of 2015 or 2016. Consequently, an acceleration of repayments of outstanding borrowings may occur. As a result of the uncertainty regarding our compliance with our restricted covenants, our long-term debt with maturities summarized in Note 10 to our consolidated financial statements are reflected as a current liability in our consolidated balance sheet at December 31, 2014. If an acceleration of repayments of outstanding borrowings were to occur, we may not have access to funding sources sufficient to repay our outstanding obligations. Conditions that are considered an event of default that may result in an acceleration of maturities under our various credit agreements are listed in Part I, Item 1A—“Risk Factors” contained elsewhere in this report.

We have begun implementing plans designed to improve our liquidity. We have reduced our 2015 capital budget, developed plans to reduce long-term recurring operating expenses, and are continuing our efforts to sell certain non-core assets. However, the terms of the RBL Revolver, our Second Lien Term Loan and the indenture governing our Senior Notes require that some or all of the proceeds from certain asset sales be used to

 

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permanently reduce outstanding debt which could substantially reduce the amount of proceeds we retain. The covenants in the RBL Revolver, our Second Lien Term Loan and indenture governing our Senior Notes impose limitations on the amount and type of additional indebtedness we can incur, which may significantly reduce our ability to obtain liquidity through the incurrence of additional indebtedness. Additionally, our ability to refinance any of our existing indebtedness on commercially reasonable terms may be materially and adversely impacted by the current conditions in the energy industry and our financial condition. As a result, we expect declining sales volumes as natural production declines will not be offset with production growth from our 2015 capital program.

Even if we are successful at reducing our costs and increasing our liquidity through asset sales, we do not expect to have sufficient liquidity to satisfy our debt service obligations, meet other financial obligations, and comply with restrictive covenants contained in our various credit facilities. We have engaged financial and legal advisors to assist us in, among other things, analyzing various strategic alternatives to address our liquidity and capital structure. We have received multiple preliminary proposals to provide additional secured financing, as well as an exchange offer and combined financing proposal from certain of our existing bondholders. We do not currently believe that any of these preliminary proposals provide a long term solution to our capital structure challenges or otherwise adequately address our leverage and liquidity constraints, but we intend to continue to explore additional strategic and refinancing alternatives through a private restructuring. However, a filing under Chapter 11 of the U.S. Bankruptcy Code may provide the most expeditious manner in which to effect a capital structure solution. There can be no assurance that we will be able to restructure our capital structure on terms acceptable to us or our financial creditors, or at all.

Cash and Cash Equivalents

All cash is denominated in U.S. dollars and, at times, is invested in highly liquid, investment-grade securities with maturities of three months or less at the time of purchase.

Net Working Capital

Net working capital is the difference between our current assets and our current liabilities. At February 28, 2015, our net working capital, including debt classified as current, was $(4.1) billion. Our most significant current assets include cash on hand of $220.7 million, accounts receivable of $171.5 million, and net derivative assets of $119.9 million. Our accounts receivable balance includes outstanding joint interest billings to other working interest owners in wells we operate and an accrual for our share of revenue associated with product sales that occurred prior to February 28, 2015. The value of our derivative assets are based on the forward market prices for oil, natural gas, and NGLs at February 28, 2015. Actual cash settlements will be more or less than the value of our derivative assets at period end based on changes in the market value of oil, natural gas, and NGLs through the settlement date of the derivative financial instruments.

At February 28, 2015, our net working capital includes an amount of current liabilities of $4.2 billion associated with our long-term debt with maturities summarized in Note 10 to our consolidated financial statements. Our long-term debt is classified as current at February 28, 2015 due to uncertainty regarding our compliance with certain restrictive covenants contained in our credit facilities. Our other significant current liabilities include accounts payable of $90.2 million and accrued liabilities of $200.1 million. Accounts payable represents the amount of invoices we have processed for payment as of a particular date. Accrued liabilities represent an accrual for expenses or capital expenditures incurred as of a particular date which is not reflected in accounts payable. Our most significant items included in accrued liabilities relate to accrued operating expenses, accrued capital expenditures, accrued long term incentive payments and other employee retention programs, and accrued interest associated with outstanding borrowings under our RBL Revolver, Second Lien Term Loans, and Senior Notes.

 

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Debt

At December 31, 2014, total outstanding debt was approximately $3.9 billion, which excludes approximately $202.8 million of our Cumulative Preferred Stock. Our total debt consists of three separate financing arrangements: the RBL Revolver, which at December 31, 2014, had a total borrowing capacity of approximately $1.0 billion and outstanding borrowings of $655.0 million; our Senior Notes, which were issued in 2012 for an aggregate principal amount of $2.25 billion; and our Second Lien Term Loan, under which we have borrowed an aggregate principal amount of $1.0 billion. The maturities, interest costs, expected interest payments, and restrictive covenants associated with all of our debt is summarized in Note 10 to our consolidated financial statements included in Part II, Item 8—“Financial Statements and Supplementary Data” of this report.

In March 2015, we amended the credit agreement governing the RBL Revolver to, among other things, modify the financial performance covenant to provide that we maintain a ratio of consolidated first lien debt to consolidated EBITDA of not more than 2.75 to 1.0 as of the end of each fiscal quarter beginning with the first quarter of 2015 through and including the third quarter of 2015, at which point the first lien debt to consolidated EBITDA ratio reverts back to 1.5 to 1.0 at the end of the fourth quarter of 2015 and beginning with the first quarter of 2016, we are required to maintain a ratio of consolidated total debt to consolidated EBITDA of not more than 4.5 to 1.0 as of the end of each fiscal quarter through maturity. Prior to the March 2015 amendment, the financial performance covenant required us to maintain a ratio of first lien debt to consolidated EBITDA of not more than 1.50 to 1.0 for all of 2015 and a ratio of consolidated total debt to consolidated EBITDA of not more than 4.5 to 1.0 beginning with the first quarter 2016. In addition, the March 2015 amendment added a restrictive covenant requiring us to maintain minimum liquidity (as defined in the credit agreement) of $150.0 million on the date of, and after giving pro forma effect to, any interest payment, subsequent to July 1, 2015, in respect of certain other indebtedness, including payments in respect of our 9.75% Senior Notes due 2020 and the second lien term loan credit facility entered into by our subsidiary, Samson Investment Company and waived the inclusion of an explanatory paragraph regarding our ability to continue as a going concern in our auditor’s report for 2014. In addition, the March 2015 amendment lowered the borrowing base of our RBL Revolver to $950.0 million and we used $46.0 million of cash on hand to repay amounts outstanding on the RBL Revolver on the amendment date. The March 2015 amendment also increased the collateral coverage minimum (as defined in the credit agreement) to at least 95% of the discounted present value of our restricted subsidiaries proved reserves.

As described above, the financial performance covenant in the credit agreement governing the RBL Revolver requires us to operate within established financial ratios. In addition, the March 2015 amendment to the credit agreement governing the RBL Revolver requires us to maintain a certain liquidity on the date of certain interest payments made subsequent to July 1, 2015. Our ability to comply with these covenants depends upon our performance and indebtedness, each of which is impacted by numerous factors, including some that are outside of our control. Accordingly, forecasting our compliance with the financial performance and liquidity covenants in future periods is inherently uncertain. Factors that could impact our future compliance with the financial performance and liquidity covenant include future realized prices for the sales of oil, natural gas and natural gas liquids, future production, returns generated by our capital program, future interest costs, future operating costs, future asset sales, and future acquisitions, among others. For example, asset sales could impact our near-term future performance by reducing our production and reserves and, for purposes of calculating compliance with the financial performance covenant, could reduce our consolidated EBITDA on a pro forma historical basis. Moreover, many of these factors could also decrease our total proved reserves and thereby may result in a reduction to our borrowing base under the RBL Revolver, which could adversely impact our liquidity and ability to meet future obligations.

Unless the financial performance covenant and/or the liquidity covenants are amended further, we do not expect to remain in compliance with all of our restrictive covenants contained in the credit agreement governing the RBL Revolver for all of 2015 or into 2016. Collectively, the negative impacts to our liquidity resulting from declining industry conditions and increased uncertainty regarding our ability to comply with restrictive covenants

 

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in our credit facilities raises substantial doubt about our ability to continue as a going concern as of December 31, 2014 as described in Note 1 to our consolidated financial statements included in Part II, Item 8—“Financial Statements and Supplementary Data” of this report.

As market conditions warrant and subject to our contractual restrictions, liquidity position and other factors, we, our affiliates and/or our equity investors and their respective affiliates, may from time to time seek to repurchase our outstanding debt, including the Senior Notes and Second Lien Term Loan debt, in open market transactions or privately negotiated transactions, by tender offer or otherwise. The amounts involved in any such transactions, individually or in the aggregate, may be material. Further, any such repurchases may result in our acquiring and retiring a substantial amount of such indebtedness, which would impact the trading liquidity of such indebtedness.

Cumulative Preferred Stock Subject to Mandatory Redemption

Our preferred stock is recorded at its redemption value. The preferred stock is redeemable at our option at any time and is mandatorily redeemable on the earliest to occur of July 1, 2022, or the consummation of an initial public equity offering or a change of control.

Contractual Obligations

Our contractual obligations include long-term debt, interest expense on debt, drilling commitments, derivatives, the Cumulative Preferred Stock, officer retention agreements, cash incentive awards and other operating lease obligations, marketing commitments and non-cancelable equipment purchases. The table below summarizes the maturity dates of our contractual obligations at December 31, 2014 (in thousands):

 

     Payments Due by Period  
     Total      Less than
1 Year
     1-3 Years      3-5 Years      More than
5 Years
 

Long-term debt(a)

              

Principal

   $ 3,905,000       $ —        $ 655,000       $ 1,000,000       $ 2,250,000   

Interest

     1,338,695         283,597         551,704         475,972         27,422   

Drilling commitments(b)

     12,473         12,473         —           —           —     

Derivatives

     5,790         5,790         —           —           —     

Cumulative preferred stock subject to mandatory redemption

              

Principal(c)

     202,808         —           —           —           202,808   

Interest(c)

     182,528         16,225        44,618        48,674         73,011   

Officer retention agreements

     28,153         28,153         —           —           —     

Cash incentive awards

     12,933         12,933         —           —           —     

Other operating leases

     58,674         7,032         13,662         12,839         25,141   

Related party management fee(d)

     188,509         23,153         49,836         54,944         60,576   

Marketing commitments(e)

     86,830         7,074         19,846         24,076         35,834   

Equipment purchases(f)

     7,566         7,566         —           —           —     
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total

$ 6,029,959    $ 403,996    $ 1,334,666    $ 1,616,505    $ 2,674,792   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

 

(a)

Principal payments are based on contractual maturities of our long-term debt. As described in Note 1 to our consolidated financial statements, our long-term debt is classified as a current liability in our consolidated balance sheet at December 31, 2014 due to uncertainty regarding our compliance with certain restrictive covenants contained in our credit facilities. Cash interest expense on our RBL Revolver is estimated assuming (i) a principal balance outstanding equal to the balance at December 31, 2014 of $655.0 million with no principal repayment until the instrument due date of December 21, 2016 and (ii) a fixed interest rate of 2.17%,

 

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  which was our interest rate at December 31, 2014. Cash interest expense on our Second Lien Term Loan is estimated assuming a fixed interest rate of 5.0%, which was our interest rate at December 31, 2014.
(b) Subsequent to December 31, 2014, we terminated approximately $12.5 million of remaining drilling rig commitments and incurred rig termination fees of approximately $5.2 million as a result.
(c) The Cumulative Preferred Stock is recorded at its redemption value. As of December 31, 2014 the redemption value is approximately $202.8 million. The Cumulative Preferred Stock is redeemable at our option at any time and is mandatorily redeemable on the earliest to occur of July 1, 2022, or the consummation of an initial public equity offering or a change of control. The contractual obligation for the Cumulative Preferred Stock as of December 31, 2014 is calculated using an estimated redemption date of July 1, 2022 and assumes future payments of interest are made in cash. Additionally, the Cumulative Preferred Stock accrues dividends quarterly at a specified per annum dividend rate. Dividends can be in cash or in-kind at the Company’s election. Dividends not paid in cash are cumulative and accrue and compound quarterly. If dividends are paid in kind, consistent with historical practice, then the timing of cash outlays will be delayed to coincide with the redemption date of the Cumulative Preferred Stock.
(d) The agreement providing for the related party management fee, which has a ten year term, will also terminate (i) automatically immediately following the consummation of an initial public offering (unless we elect to continue the agreement) and (ii) at our election, in connection with certain sales of shares of our common stock held by our principal stockholders. If the agreement is terminated under such circumstances, then we must pay a termination fee based on the net present value of future payment obligations under the agreement. In March 2015, the shareholders consented to the extension of time for the payment of the quarterly management fee until the earlier of (i) September 30, 2015 and (ii) such time as the shareholders determine to reinstate such payment as described in Part III, Item 13—“Certain Relationships and Related Transactions, and Director Independence.” The payment schedule above reflects the fees incurred each period. The March 2015 extension does not change the amount of management fee incurred pursuant to the consulting agreement.
(e) Includes firm transportation and throughput commitments with midstream service companies and pipeline carriers for future gathering and transportation of natural gas to move our production to market. These and other commitments related to gathering and transportation agreements are not recorded in the accompanying consolidated balance sheets. Excluded from the contractual obligations table above are liabilities associated with asset retirement obligations, which totaled $75.7 million as of December 31, 2014. The ultimate settlement and timing cannot be precisely determined in advance.
(f) For the next twelve months, we have non-cancelable commitments to purchase approximately $7.6 million of new tubular and related equipment, including inspection and transportation costs, for drilling and completion projects.

Off-Balance Sheet Arrangements

We do not currently utilize any off-balance sheet arrangements with unconsolidated entities to enhance our liquidity and capital resource positions or for any other purpose. However, as is customary in the oil and gas industry, we have various contractual work commitments and letters of credit as described in Note 18 to the consolidated financial statements included in Part II, Item 8—“Financial Statements and Supplementary Data” of this report.

Capital Expenditures

Total capital expenditures, including acquisitions, capitalized direct internal costs and interest paid, were approximately $968.9 million for the year ended December 31, 2014. Substantially all of our expenditures, excluding interest paid, relate to the acquisition and development of our oil and gas properties with the remaining expenditures relating primarily to the acquisition and construction of facilities used to support our operational requirements. Our capital expenditures include interest and direct internal costs that are capitalized and increase the basis of our oil and gas properties.

 

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Due to the significant decline in commodity prices and our evaluation of our short term liquidity, we decided to discontinue drilling and completion activity after the first quarter of 2015, which will significantly lower our 2015 capital budget from recent spending levels. The following table summarizes our capital budget for the year ended December 31, 2015, excluding capitalized interest paid (in thousands):

 

     2015
Capital Budget
 

Drilling and completion:

  

West Division

   $ 52,500   

East Division

     40,700   
  

 

 

 

Total drilling and completion

  93,200   
  

 

 

 

Leasehold, geological and geophysical

  11,500   

Related field facilities, corporate and other

  51,800   
  

 

 

 

Total capital budget, excluding capitalized direct internal costs and interest paid(1)

$ 156,500   
  

 

 

 

 

(1) Amount does not include capital that was incurred in 2014 but expected to be paid in 2015 of approximately $100.0 million to $110.0 million.

The following table sets forth information regarding capital expenditures for the year ended December 31, 2014 (in thousands):

 

Drilling and completion

$ 558,076   

Tubular oil and gas equipment, prepaid drilling costs and other

  36,005   
  

 

 

 

Total drilling and completion

  594,081   

Leasehold, geological and geophysical

  13,460   

Related field facilities, corporate and other

  27,500   
  

 

 

 

Total

  635,041   

Capitalized interest paid

  245,366   

Capitalized direct internal costs

  30,845   
  

 

 

 

Total capital expenditures excluding acquisitions

  911,252   

Acquisitions

  57,631   
  

 

 

 

Total capital expenditures

$ 968,883   
  

 

 

 

We primarily fund our capital expenditures with our cash flows generated by operations, borrowings under our RBL Revolver or Second Lien Term Loans, and proceeds from asset sales. The actual amount and timing of our expenditures may differ materially from our estimates as a result of actual drilling results, the timing of expenditures by third parties on projects that we do not operate the availability of drilling rigs and other services and equipment, regulatory, technological and competitive developments and market conditions, among other factors. In addition, under certain circumstances we will consider adjusting or reallocating our capital spending plans.

Property acquisitions in 2014 shown above include the cash paid for the Goodrich Acquisition described in Note 2 to the accompanying consolidated financial statements included in Part II, Item 8—“Financial Statements and Supplementary Data” of this report.

Divestitures of Oil and Gas Properties

We have historically utilized proceeds from sales of oil and gas properties to supplement other sources of cash to cover our expenditures. For the years ended December 31, 2014, 2013 and 2012, we received total

 

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proceeds of approximately $156.6 million, $316.7 million, and $735.0 million from sales of oil and gas properties and other property and equipment. Our recent divestiture activity is summarized below:

2015 Divestitures

In the first quarter of 2015, we received approximately $48.0 million from sales of oil and gas properties in the Arkoma basin.

2014 Divestitures

For the year ended December 31, 2014, we had divestitures of oil and gas properties in various regions and received total additional proceeds of approximately $146.7 million.

2013 Divestitures

In June 2013, we completed the sale of certain oil and gas properties in the Permian Basin for approximately $68.0 million.

In September 2013, we completed the sale of certain oil and gas properties in the Trail Unit of Wyoming’s Vermillion Basin for approximately $106.7 million.

For the year ended December 31, 2013, we had additional divestitures of oil and gas properties in various regions and received total additional proceeds of approximately $136.9 million.

2012 Divestitures

In December 2012, we closed a transaction in which we sold certain Bakken producing and undeveloped properties in North Dakota, for approximately $650.0 million plus certain customary post-closing adjustments. Also in December 2012, we closed a transaction with a separate counterparty to sell certain Bakken producing and undeveloped properties for $30.0 million plus certain customary post-closing adjustments.

Sources and Uses of Cash

The following table summarizes our net change in cash and cash equivalents for the periods shown (in thousands):

 

     Year Ended December 31,  
     2014      2013      2012  

Operating activities

   $ 487,557       $ 688,627       $ 531,864   

Investing activities

     (812,301      (764,281      (489,884

Financing activities

     347,843         73,342         (165,670
  

 

 

    

 

 

    

 

 

 

Net change in cash

$ 23,099    $ (2,312 $ (123,690
  

 

 

    

 

 

    

 

 

 

Cash flows from operating activities. Cash flows from operating activities decreased $201.1 million for the year ended December 31, 2014 as compared to the year ended December 31, 2013. The decrease in cash flows from operating activities was primarily the result of a decrease in oil, natural gas and NGL sales of $45.6 million, increased cash expenses for lease operating and general and administrative costs of $13.1 million and $17.8 million, respectively, as well as an increase in cash payments for settled derivatives of $51.6 million, all as compared to the year ended December 31, 2013. Cash flows from operating activities were also impacted by a decrease in oil and gas revenues held for distribution of $24.4 million, as compared to the year ended December 31, 2013. Additionally, a reduction in our capitalized cash interest expense decreased operating cash flows by $58.4 million during the year ended December 31, 2014.

 

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Cash flows from operating activities increased $156.8 million for the year ended December 31, 2013 as compared to the year ended December 31, 2012. The increase in cash flows from operating activities was primarily the result of an increase of $95.5 million related to oil, natural gas and NGL sales and a decrease in lease operating expenses of $26.7 million. Additionally, 2013 benefitted from the absence of approximately $41.0 million in restructuring costs that were paid in 2012.

Cash flows used in investing activities. Cash flows used in investing activities increased $48.0 million for the year ended December 31, 2014 as compared to the year ended December 31, 2013. The increase in cash flows used in investing activities was primarily the result of a decrease in proceeds from divestitures of oil and gas properties of $160.1 million and an increase in acquisitions of oil and gas properties of $57.6 million partially offset by a decrease in capital expenditures for oil and gas properties and other property and equipment of $169.7 million, all as compared to the year ended December 31, 2013.

Cash flows used in investing activities increased $274.4 million for the year ended December 31, 2013 as compared to the year ended December 31, 2012. The increase in cash flows used in investing activities was primarily the result of a decrease in proceeds from divestitures of $423.4 million. During 2012, total divestitures of oil and gas properties were approximately $735.0 million as compared to total divestitures during 2013 of $311.6 million. The 2012 divestitures included large Bakken divestitures in the fourth quarter totaling $680.0 million. Capital expenditures, including cash paid for the purchase of the Predecessor business, decreased $147.7 million from 2012 as a result of our focus on drilling and completion capital and constrained spending on leasehold, geological and geophysical projects as well as a decrease in cash paid for the Acquisition of $109.5 million.

Cash flows from financing activities. Cash flows from financing activities increased $274.5 million for the year ended December 31, 2014 as compared to the year ended December 31, 2013. The increase in cash flows provided by financing activities was primarily the result of an increase in net borrowings under the RBL Revolver of $272.0 million as compared to the year ended December 31, 2013. Borrowings under the RBL Revolver are primarily utilized to fund our capital expenditures as well as for general corporate purposes.

During the year ended December 31, 2013 and the year ended December 31, 2012 we completed the following significant activities:

 

    During 2013, our payments on our RBL Revolver were $1.2 billion lower than during 2012. We used substantially all of the proceeds from the Second Lien Term Loan and the large divestitures that occurred in the fourth quarter of 2012 to pay down outstanding borrowings on our RBL Revolver.

 

    During the year ended December 31, 2012, we issued $2.25 billion in aggregate principal amount of Senior Notes and utilized those proceeds to repay the Bridge Facility. We incurred approximately $51.9 million of debt issuance costs during the year ended December 31, 2012 associated with the Senior Notes offering and the issuance of the Second Lien Term Loan.

Critical Accounting Policies, Practices and Estimates

Accounting policies that we consider significant are summarized in Note 1 to the accompanying consolidated financial statements included in Part II, Item 8—“Financial Statements and Supplementary Data” of this report. Certain accounting policies require management to make critical accounting estimates. Accounting estimates are considered to be critical if (a) the nature of the estimates and assumptions involves a high degree of subjectivity and judgment concerning uncertain matters or such matters are subject to future changes and (b) the impact of the estimates and assumptions on our financial position or results of operations is material. Additional information regarding how our critical accounting estimates are determined and the subjectivity of those estimates is provided below.

 

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Oil and Gas Properties

Accounting for oil and gas properties using the full cost method of accounting requires management to make estimates which have a material impact on the Company’s financial position and results of operations as they determine the carrying amount of our proved and unproved oil and gas properties, the amount of depletion expense recorded, and the amount of impairment expense recorded pursuant to the full cost ceiling limitation (if any). We believe the following to be critical accounting estimates associated with our application of the full cost method of accounting for our oil and gas properties:

 

    Proved reserves—Proved oil and natural gas reserves are defined by the SEC as the estimated quantities of oil and natural gas reserves that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs based on the unweighted average first-day-of-the-month commodity prices for the prior twelve months, adjusted for market differentials and under period-end economic and operating conditions. The process of estimating quantities of proved reserves is complex, requiring subjective decisions in the evaluation of all geological, engineering and economic data for each reservoir. The data for a given reservoir may change substantially over time as a result of numerous factors including additional development activity and evolving production history. Changes in oil, natural gas and NGL prices, operating costs and expected performance from a given reservoir also will result in future revisions to the amount of our estimated proved reserves. Reserve estimates are updated at least annually. Changes to our proved reserves are summarized in Note 23 to our accompanying consolidated financial statements included in Part II, Item 8—“Financial Statements and Supplementary Data” of this report. Future additions of proved reserves are also directly impacted by the size and success of our capital program.

All reserve information in this report is based on estimates prepared by our petroleum engineering staff or obtained from a third party reserve engineering firm engaged to report on our company’s proved reserves. The subjective nature of reserve estimation increases the likelihood of significant changes in these estimates in future periods as new information becomes available. Any significant changes could have a material impact on future depletion expense and full cost ceiling impairment expense. Assuming a 5% change of estimated proved reserves results in a corresponding change in estimated future net revenues associated with proved reserves (discounted at 10%), such change would impact our full cost ceiling impairment expense for the year ended December 31, 2014 by approximately $128.4 million.

 

    Future development costs of proved undeveloped reserves—An input to our periodic depletion calculation and our full cost ceiling limitation is our estimate of future development costs associated with proved undeveloped reserves. Costs associated with our drilling and completion activities can change quickly as market conditions change. A 10% change in our estimated future development costs would impact our annual depletion expense by approximately $6.0 million and our full cost ceiling limitation at December 31, 2014 by approximately $22.1 million.

 

    Allocations of costs to the depletion base—Costs associated with unproved properties are excluded from our depletion base until proved reserves are established for undeveloped locations or wells are drilled. At that time, costs are moved from unproved properties to proved properties in our consolidated balance sheet and become subject to periodic depletion. The amount of costs transferred is determined based on our estimate of the total number of wells expected to be drilled for a particular geographically defined area. If our estimate of the total number of wells expected to be drilled decreases, then the amount allocated to proved properties for each future well drilled increases. Our estimates of drilling locations are derived from internal reserve reports identifying proved, probable, and possible drilling locations. Significant changes to our estimated drilling locations can have a material impact on future depletion expense or our full cost ceiling impairment expense. For the year ended December 31, 2014, a 10% change in our unproved property allocations associated with these estimated drilling locations would impact our depletion base by $18.0 million with a corresponding change to our full cost ceiling limitation.

 

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In addition, costs associated with unproved properties are also transferred to our depletion base, which also reduces our full cost ceiling limitation, when those properties are considered impaired. The effect of impairments to our unproved property is higher future depletion expense and potentially higher full cost ceiling impairment expense. Our decision to impair unproved properties is based primarily on evaluating factors that result in a higher degree of uncertainty regarding our future development plans for our unproved property. Future development plans can be impacted by general market conditions, our financial condition, planned asset sales, or new information gathered concerning the economic viability of developing a particular unproved property.

At December 31, 2014, we have approximately $2.1 billion of unproved property costs excluded from our depletion base. A significant portion of our unproved property relates to value assigned to unproved property in connection with the acquisition of our company in December 2011 and the capitalization of interest cost subsequent to the acquisition. Approximately 64% of our unproved property balance relates to our largest two geographically defined potential development areas, whereas our largest 10 geographically defined potential development areas comprise 89% of our unproved property balance. Our assessment of our unproved properties is a continuous process. Within the last three years we have recorded material impairments as we refine our capital deployment plans and establish the strategic direction for our company. Total impairments of unproved property balances for the years ended December 31, 2014, 2013, and 2012 were $1.7 billion, $1.6 billion, and $1.3 billion, respectively. Changes to our assessment of the uncertainty regarding future development plans, particularly with respect to areas having the largest unproved property balances, would have material impact to our reported earnings through higher depletion expense or full cost ceiling impairment expense.

 

    Pricing used to calculate the full cost ceiling limitation—Although the pricing used to estimate the future net revenues from proved properties (discounted at 10%) is prescribed by rules governing the full cost method of accounting for oil and gas properties, changes in prices can materially impact the determination of impairment expense (if any) for a particular period. For example, a 10% decline in prices of oil, natural gas and natural gas liquids used in determining the full cost ceiling limitation would have increased pre-tax impairment expense by approximately $460.2 million for the year ended December 31, 2014. Currently, forward prices are significantly lower than the pricing used to calculate the full cost ceiling limitation at December 31, 2014. If prices remain at current levels, we expect continuing material full cost ceiling test impairment expense in 2015. The following table summarizes the pricing used to determine the full cost ceiling limitation for the periods presented:

 

     December 31,  
     2014      2013      2012  

Oil (per barrel)(a)

   $ 94.99       $ 96.91       $ 94.71   

Natural gas (per MMBtu)(a)

   $ 4.35       $ 3.67       $ 2.76   

NGLs (per barrel)

   $ 33.46       $ 34.47       $ 38.15   

 

(a) Before adjustment for market differentials.

Capitalized Interest

Our interest expense is the difference between our total interest cost and the amount of interest we capitalize during a period. The amount of interest capitalized is based on the amount of unproved property balances that relate to ongoing development activities. Our total interest cost incurred in 2014 was $335.0 million, of which $296.9 million was cash interest expense associated with our outstanding debt. Of the total interest cost incurred, $243.1 million was capitalized and $91.9 million was recorded as interest expense. The material impairments recorded for our unproved property balances in recent years decreases the amount of interest cost capitalized for future periods. In addition, our 2015 capital budget does not contemplate any drilling or completion activity after the first quarter. We expect reduced unproved property balances and limited development activity will result in material reductions in the amount of interest cost capitalized, which in turn will result in material increases to our interest expense in 2015 compared to historical periods.

 

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Capitalized Internal Costs

We capitalize internal costs directly related to exploration or development activities associated with our oil and gas properties. During the years ended December 31, 2014, 2013, and 2012, we capitalized internal costs of approximately $30.8 million, $37.6 million, and $35.8 million, respectively. The amount we capitalize is based on our estimate of employee time spent on exploration or development activity for a particular period. Our 2015 capital budget does not contemplate drilling and completion activities beyond the first quarter of 2015. Consequently, we expect the amount of internal costs capitalized to decrease significantly in 2015.

Asset Retirement Obligations

We have obligations to remove tangible equipment and restore land at the end of oil and natural gas production operations. Removal and restoration obligations are primarily associated with plugging and abandoning wells. We develop estimates of these costs for each of our significant areas of operation based upon their geographic type, type of production structure, reservoir depth and characteristics, and currently available information. Because these costs typically extend many years into the future, estimating these future costs is difficult and requires management to make judgments that are subject to future revisions based upon numerous factors, including changing technology and the political and regulatory environment. We review our assumptions and estimates of future asset retirement obligations on an annual basis, or more frequently, if an event occurs or circumstances change that would affect our assumptions and estimates. Because of the subjectivity of assumptions and the relatively long lives of most of our wells, the costs to ultimately retire our wells may vary significantly from prior estimates.

The accounting guidance for asset retirement obligations requires that a liability for the present value of estimated future retirement obligations be recorded in the period in which it is incurred and the corresponding cost capitalized by increasing the carrying amount of the related long-lived asset. The liability is accreted to its new present value each period, and the capitalized cost becomes part of the depletion base for our oil and gas properties. Holding all other factors constant, if our estimate of asset retirement obligations is revised upward, earnings would decrease due to higher DD&A expense or higher full cost ceiling impairment expense. In addition, the amount of liability recorded for our asset retirement obligation is significantly impacted by our estimate of when the liability will be settled because of the discounting that occurs to reflect the liability at the present value of the future obligation. If we change our estimate of the timing of when each asset retirement obligation is settled by increasing or decreasing the expected settlement date by 3 years, the present value of our asset retirement obligation would decrease $(17.3) million and increase $19.9 million, respectively, at December 31, 2014.

Commodity Derivative Activities

A summary of our outstanding derivative financial instruments is included in Note 8 to the accompanying consolidated financial statements included in Part II, Item 8—“Financial Statements and Supplementary Data” of this report. Critical accounting estimates associated with our accounting for derivative financial instruments include estimates associated with determining the fair value of those instruments at period end.

The estimated fair value of our swap contracts is primarily based on contractual terms and forward commodity prices. The fair value of our natural gas collars are based on option pricing models which consider the contractual terms, forward commodity prices, and the volatility of natural gas. The credit worthiness of the parties to the derivative contracts also impacts our estimate of the fair value of those contracts. Assuming all other factors are held constant, a 10% change in estimated forward commodity prices would result in an impact of $57.3 million to the estimated fair value of our derivative financial instruments at December 31, 2014. The market price for oil, natural gas, and natural gas liquids is highly volatile. The volatility results in material changes to our reported revenues for a particular period. For example, we recorded $81.3 million, $(58.4) million, and $121.4 million of revenues associated with our derivative financial instruments for the years ended December 31, 2014, 2013 and 2012.

 

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Stock-Based Compensation

Compensation expense associated with granted stock options and restricted stock is determined based on our estimate of the fair value of those awards at the initial grant or upon modification. The fair value of restricted stock is based on our estimate of the fair value of an unrestricted share of common stock, adjusted for a lack of marketability discount. We utilize the Black-Scholes-Merton option pricing model to measure the fair value of stock options. Key inputs used in the option pricing model include the risk-free interest rate, the fair value and expected volatility of underlying stock, and the expected life of the award. Key assumptions used in measuring stock compensation expense are included in Note 14 to the accompanying consolidated financial statements included in Part II, Item 8—“Financial Statements and Supplementary Data” of this report.

Our estimate of the fair value of the Company’s common stock has a material impact on the determination of stock compensation expense and is difficult to estimate with a high degree of certainty because our common stock is not publically traded and we have not sold any shares of common stock in private transactions subsequent to the initial formation of the Company. We utilize internal models to estimate the fair value of our common stock. Those models consider company specific financial and operational data as well as publically available information about other companies operating within our industry. Equity valuations in our industry can change rapidly with changing market conditions.

The compensation expense we recognize associated with our stock options and restricted stock is net of estimated forfeitures. We estimate our forfeiture rate based on prior experience and adjust it as circumstances warrant. For the year ended December 31, 2014, a 10% change in the estimated grant date fair value of our outstanding stock options and restricted stock would have changed our stock compensation expense for the period by approximately $5.6 million.

Income Taxes

When recording income tax expense, certain estimates are required because income tax returns are generally filed many months after the close of a calendar year, tax returns are subject to future audits, and future events often impact the timing of when income tax expenses and benefits are recognized. We have deferred tax assets relating to tax operating loss carryforwards and other deductible temporary differences. We routinely evaluate deferred tax assets to determine the likelihood of realization. If we determine that it is more likely than not that our deferred tax assets will not be realized, we must record a valuation allowance to reduce the carrying value of our deferred tax assets. Our assessment includes estimating our future taxable income to determine if our operating loss carryforwards will be utilized before expiration. Numerous assumptions are inherent in the estimation of future taxable income, including assumptions about matters that are dependent on future events such as future operating results (which are impacted by prevailing natural gas, oil and NGL prices and our forecasted production levels). In addition, we have certain income tax elections available to us which can increase our taxable income in future periods. Those elections include an election to reduce our current deduction for certain intangible drilling costs.

In addition, we are required to consider the reversal of taxable temporary differences (deferred tax liabilities) when assessing the need for a potential valuation allowance against our deferred tax assets. Our primary taxable temporary difference relates to the difference between the carrying amount of our oil and gas properties and the tax basis of those properties. Our deferred tax liabilities associated with our oil and gas properties are reduced when we record full cost ceiling impairments and periodic depletion expense.

At December 31, 2014, we have deferred tax assets of approximately $515.0 million associated with net operating loss carryforwards totaling $1.5 billion. No valuation allowance was recorded at December 31, 2014 related to our deferred tax assets in part because we have future taxable temporary differences (deferred tax liabilities) that exceed the amount of our deferred tax assets by $765.3 million. We expect the excess of our deferred tax liabilities over our deferred tax assets to be reduced over time as we record full cost ceiling impairments and periodic depletion expense. This is particularly true in periods where we have reduced capital

 

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budgets as capital expenditures have the potential for increasing our deferred tax liabilities because of tax elections available to us related to certain intangible drilling costs. If we conclude in future periods that it is more likely than not that some of our deferred tax assets will not be realized, we would record a valuation allowance against our deferred tax asset and our deferred tax expense would increase.

Contingent Liabilities

A provision for legal, environmental and other contingent matters is charged to expense when the loss is probable and the cost or range of cost can be reasonably estimated. Judgment is often required to determine when expenses should be recorded for legal, environmental and contingent matters and is required to reasonably estimate recorded expenses when appropriate. In many cases, our judgment is based on the input of our legal advisors and on the interpretation of laws and regulations, which can be interpreted differently by regulators and/or the courts. Actual costs can differ from estimates for many reasons. We monitor known and potential legal, environmental and other contingent matters and make our best estimate of when to record losses for these matters based on available information. As new information becomes available as a result of activities in such matters, legal or administrative rulings in similar matters, or a change in applicable law, our conclusions regarding the probability of outcomes and potential exposure may change. The impact of subsequent changes to our estimates and accruals may have a material effect on our results of operations in a single period. At December 31, 2014, our accrual for loss contingencies approximated $12.2 million.

Related Party Transactions

For a discussion of related party transactions, see Part III, Item 13—“Certain Relationships and Related Transactions, and Director Independence” and Note 20 to our audited consolidated financial statements included in Part II, Item 8—“Financial Statements and Supplementary Data” of this report in this report.

Recent Accounting Pronouncements

In August 2014, the Financial Accounting Standards Board (“FASB”) issued ASU 2014-15 “Presentation of Financial Statements—Going Concern.” ASU 2014-15 provides guidance around management’s responsibility to evaluate whether there is substantial doubt about an entity’s ability to continue as a going concern and to provide related footnote disclosures. ASU 2014-15 is effective for our annual period ending after December 15, 2016, and for all annual and interim periods thereafter. Early application is permitted. We have not determined when we will adopt ASU 2014-15 or the impact the new standard will have on our consolidated financial statements. Upon adoption, we will be required to consider whether there are adverse conditions or events that raise substantial doubt about the Company’s ability to continue as a going concern within one year after the date that the financial statements are issued and the probability that management’s plans will mitigate the adverse conditions or events (if any). Adverse conditions or events would include, but not be limited to, negative financial trends (such as recurring operating losses, working capital deficiencies, or insufficient liquidity), a need to restructure outstanding debt to avoid default, and industry developments (for example commodity price declines and regulatory changes).

In May 2014, the FASB issued ASU 2014-09 “Revenue from Contracts with Customers.” ASU 2014-09 creates a comprehensive framework for the recognition of revenue. ASU 2014-09 requires an entity to (i) identify the contract(s) with a customer, (ii) identify the performance obligations in the contract(s), (iii) determine the transaction price, (iv) allocate the transaction price to the performance obligations in the contract(s), and (v) recognize revenue when, or as, the entity satisfies a performance obligation. ASU 2014-09 is effective beginning on January 1, 2017 for public entities. We are currently evaluating the potential impact of ASU 2014-09 on our consolidated financial statements.

 

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ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

The primary objective of the following information is to provide quantitative and qualitative information about our potential exposure to market risk. The term “market risk” refers to the risk of loss arising from adverse changes in oil, natural gas and NGL prices and interest rates. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of how we view and manage our ongoing market risk exposures.

Commodity Price Exposure

Our revenues and associated cash flows are dependent on the prices we receive for our crude oil, natural gas and NGLs, which can be volatile because of unpredictable events such as economic circumstances, weather, and political climate, among others. We periodically enter into derivative positions on a portion of our projected oil, natural gas, and NGL production to manage fluctuations in cash flows resulting from changes in commodity prices. All of our market risk sensitive instruments were entered into for risk mitigation purposes, rather than for speculative trading.

At December 31, 2014, we had open natural gas derivatives, crude oil and NGL derivatives in an asset position with a combined fair value of $151.7 million. A ten percent increase in natural gas, crude oil and NGL prices would decrease the asset position by approximately $57.3 million. See Note 8 to our consolidated financial statements, included in Part II, Item 8—“Financial Statements and Supplementary Data” of this report, for notional volumes and terms associated with the Company’s derivative contracts.

Interest Rate Risk

Under our RBL Revolver and Second Lien Term Loan, we have debt which bears interest at a floating rate. For the year ended December 31, 2014, the weighted average interest rates on our RBL Revolver and Second Lien Term Loan were 2.1% and 5.1%, respectively. Assuming all revolving loans are fully drawn under the RBL Revolver, each quarter point increase in interest rates would result in a $5.0 million increase in annual interest cost, before capitalization.

Exchange Rate Risk

All of our transactions are denominated in U.S. dollars, and as a result, we do not currently have exposure to currency exchange-rate risks.

Credit Risk

Cash and cash equivalents are not insured above FDIC insurance limits, causing us to be subject to risk. Accounts receivable are primarily due from other companies within the oil and natural gas industry. A portion of the receivables are due from major oil and natural gas purchasers with which we have large natural offsets between revenues and joint interest billings. We do not generally require collateral related to these receivables; however, cash prepayments and letters of credit are requested for accounts with indicated credit risk. All of our derivative exposure is with banks that are lenders under our RBL Revolver or their respective affiliates.

 

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

The Company’s audited consolidated financial statements required by this item are included in this report beginning on page F-1.

 

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

None.

 

ITEM 9A. CONTROLS AND PROCEDURES

Management’s Evaluation of Disclosure Controls and Procedures. As required by Rule 15d-15(b) under the Securities Exchange Act of 1934, as amended (the “Exchange Act”), management has evaluated, with the participation of our principal executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of December 31, 2014. Our disclosure controls and procedures are controls and procedures that we have designed to ensure that the information required to be disclosed by us in reports that we file under the Exchange Act is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure and is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC. All internal control systems, no matter how well designed, have inherent limitations. Therefore, even those determined to be effective can provide only a level of reasonable assurance with respect to the financial statement preparation and presentation. Based upon the evaluation, our principal executive officer and principal financial officer have concluded that our disclosure controls and procedures were effective as of December 31, 2014 at the reasonable assurance level.

Changes in Internal Control over Financial Reporting. We had previously identified a material weakness in our internal control over financial reporting in connection with the preparation of our financial statements for the year ended December 31, 2013 related to the valuation and disclosure of our estimated proved reserves. The material weakness was due to ineffective controls associated with the review of certain underlying data and assumptions used in reserve valuation and disclosures. In response to the previously identified material weakness, we strengthened our internal controls associated with reserve valuation and disclosure for the year ended December 31, 2014 by implementing enhanced management review and data validation procedures associated with underlying data and assumptions used in reserve valuation and disclosures. In addition, we began transacting with our newly implemented enterprise resource planning system in January 2014, which resulted in conforming adjustments to certain internal control processes throughout 2014. Except for the aforementioned changes, there were no changes in our internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) that occurred during the three months ended December 31, 2014 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

This Annual Report on Form 10-K does not include a report of management’s assessment regarding internal control over financial reporting or an attestation report of Samson’s independent registered public accounting firm due to a transition period established by SEC rules for newly public companies. A report of management’s assessment regarding internal control over financial reporting is not required until we file our annual report for the year ended December 31, 2015.

 

ITEM 9B. OTHER INFORMATION

None.

 

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PART III

 

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

The Boards of Directors of Samson Investment Company and Samson Resources Corporation supervise our management and the general course of our affairs and business operations. Except as otherwise noted below, the individuals comprising the directors and executive officers of Samson Investment Company and Samson Resources Corporation are identical, with each such individual serving in the same capacity for both companies. Unless the context otherwise requires, in this report, references to the “Board of Directors,” “our Board” or like terms refer to the Boards of Directors of Samson Investment Company and Samson Resources Corporation collectively.

The following table sets forth certain information regarding the directors and executive officers of Samson Resources Corporation and Samson Investment Company as of March 31, 2015, as well as the committee memberships of the Board of Directors of Samson Resources Corporation. The ages stated below are as of March 31, 2015.

 

Name

  Age  

Office and Position

Randy L. Limbacher

  56   Chief Executive Officer, President, Director and Member of Executive Committee

Philip W. Cook

  53   Executive Vice President and Chief Financial Officer

Richard E. Fraley

  57   Executive Vice President and Chief Operating Officer

Andrew C. Kidd

  52   Senior Vice President and General Counsel

Julia C. Gwaltney

  43   Vice President—West Division

Robert W. Jackson

  51   Vice President—Information Services and Technology

John L. Sharp

  55   Vice President—Exploration and New Ventures

Brian A. Trimble

  39   Vice President and Chief Accounting Officer

Sean C. Woolverton

  45   Vice President—East Division

Robert V. Delaney, Jr.

  57   Director and Member of Audit,* Compensation and Executive Committees

Claire S. Farley

  56   Director and Member of Compensation and Executive Committees

Brandon A. Freiman

  33   Director and Member of Audit Committee

Toshiyuki Mori

  52   Director and Member of Compensation and Executive Committees

David C. Rockecharlie

  43   Director and Member of Audit Committee

Jonathan D. Smidt

  42   Director and Member of Compensation* and Executive Committees

Akihiro Watanabe

  56   Director and Member of Audit Committee

 

* Indicates Chairman of the respective Committee of the Board of Directors of Samson Resources Corporation.

Officers and Directors

Randy L. Limbacher

Mr. Limbacher joined Samson in April 2013. He serves as a director and as Chief Executive Officer and President of Samson Resources Corporation and is a member of the Company’s Executive Team. From November 2007 to February 2013, Mr. Limbacher served as Chief Executive Officer, President and director of Rosetta Resources Inc. (“Rosetta”), a public independent oil and natural gas exploration and development company. Beginning in February 2010, Mr. Limbacher also served as Chairman of the Board of Directors of Rosetta. From February 2013 to April 2013, Mr. Limbacher was a non-officer employee of Rosetta. Prior to joining Rosetta, Mr. Limbacher served as President, Exploration and Production—Americas for ConocoPhillips, where he was responsible for all exploration and production activities of that company in the Western Hemisphere. Mr. Limbacher joined ConocoPhillips as part of its April 2006 acquisition of Burlington Resources Inc. (“Burlington”), an oil and natural gas exploration and production company, where he spent over 20 years. At Burlington, Mr. Limbacher held a series of positions of increasing responsibility, including his role at the time of the acquisition by ConocoPhillips of Executive Vice President, Chief Operating Officer and as a director on the Board of Directors of Burlington. Mr. Limbacher serves on the Board of Directors of CARBO Ceramics Inc. He holds a Bachelor of Science degree in Petroleum Engineering from Louisiana State University.

 

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As the Chief Executive Officer and President of Samson, Mr. Limbacher provides a management representative on the Board of Directors with knowledge of the day-to-day operations of the Company obtained as a result of his role. Accordingly, he can facilitate the Board’s access to timely and relevant information and its oversight of management’s strategy, planning and performance. In addition, Mr. Limbacher brings to the Board considerable management and leadership experience and extensive knowledge of the oil and natural gas industry and of our business gained during his over 30-year career in the exploration and production business.

Philip W. Cook

Mr. Cook joined Samson in April 2012. He is Executive Vice President and Chief Financial Officer of Samson Resources Corporation and serves on the Company’s Executive Team. From October 2005 to joining Samson in April 2012, Mr. Cook served as Executive Vice President and Chief Financial Officer for Quicksilver Resources, Inc., a public independent oil and natural gas exploration and production company. From September 2011 to April 2012, Mr. Cook also served as a director of Crestwood Gas Services GP LLC, the general partner of Crestwood Midstream Partners LP, a publicly-traded master limited partnership engaged in oil and natural gas midstream operations. Prior to joining Quicksilver Resources, Inc., Mr. Cook served as the chief financial officer for other private energy companies and held various executive positions at Burlington. Mr. Cook holds a CPA and a Bachelor’s degree in Accounting from New Mexico State University.

Richard E. Fraley

Mr. Fraley joined Samson in July 2013. He is Executive Vice President and Chief Operating Officer of Samson Resources Corporation and serves on the Company’s Executive Team. From March 2013 to July 2013, Mr. Fraley served as a managing director for the Energy Mezzanine Opportunities Fund, focusing on upstream and midstream oil and natural gas investment opportunities, for The Carlyle Group, a global alternative asset management firm. Prior to joining The Carlyle Group, Mr. Fraley was an oil and natural gas consultant from July 2007 through February 2013. Beginning in February 1986, Mr. Fraley was with Burlington, where he held officer level positions, including Chief Engineer and Vice President of International Operations. He subsequently oversaw Burlington’s largest operating division in the San Juan Basin, a role which he continued with ConocoPhillips, after its acquisition of Burlington, until June 2007. Prior to Burlington, Mr. Fraley was employed by Superior Oil Company and Mobil Corporation for six years. Mr. Fraley has over 30 years of experience in the oil and natural gas industry and received his Bachelor of Science degree in Geological Engineering from Colorado School of Mines.

Andrew C. Kidd

Mr. Kidd joined Samson in September 2013. He is Senior Vice President and General Counsel of Samson Resources Corporation and serves on the Company’s Executive Team. Prior to joining Samson, he served as Partner and General Counsel of Anthem Energy, a private investment manager that develops and operates energy investments, from March 2009 to October 2010 and from October 2011 to August 2013. During October 2010 through September 2011, Mr. Kidd was Senior Vice President and General Counsel of Quantum Utility Generation, LLC, a power generation asset operator. From August 2004 to December 2008, Mr. Kidd was with Constellation Energy Group, Inc. (“CEG”), serving in various positions, including Deputy General Counsel of CEG, General Counsel of Constellation Energy Resources, the business organization representing CEG’s customer supply, global commodities and portfolio management activities, and a member of the Board of Managers of Constellation Energy Partners LLC, a publicly traded exploration and production company that was previously sponsored by CEG. Mr. Kidd also served as a consultant for CEG from December 2008 to March 2009. Earlier in his career, he served as Senior Vice President and Deputy General Counsel of El Paso Corporation and held various officer level positions at Covanta Energy, Inc. Mr. Kidd received his Bachelor of Arts degree from Dartmouth College and his Juris Doctorate degree from the University of Maryland School of Law.

 

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Julia C. Gwaltney

Ms. Gwaltney joined Samson in April 2014. She is Vice President—West Division of Samson Resources Company and certain of our other operating subsidiaries. Prior to joining Samson, Ms. Gwaltney was with Encana Oil and Gas (USA) Inc., the U.S. subsidiary for a public North American energy producer, for the past 14 years and held a series of positions of increasing responsibility, including Vice President and General Manager, Western Operations. Earlier in her career, Ms. Gwaltney served in various engineering roles with Burlington. Ms. Gwaltney holds a Bachelor of Science degree in Petroleum Engineering from Colorado School of Mines.

Robert W. Jackson

Mr. Jackson joined Samson in May 2012. He is Vice President—Information Services and Technology of Samson Resources Corporation. Prior to joining Samson, he was the Director of Enterprise Architecture & Strategy at Quicksilver Resources, Inc. from May 2007 to May 2012. Earlier in his career, Mr. Jackson held a series of positions of increasing responsibility with Burlington and ConocoPhillips (after its acquisition of Burlington), including Director of Enterprise IT Application. Mr. Jackson received his Bachelor of Science degree in Computer Science from New Mexico State University.

John L. Sharp

Mr. Sharp joined Samson in October 2014. He is Vice President—Exploration and New Ventures of Samson Resources Company and certain of our other operating subsidiaries. Prior to joining Samson, Mr. Sharp served as Vice President—Asset Development of HighMount Exploration & Production LLC, a private oil and gas company, from March 2014 to September 2014. From 2010 to 2013, Mr. Sharp held positions of increasing responsibility with Chesapeake Energy Corporation, a public independent exploration and development oil and natural gas company, including Vice President—Geoscience, Southern Division, where he oversaw the geoscience activity of its Haynesville and Barnett Shale assets. From September 2013 to March 2014, Mr. Sharp was on leave after departing Chesapeake. Earlier in his career, he held various technical and managerial positions at other oil and gas companies, including Marathon Oil Corporation and Transfuel Resources Company. Mr. Sharp received his Bachelor of Science and Master of Science degrees from the University of Arkansas.

Brian A. Trimble

Mr. Trimble joined Samson in October 2012. He is Vice President and Chief Accounting Officer of Samson Resources Corporation. From June 2002 through September 2012, Mr. Trimble was with the Tulsa office of Grant Thornton LLP, an independent audit, tax and advisory firm. During that period, he was an audit partner (August 2008 through September 2012) and audit practice leader for the Tulsa office (October 2011 until September 2012). Mr. Trimble’s audit clients included many large public energy companies. Mr. Trimble received his Bachelor of Accountancy degree from the University of Oklahoma and is a Certified Public Accountant.

Sean C. Woolverton

Mr. Woolverton joined Samson in November 2013. He is Vice President—East Division of Samson Resources Company and certain of our other operating subsidiaries. From April 2007 to October 2013, Mr. Woolverton held a series of positions of increasing responsibility at Chesapeake Energy Corporation, a public independent exploration and development oil and natural gas company, including Vice President of its Southern Appalachia business unit. Prior to joining Chesapeake Energy Corporation, Mr. Woolverton worked for Encana Corporation, a North American oil and natural gas producer, where he oversaw its Fort Worth Basin development and shale exploration teams in North Texas from April 2006 through April 2007. Earlier in his career, Mr. Woolverton worked for Burlington in multiple senior staff engineering and managing roles. Mr. Woolverton received his Bachelor of Science degree in Petroleum Engineering from Montana Tech.

 

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Robert V. Delaney, Jr.

Mr. Delaney was named a director of Samson Resources Corporation in December 2011 and is a Partner at Crestview Partners. Mr. Delaney leads the firm’s energy investing efforts. Prior to joining Crestview Partners in 2007, Mr. Delaney was a Partner at Goldman Sachs & Co. where he served in a variety of leadership positions in private equity and investment banking, including head of the private equity business in Asia and head of the global leveraged finance group. Mr. Delaney received a Master of Business Administration, with high distinction, from Harvard Business School where he was a Baker Scholar. Mr. Delaney also holds a Master of Science degree in Accounting from the Stern School of Business at New York University, and a Bachelor of Arts degree in Economics from Hamilton College, summa cum laude, where he was elected to Phi Beta Kappa. Mr. Delaney also serves on the boards of directors of Select Energy Services, Silver Creek Oil & Gas, Synergy Energy Holdings and CP Energy. The Board of Directors believes Mr. Delaney’s senior leadership positions at Crestview Partners and Goldman Sachs & Co., his exceptional educational background and his service on multiple boards of directors provide him the requisite experience necessary to serve as a director.

Claire S. Farley

Ms. Farley was named a director of Samson Resources Corporation in December 2011 and previously served as our interim Chief Executive Officer and President from February 2013 to April 2013. Ms. Farley is a member of KKR Management LLC, the general partner of KKR & Co. L.P., and was a Managing Director of KKR’s energy and infrastructure group from November 2011 to December 2012. Prior to joining KKR, from September 2010 to October 2011, Ms. Farley co-founded and was with RPM Energy, LLC, which partnered with KKR to invest in unconventional oil and gas resources. Prior to co-founding RPM Energy, LLC, Ms. Farley was an advisory director at Jefferies Randall & Dewey, the global oil and natural gas industry advisory group at Jefferies Group, Inc., from August 2008 to September 2010 and was Co-President of Jefferies Randall & Dewey from February 2005 to July 2008. Prior to that, Ms. Farley served as Chief Executive Officer of Randall & Dewey, an oil and natural gas asset transaction advisory firm, from September 2002 until its acquisition by Jefferies Group, Inc. in February 2005. Ms. Farley has extensive expertise in oil and natural gas exploration operations, business development and marketing, having spent 18 years at Texaco, Inc. where she held several senior positions, including Chief Executive Officer of Hydro-Texaco, Inc., President of Worldwide Exploration and New Ventures and President of North American Production. She also served as chief executive officer of two start-up ventures, Intelligent Diagnostics Corporation and Trade-Ranger Inc. Ms. Farley holds a Bachelor of Science in Geology from Emory University. Ms. Farley also serves on the board of directors of LyondellBasell Industries, N.V. and FMC Technologies, Inc. and previously served as a director at Encana from 2008 to 2014. The Board of Directors believes that Ms. Farley’s successful experience as chief executive officer of several companies, her experiences in exploration, business development and marketing at Texaco, Inc. and her service on multiple boards of directors provide her the requisite experience necessary to serve as a director.

Brandon A. Freiman

Mr. Freiman was named a director of Samson Resources Corporation in May 2013. Mr. Freiman joined KKR in 2007, where he is currently a director in the energy and infrastructure group. During his time at KKR, he has also been involved in several of the firm’s energy investments, including El Paso Midstream Company, Accelerated Oil Technologies, LLC and Westbrick Energy Ltd., and he has had portfolio company responsibilities for Rockwood Holdings, Inc., a specialty chemical and advanced material company. Prior to joining KKR, Mr. Freiman was with Credit Suisse Securities in its energy investment banking group, where he was involved in a number of merger, acquisition and other corporate transactions. Mr. Freiman currently sits on the board of directors of Energy Future Holdings Corp. He holds a Bachelor of Commerce, with a Joint Honors in Economics and Finance, from McGill University. The Board of Directors believes Mr. Freiman’s experience at KKR along with his background in investment banking while at Credit Suisse Securities provide him the requisite experience necessary to serve as a director.

 

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Toshiyuki Mori

Mr. Mori was named a director of Samson Resources Corporation in April 2013. Since October 2011, Mr. Mori has been president and a director of JD Rockies, a wholly-owned subsidiary of ITOCHU. From April 2007 to September 2011, Mr. Mori held a number of positions with ITOCHU, including deputy general manager of its exploration and production department. Prior to joining ITOCHU, Mr. Mori held various management and project development positions with SOJITZ Corporation, Thai Sunrock Company Limited, and NISSHO IWAI Corporation. Mr. Mori earned Bachelor and Master of Science (Economic Geology) degrees from Hokkaido University, Japan. He also attended the Duke Advance Management Program at The Fuqua School of Business Executive Education Program at Duke University. The Board of Directors believes Mr. Mori’s background in the exploration and production industry at ITOCHU and his prior management experience provide him the requisite experience necessary to serve as a director.

David C. Rockecharlie

Mr. Rockecharlie was named a director of Samson Resources Corporation in December 2011. He is a member of KKR Management LLC, the general partner of KKR & Co. L.P., and he joined KKR in November 2011 as a member of its energy and infrastructure group. Prior to joining KKR, from September 2010 to October 2011, Mr. Rockecharlie co-founded and was with RPM Energy, LLC, which partnered with KKR to invest in unconventional oil and natural gas resources. Prior to founding RPM Energy, LLC, Mr. Rockecharlie was Managing Director and co-head of Jefferies Randall & Dewey, the global oil and natural gas industry advisory group at Jefferies Group, Inc., from June 2008 to June 2010 and Managing Director and head of corporate finance at Jefferies Randall & Dewey from February 2005 to June 2008. Prior to that, Mr. Rockecharlie was a Partner and Managing Director of Randall & Dewey from June 2003 until its acquisition by Jefferies Group, Inc. in February 2005. Earlier in his career, Mr. Rockecharlie was an executive with El Paso Corporation, where he served in various operating and financial roles. Mr. Rockecharlie began his career as an energy investment banker with Donaldson Lufkin & Jenrette and SG Warburg & Co. Mr. Rockecharlie holds an A.B. in Economics, magna cum laude, from Princeton University. The Board of Directors believes Mr. Rockecharlie’s experience as co-founder of RPM Energy, LLC, his executive experience at El Paso Corporation and his investment banking experience at Donaldson Lufkin & Jenrette and SG Warburg & Co. provide him the requisite experience necessary to serve as a director.

Jonathan D. Smidt

Mr. Smidt was named a director of Samson Resources Corporation in December 2011. Mr. Smidt joined KKR in 2000 where he is currently a senior member of KKR’s energy and infrastructure team. Prior to joining KKR, Mr. Smidt was at Goldman, Sachs & Co. in the investment banking group in New York where he spent two years in the energy and power industry group and one year in the mergers and acquisitions group. Mr. Smidt started his career at Ernst & Young in Cape Town, South Africa. He holds a Bachelor of Business Science and a postgraduate diploma in Accounting from the University of Cape Town (South Africa). Mr. Smidt also sits on the boards of Energy Future Holdings Corp., Laureate Education and Westbrick Energy, Ltd. Mr. Smidt also sits on the board of the Mailman School of Public Health at Columbia University. The Board of Directors believes Mr. Smidt’s energy experience at KKR, including leading KKR Natural Resources, as well as his background in investment banking while at Goldman, Sachs & Co. provide him the requisite experience necessary to serve as a director.

Akihiro Watanabe

Mr. Watanabe was named a director of Samson Resources Corporation in May 2012. Mr. Watanabe is the founder and representative director of GCA Savvian Corporation (“GCA”), an investment banking firm listed on Tokyo Stock Exchange, and the founder of Global Corporate Advisory, GCA’s predecessor company, and he has over 25 years of experience in providing merger and acquisition advisory services both in Japan and overseas. Prior to founding Global Corporate Advisory in 2002, Mr. Watanabe spent 20 years with KPMG, primarily focusing on merger and acquisition advisory and transaction related services for Japanese as well as U.S.

 

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companies. Mr. Watanabe is a member of the board of directors and the chairman of the audit committee of Ranbaxy Laboratories, Ltd., an Indian pharmaceutical company listed on Bombay Stock Exchange, a visiting professor of Kobe University Business School and he is a certified public accountant. Mr. Watanabe received his Bachelor of Arts in Commerce and Accounting from Chuo University. The Board of Directors believes Mr. Watanabe’s extensive background in mergers and acquisitions at KPMG and GCA as well as his experience as a board member and chairman of the audit committee of Ranbaxy Laboratories, Ltd. provide him the requisite experience necessary to serve as a director.

Board Structure and Committee Composition

Our Board of Directors currently consists of eight directors, which were appointed by the Principal Stockholders pursuant to the stockholders’ agreement among Samson Resources Corporation and the Principal Stockholders. For additional information, see Part III, Item 13—“Certain Relationships and Related Transactions, and Director Independence.” Our directors serve until the election of their successor, or until their earlier death, resignation or removal. The Board of Directors of Samson Resources Corporation has an Audit Committee, Compensation Committee and Executive Committee. Our Board of Directors may also establish from time to time other committees that it deems necessary and advisable.

The Board of Directors believes that administering risk management requires the Board as a whole. Our risk management structure is set up in such a way that the executive officers are responsible for the day-to-day risk management responsibilities. Certain of the executive officers attend the meetings of our Board of Directors. The Board of Directors are provided reports on our financial results, the status of our operations, our financial derivatives and other aspects of implementation of our business strategy, with inquiries often made of management regarding specifics within these reports. In addition, at each regular meeting of the Board of Directors, management provides a report of the Company’s financial and operational performance, with feedback from the Board of Directors. The Audit Committee provides additional risk oversight through its quarterly meetings, where it receives a report from the Company’s internal auditor, who reports directly to the Audit Committee, and reviews the Company’s significant accounting and audit matters with management and our independent auditors.

The Board of Directors is comprised of individuals with backgrounds relevant to the future success of the Company, including extensive experience in energy and finance, as well as backgrounds in operations and marketing. The Board of Directors does not have a formal policy requiring consideration of diversity in board members, nor does it have a formal policy for identifying director nominees. The Board of Directors believes the interests of the Company are best served by individuals with varying backgrounds and expertise in the energy arena. We do not have procedures by which security holders may recommend nominees to our Board of Directors.

Audit Committee

Our Audit Committee consists of Robert Delaney (Chair), Brandon Freiman, David Rockecharlie and Akihiro Watanabe. Among other things, the Audit Committee oversees, reviews, acts on and reports on various auditing, accounting and compliance matters to our Board of Directors. In light of our status as a privately-held company and the absence of a public trading market for shares of our common stock, there are no requirements that we have an independent audit committee and the Board of Directors has not designated any member of the Audit Committee as an “audit committee financial expert.”

Compensation Committee

Our Compensation Committee consists of Jonathan Smidt (Chair), Robert Delaney, Claire Farley and Toshiyuki Mori. The Compensation Committee has primary responsibility for reviewing and approving the compensation of executive officers, overseeing the Company’s benefit plans, and reviewing and making recommendations regarding Board compensation.

 

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Executive Committee

Our Executive Committee consists of Robert Delaney, Claire Farley, Randy Limbacher, Toshiyuki Mori and Jonathan Smidt. The Executive Committee is responsible for providing rapid access to decision making and confidential discussions for the Board of Directors.

Code of Business Conduct and Ethics

We have adopted a Code of Business Conduct and Ethics for all officers and employees of the Company, including our principal executive, financial and accounting officers. The Code is available on our web site at www.samson.com under “Company” and “Investors.” Information on or accessible through our website does not constitute a part of this report.

 

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ITEM 11. EXECUTIVE COMPENSATION

Compensation Discussion and Analysis

Introduction

In May 2012, a compensation committee with authority to recommend or make executive compensation decisions was established by the Board of Directors of Samson Resources Corporation (the “Compensation Committee”). The following information provides an overview of our compensation objectives and philosophy, describes how our compensation programs are designed and operate with respect to our executive officers for whom compensation is disclosed in the tables below as required by the SEC rules (referred to as the “named executive officers”) and analyzes important executive compensation decisions with respect to the named executive officers.

2014 Named Executive Officers

Our named executive officers for the fiscal year ended December 31, 2014 were:

 

Name

  

Title

  

Start Date

Randy L. Limbacher

   Chief Executive Officer and President    April 2013

Philip W. Cook

   Executive Vice President and Chief Financial Officer    April 2012

Richard E. Fraley

   Executive Vice President and Chief Operating Officer    July 2013

Louis D. Jones

   Executive Vice President—Business Development, New Ventures and Portfolio Management    August 2013

Andrew C. Kidd

   Senior Vice President and General Counsel    September 2013

From February 26, 2013 to April 17, 2013, we were searching for a new Chief Executive Officer, and Claire S. Farley, a member of KKR Management LLC, the general partner of KKR & Co. L.P., and a director of Samson Resources Corporation and Samson Investment Company since December 2011, acted as our interim Chief Executive Officer and President. Ms. Farley did not receive any compensation for her services as our interim Chief Executive Officer and President, although we provided her with corporate housing in Tulsa, Oklahoma. Our current Chief Executive Officer and President, Randy L. Limbacher, joined the Company on April 18, 2013.

Subsequent to Mr. Limbacher joining the Company in 2013, additional new members of our management team were retained, including our Executive Vice President and Chief Operating Officer, Richard E. Fraley, our Executive Vice President—Business Development and New Ventures, Louis D. Jones, and our Senior Vice President and General Counsel, Andrew C. Kidd. Mr. Jones’ employment with the Company terminated effective March 31, 2015.

Executive Compensation Objectives, Philosophy and Process

The elements and amount of compensation for the named executive officers for 2014 are designed based upon the Company’s philosophy and practice to attract, retain, motivate, and reward top tier talent in our industry while also creating long-term alignment with our stakeholders’ interests. Our executive compensation program is designed to provide equitable compensation in a highly competitive environment for talented executives. For 2014, our executive compensation actions largely focused on retention of our named executive officers, as their retention is especially critical due to the challenges in both our industry and our company. To achieve these objectives, during fiscal 2014 we delivered executive compensation through a combination of the following components:

 

    base salary;

 

    annual and special retention cash bonuses;

 

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    long-term equity incentive awards and equity-based retention awards;

 

    additional benefits, including supplemental executive benefits and perquisites; and

 

    other enhanced severance benefits.

Role of the Board of Directors, Compensation Committee and Executive Officers

Prior to the Acquisition, we were a privately owned company where all executive compensation decisions were made by an executive team. Following the Acquisition and prior to the formation of the Compensation Committee in May 2012, the Board of Directors made all of our executive compensation decisions. Since the formation of the Compensation Committee, all executive compensation decisions have been made by the Compensation Committee with input, as requested, from our human resources department and our Chief Executive Officer, Chief Financial Officer and General Counsel and, starting in 2014, its independent compensation consultant, Frederic W. Cook (“F.W. Cook”). Our human resources department, Chief Executive Officer and Chief Financial Officer make recommendations to the Compensation Committee for annual base salary and bonus adjustments primarily based on comparative information acquired through industry surveys, as further described below. The Chief Executive Officer evaluates the other named executive officers’ performance during the year based on their achievement of the goals that were established at the start of the compensation cycle and provides input to the Compensation Committee regarding the other named executive officers’ base salaries and annual cash bonus amounts. The Compensation Committee makes decisions about the Chief Executive Officer’s compensation based on his performance during the year, with input from the full Board of Directors. The Chief Executive Officer, Chief Financial Officer and General Counsel are the only named executive officers who have assumed a role in the evaluation, design or administration of our executive officer compensation program. In late 2013, our Compensation Committee engaged F. W. Cook as its independent compensation consultant to provide it with expert analyses, advice and information with respect to our compensation program, including executive officers’ compensation.

Typically, decisions about the annual base salary adjustments and annual cash bonuses have been made following the end of a compensation cycle, which is based on the close of our fiscal year.

Use of Peer Group Based on Compensation Surveys and Data

In order to improve our compensation analysis, the Compensation Committee considers information from a “peer group.” The Compensation Committee believes that monitoring executive pay practices at our peer group helps ensure that our executive compensation program and pay levels remain competitive. The peer group is comprised of the companies that we believe that we often compete with for executive talent. The peer group also generally reflects companies that have significant North American oil and gas activities and comparable financial factors such as market capitalization, revenue, assets and enterprise value. Prior to our engagement of F.W. Cook, we used comparative information acquired through industry surveys in formulating recommendations for annual base salary adjustments, bonus payments and equity awards, and our peer group was compiled from the list of companies participating in various industry surveys we utilized when making compensation recommendations. In late 2013, F.W. Cook reviewed the suitability of the peer group being utilized based on operations, market capitalization, revenue, assets and enterprise value and made recommendations for an updated peer group. After considering the recommendations made by F.W. Cook, the peer group was modified by adding 11 new companies (identified with an asterisk in the list below) and removing the following companies: Apache Corporation, Chesapeake Energy Corporation, Continental Resources, Inc., Devon Energy Corporation, Encana Oil & Gas (USA) Inc., EOG Resources, Inc., Linn Operating, Inc., McMoRan Exploration Co., Mewbourne Oil Company, Noble Energy, Inc., Penn Virginia Corporation, PetroQuest Energy, Inc., Pioneer Natural Resources Company, Plains Exploration & Production Company, Talisman Energy USA, Inc. and XTO Energy, Inc.

The updated 2013 peer group was used in making decisions with respect to cash bonuses for services during the fiscal year 2013 that were paid in April 2014. The updated 2013 peer group was also used in making decisions with respect to base salary and annual target bonus modifications during fiscal year 2014.

 

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The 2013 peer group consisted of the following companies:

 

    Bill Barrett Corporation*

 

    Cabot Oil & Gas Corporation

 

    Cimarex Energy Co.

 

    Concho Resources, Inc. (COG Operating LLC)*

 

    Denbury Resources, Inc.*

 

    EXCO Resources, Inc.*

 

    Forest Oil Corporation

 

    Laredo Petroleum Holdings, Inc.*

 

    Newfield Exploration Company

 

    Oasis Petroleum, Inc.*

 

    QEP Resources, Inc.

 

    Range Resources Corporation

 

    SandRidge Energy, Inc.*

 

    SM Energy Company

 

    Southwestern Energy Company

 

    Stone Energy Corporation*

 

    Swift Energy Company*

 

    Ultra Petroleum Corporation*

 

    Whiting Petroleum Corporation*

 

    WPX Energy, Inc.

Assessment of Individual and Company Performance

We generally conduct annual performance reviews of each of our senior executives during the first quarter following the end of the respective compensation cycle. The manager and executive review the goals and objectives that were established at the start of that compensation cycle and assess the degree of achievement. We also assess the overall performance and organizational impact of each executive as well as their future potential in the Company. The performance goals and objectives set at the start of the compensation cycle vary from individual to individual, although there are shared goals among the executives, and they generally relate to operational or management goals relating to the person’s area of responsibility within the organization.

Due to the changes in our management team during 2013, our named executive officers did not have pre-determined goals that were communicated to them at the beginning of fiscal year 2013 or at the time of hire. Rather, their annual bonus amounts were determined based on our Chief Executive Officer’s (or, in the case of the Chief Executive Officer, the Compensation Committee’s) subjective evaluation of their performance. For 2014, the Chief Executive Officer communicated individual goals to the other named executive officers in the first quarter of the fiscal year. For further discussion, see “—Elements of Compensation—2014 Bonuses.”

In late 2013, the Company hired F.W. Cook, a nationally recognized consulting firm specializing in executive compensation, to assist the Company in setting the total compensation of the executives at levels between the 50th and 75th percentile of our peers and to more consistently align the components and terms of the

 

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total compensation packages among our executives based on their respective positions. As of result of the information presented by F.W. Cook and the then-recent fair market value determination of our common stock made by our Board of Directors, we made various executive compensation actions in February and March 2014, including, among other things, the following: i) implemented a moderate increase in the base salary of the executives, ii) implemented a moderate increase in the annual target bonus for Mr. Kidd, (iii) granted stock and options to certain named executive officers, iv) repriced outstanding stock options held by employees, including the named executive officers, to reduce the exercise price per share to $2.50, v) amended the vesting terms of restricted stock awards held by all employees, with the exception of Mr. Limbacher, to provide that (a) all restricted stock awards will immediately vest upon a change-in-control and a qualifying termination of employment and (b) the 2013 restricted stock awards will vest annually in four equal tranches beginning in 2015, and (vi) offered to repurchase shares of our common stock at a price per share equal to the initial cost basis of such shares, which was more than the then current fair market value, from current employees who had previously purchased shares. For additional information on these compensation actions, please see “—Elements of Compensation—Long-Term Equity Incentive Awards and Award Modifications” and “—Narrative Disclosure to Summary Compensation Table and Grants of Plan-Based Awards in Fiscal 2014 Table—Terms of Restricted Stock Awards.”

In August 2014, the Compensation Committee approved a number of executive compensation actions to retain our executives, including, but not limited to: (i) approving officer retention letter agreements (“Officer Retention Letter Agreements”) which provide for, among other things, (a) a retention award for officers remaining employed with the Company through September 1, 2015, (b) accelerated vesting of outstanding equity held by the officers, and (c) special temporary put and call rights on restricted stock held by officers; (ii) adopting the Samson Resources Corporation Voluntary Severance Plan for Officers (the “ Officer Voluntary Severance Plan”); (iii) awarding officers 100% of their individual annual target bonuses for 2014 and accelerating payment of those bonuses to January 9, 2015; and (iv) awarding officers a one-time special bonus in an amount equal to 100% of their individual annual target bonus. For further discussion, see “—Potential Payments Upon a Termination or a Change of Control—Officer Retention Letter Agreements.” These actions were made to (i) help ensure the continued services of our executives for the execution of certain portfolio management activities and other strategic transactions then-contemplated by the Company; (ii) increase the cash component of our executives’ total compensation package, in recognition of the uncertainties relating to the future realized value of their equity awards due, in part, to the absence of a public market for our common stock; and (iii) generally increase the retentive nature of the executives’ total compensation package in light of the Company’s substantial indebtedness.

In March 2015, the Company entered Release Payment Letter Agreements with officers which release the Company from the obligations under the Officer Retention Letter Agreements and Officer Voluntary Severance Plan, with the exception of the accelerated vesting of outstanding equity and COBRA reimbursement provisions. For further discussion, see “—Recent Compensation Actions in 2015.”

Elements of Compensation

Base Salary

Base salaries are intended to provide a market competitive level of fixed compensation that recognizes the responsibilities, skills, capabilities, experience, and leadership of each executive officer. Base salaries are tiered to be competency and tenure based. Base salaries of employees, including our executive officers, are generally reviewed at least annually, typically during the first quarter after conducting the performance reviews described above, and decisions about base salary adjustments are made at that time.

On February 13, 2014, the Compensation Committee approved upward adjustments to the base salaries of the named executive officers, effective April 1, 2014. The 2014 levels of base salaries reflected the increase in base salary in the industry in general at the time and, with the exception of Mr. Limbacher, were intended to

 

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approximate between the 50th percentile and the 75th percentile of the comparable positions in the peer group used with respect to fiscal years 2013 and 2014, which the Compensation Committee believed was important to retain top tier talent in an intensely competitive industry. For further discussion, see “—Assessment of Individual and Company Performance.

The base salaries of the named executive officers in effect during fiscal year 2014 were:

 

Name

   Base Salary (in effect from
January 1, 2014—March 31,
2014)
     Base Salary (in effect from
April 1, 2014—December 31,
2014)
 

Randy L. Limbacher

   $ 800,000       $ 830,000   

Philip W. Cook

   $ 530,006       $ 550,000   

Richard E. Fraley

   $ 530,004      $ 550,000   

Louis D. Jones

   $ 475,008       $ 495,000   

Andrew C. Kidd

   $ 400,008       $ 415,000   

The base salaries of the named executive officers shown in the Summary Compensation Table below reflect the base salaries actually earned by them during the fiscal years ending December 31, 2014, 2013 and 2012 as indicated in the table.

2014 Bonuses

Under the terms of Mr. Limbacher’s employment agreement, his target annual award opportunity under the annual bonus plan is 100% of his base salary. With respect to annual target bonuses for performance during 2014, Messrs. Cook, Fraley, Jones and Kidd were each informed that their respective target annual bonus amount was 100% of their respective base salary. Pursuant to recommendations made by our Chief Executive Officer, Mr. Limbacher, in August 2014, the Compensation Committee approved the amount of annual bonuses to be paid to the other named executive officers at target level on an expedited basis. Mr. Limbacher’s recommendations were aimed at retaining the executives into the third quarter of 2015 and were based on the strategic direction of the Company and the short-term value of equity awards owned by the executives as well as his subjective evaluation of each such officer’s performance during 2014. The Compensation Committee approved his recommendations. Similarly, in August 2014, the Compensation Committee determined the amount of Mr. Limbacher’s annual bonus was also to be paid at target based on the same considerations. The Compensation Committee and Mr. Limbacher did not rely on any objective or quantitative performance metrics in evaluating the named executive officers’ annual bonus amounts. The annual bonuses with respect to fiscal year 2014 were paid on January 9, 2015.

Additionally, in August 2014, the Compensation Committee approved a special one-time cash bonus (“Special Bonus”) for the named executive officers of the Company in an amount equal to the individual officer’s 2014 annual target bonus, as described in the preceding paragraph. The Compensation Committee granted the Special Bonuses as an additional retention element for the officers of the Company. In order to receive the Special Bonus, officers were required to execute a bonus agreement which specified that the Special Bonus was a one-time bonus not to be included in any calculation of a future bonus amount. The Special Bonuses were also paid to officers on January 9, 2015.

Long-Term Equity-Based Incentive Awards and Award Modifications

In connection with the Acquisition, we adopted the Samson Resources Corporation 2011 Stock Incentive Plan (the “2011 Plan”) for our employees, directors, and certain other service providers and independent contractors. The Compensation Committee may grant stock options, stock appreciation rights, restricted stock, restricted stock units or other stock-based awards under the 2011 Plan. In May 2013, we amended the 2011 Plan to increase the number of shares available for issuance.

 

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Our long-term incentive (“LTI”) awards for executive officers are granted in the form of stock options and restricted stock. The Compensation Committee believes that LTI awards closely align our management’s interest with those of our stockholders and incentivizes our management employees to remain in our service.

In late 2013, the Company hired F.W. Cook, a nationally recognized consulting firm specializing in executive compensation, to assist the Company in setting the total compensation of the executives at levels between the 50th and 75th percentile of our peers and to more consistently align the components and terms of the total compensation packages among our executives based on their respective positions. As of result of the information presented by F.W. Cook and the then-recent fair market value determination of our common stock made by our Board of Directors, on March 24, 2014,

 

    we granted Mr. Fraley 800,000 stock options, as described in more detail under “—Terms of Option Awards—2014 Options”;

 

    we granted Mr. Limbacher 2,500,000 shares of restricted stock, as described in more detail under “—Terms of Restricted Stock Awards —Restricted Stock Granted to Mr. Limbacher”; and

 

    we granted 1,300,000, 1,450,000, 600,000 and 1,000,000 shares of restricted stock to each of Messrs. Cook, Fraley, Jones and Kidd, respectively, as described in more detail under “—Terms of Restricted Stock Awards —Restricted Stock Granted to Messrs. Cook, Fraley, Jones and Kidd”.

As part of a review of our executive compensation and employee benefit arrangements on behalf of and under the supervision of our board of directors and due to the previously granted options having a fair market value below their exercise price, in fiscal year 2014 we determined that modifying all outstanding options by reducing the per-share exercise price may be better suited than the original options to meet our objectives to attract, motivate, retain and reward talented and experienced individuals. In addition, we believed the repricing would align executive compensation with achievement of our overall business goals, adherence to our core values and stakeholder interests. Therefore, on March 24, 2014, we reduced the exercise price of all outstanding options, including those held by our named executive officers (other than Mr. Limbacher), to $2.50. All of the option holders were required to enter into an amendment to their existing option agreement that reflected the repricing.

At the same time as the general repricing described above, we amended Mr. Limbacher’s employment agreement, to provide for (i) the forfeiture by Mr. Limbacher of 250,000 stock options with an exercise price of $4.00 per share, (ii) the forfeiture by Mr. Limbacher of 250,000 stock options with an exercise price of $5.00 per share, (iii) the repricing of 10,000,000 of his stock options with an initial exercise price of $7.50 per share to an exercise price of $2.50 per share (consistent with the repricing for all employees), and (iv) an amended vesting schedule for his 2013 restricted stock awards which will now vest annually in four equal tranches beginning in April 2015.

Severance and Retention Benefits

The employment agreement we entered into with Mr. Limbacher and the special agreements we entered into with Messrs. Cook, Fraley and Jones at the time of their respective hire provide for severance payments and benefits under certain termination circumstances. The terms of these agreements and the severance payments and benefits are described more fully under “Potential Payments Upon a Termination or a Change of Control.”

On March 24, 2014, the Compensation Committee adopted the Samson Resources Corporation Change in Control Severance Plan for Officers (the “Change in Control Severance Plan”), effective as of January 1, 2014, pursuant to which officers will receive cash compensation and certain other benefits in the event of a change-in-control and a qualifying termination of employment. All of the named executive officers, except Mr. Limbacher, are eligible for severance under the Change in Control Severance Plan. The terms of these severance payments and benefits are described more fully under “Potential Payments Upon a Termination or a Change of Control.”

 

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Also in March 2014, the Compensation Committee approved amendments to the vesting terms of the restricted stock awards held by employees, including our named executive officers, except Mr. Limbacher, which provide that (i) all restricted stock awards will immediately vest upon a change-in-control and a qualifying termination of employment and (ii) the 2013 restricted stock awards will now vest annually in four equal tranches beginning in 2015. The Compensation Committee also approved an agreement with Mr. Jones permitting him, in the event of retirement or permanent disability, to retain the then vested portion of any restricted stock or stock options (which may be exercised at any time during the term of such options).

In August 2014, the Compensation Committee approved the entry into the Officer Retention Letter Agreements with the named executive officers, which provide for participation in the Officer Voluntary Severance Plan for named executive officers who remain with the Company through September 1, 2015, but choose to terminate employment as of that date. The Officer Retention Letter Agreements also provide for certain severance payments and benefits for officers in the event the Company terminates the officer’s employment without Cause prior to September 1, 2015. The terms of the Officer Retention Letter Agreements and the Officer Voluntary Severance Plan were finalized in November 2014, and are described more fully under “Potential Payments Upon a Termination or a Change of Control.” The Compensation Committee believes that severance arrangements are necessary to attract and retain the talent necessary for our long-term success. For further discussion see, “—Assessment of Individual and Company Performance.” In March 2015, the Company entered Release Payment Letter Agreements with officers which release the Company from the obligations under the Officer Retention Letter Agreements and Officer Voluntary Severance Plan, with the exception of the accelerated vesting of outstanding equity and COBRA reimbursement provisions, which remain in effect. For further discussion, see “—Recent Compensation Actions in 2015.”

Additional Benefits

Health and Welfare Benefits. Our named executive officers are eligible to participate in all of our employee health and welfare benefit arrangements on the same basis as other employees (subject to and in accordance with applicable laws). These arrangements include: medical, dental, vision, life and accidental death and dismemberment insurance, as well as short and long term disability benefits. These benefits are provided to ensure that we are able to competitively attract and retain employees, including our named executive officers.

In addition, in 2014 our named executive officers were eligible to participate in Execucare, a special medical plan available to our officers that reimburses the participant for all of his or her premium costs and out-of-pocket medical expenses. The Execucare plan was terminated effective December 31, 2014.

Retirement Benefits. We maintain an employee retirement savings plan through which employees may save for retirement or future events on a tax-advantaged basis. We currently provide matching contributions under our 401(k) plan up to 6% of an employee’s base salary plus bonus, as well as providing an additional 2% non-matching contribution. Employees become fully vested in the Company’s contributions after five years of service. Participation is at the discretion and direction of each individual employee, and our named executive officers participate in the plan on the same basis as all other employees.

We also provide certain other benefits described below to our named executive officers, which are not tied to any performance criteria. Rather, these benefits are intended to support objectives related to the attraction and retention of highly skilled executives.

Use of Corporate Aircraft. Prior to May 2013, Company officers were eligible to use the corporate aircraft for personal use on a limited basis. Subsequent to May 2013, our employees’ personal use of the corporate aircraft has been limited to exceptional circumstances, such as medical emergencies, and spousal travel on trips related to business which, under the SEC rules, may not be considered to be directly and integrally related to our business.

 

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Relocation Benefits. To facilitate the relocation and hiring of officers and other key personnel, we provide relocation benefits which generally include payments to prevent a loss on the sale of residence and to cover reasonable costs related to the move.

Other Perquisites. We also provide certain other immaterial perquisites, such as personal use of company vehicles, dependent education assistance, financial planning reimbursement and private club dues, as further described in the footnote to the “All Other Compensation” column in the Summary Compensation Table below.

Recent Compensation Actions in 2015

In March 2015, the Company entered Release Payment Letter Agreements with officers remaining employed with the Company after April 1, 2015, including the named executive officers. The Release Letter Agreements release the Company from the obligations under the November 14, 2014 Officer Retention Agreements and the Voluntary Severance, with the exception of the accelerated vesting of outstanding equity and COBRA reimbursement provisions. The Release Letter Agreements provide that the Company shall pay to the officers a one-time lump sum payment equal to one-half of the value of the Retention Award provided in the Officer Retention Letter Agreements (i.e., an amount equal to the officer’s 2015 base salary and annual target bonus) (“Release Payment”). The officer must sign a waiver and release agreement in exchange for the Release Payment.

Additionally, in March 2015, the Compensation Committee approved a new incentive compensation program that replaces the Company’s existing short- and long-term incentive arrangements. Effective immediately, the named executive officers shall be eligible to receive quarterly cash bonuses based on the achievement of applicable vesting conditions established by the Compensation Committee, which for quarters beginning April 1, will be one or more objective performance criteria.

Summary Compensation Table

The following table provides summary information concerning compensation paid or accrued by us to or on behalf of our named executive officers, for services rendered to us during each of the years presented.

 

Name and Principal Position

  Year     Salary
($)
    Bonus
($)(2)
    Stock
Awards ($)(3)
    Option
Awards
($)(3)
    All Other
Compensation
($)(4)
    Total
($)
 

Randy L. Limbacher, Chief

    2014        822,500        1,660,000        5,325,000        5,558,456        46,730        13,412,686   

Executive Officer and President(1)

    2013        561,026        750,000        17,000,000        38,236,156        72,730        56,619,912   

Philip W. Cook, Executive Vice

    2014        545,002        1,100,000        2,769,000        788,432        158,610        5,361,044   

President and Chief Financial Officer(1)

    2013        530,006        650,000        1,360,000        1,948,675        328,218        4,816,899   
    2012        359,170        915,100        —          2,880,000        1,023,607        5,177,877   

Richard E. Fraley, Executive Vice

    2014        545,012        1,100,000        3,088,500        1,619,270        69,752        6,422,534   

President and Chief Operating Officer(1)

    2013        226,950        550,000        1,360,000        3,666,597        122,808        5,926,355   

Louis D. Jones, Executive Vice

    2014        490,002        990,000        1,278,000        1,099,981        42,468        3,900,451   

President—Business Development and New Ventures(1)

    2013        194,571        250,000        1,360,000        3,108,892        5,974        4,919,437   

Andrew C. Kidd, Senior Vice

    2014        411,253        830,000        2,130,000        544,015        103,284        4,018,552   

President and General Counsel(1)

    2013        125,003        170,000        —          2,835,348        268,770        3,399,121   

 

(1) Messrs. Limbacher, Cook, Fraley, Jones and Kidd each commenced employment with us, effective April 18, 2013, April 16, 2012, July 29, 2013, August 5, 2013 and September 9, 2013, respectively. Accordingly, 2012 salaries (in the case of Mr. Cook) and 2013 salaries (in the case of Messrs. Limbacher, Fraley, Jones and Kidd) were pro-rated, as applicable. 2014 salaries represent amounts actually paid during the year and reflect increases as of April 1, 2014.

 

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(2) Mr. Cook’s 2012 amount represents a special hiring bonus of $350,000 he received upon the commencement of his employment, a pro-rated annual discretionary bonus of $300,000 he received in November 2012 under the terms of his special agreement with us and the bonus he earned for his services during the six-month period from July 1, 2012 to December 31, 2012, which was paid in April 2013. The amount for 2014 for each of our named executive officers represents the annual bonus earned by each such officer for services during the year ended December 31, 2014, as well as their special bonuses, which were paid in January 2015. See “—Compensation Discussion and Analysis—Elements of Compensation—2014 Bonuses.”
(3) The dollar amounts represent the aggregate grant date fair value of restricted stock awards and option awards, respectively, granted in the indicated fiscal year. The grant date fair value of a restricted stock award and an option award, respectively, is measured in accordance with FASB ASC Topic 718 utilizing the assumptions discussed in Note 14 to our audited consolidated financial statements included in Part II, Item 8—“Financial Statements and Supplementary Data” of this report. On March 24, 2014, we repriced outstanding stock options held by each of our named executive officers, other than Mr. Limbacher, to reduce the exercise price per share to an exercise price of $2.50 per share. Additionally, on March 24, 2014, Mr. Limbacher forfeited 250,000 stock options with an exercise price of $4.00 per share and 250,000 stock options with an exercise price of $5.00 per share and the Company the repriced 10,000,000 of his stock options with an initial exercise price of $7.50 per share to an exercise price of $2.50 per share. The incremental fair value with respect to such repriced awards, calculated pursuant to ASC Topic 718 as of the repricing, is included for each named executive officer in the 2014 “Option Awards” column. For a discussion of specific restricted stock awards and option awards granted during 2014, see “—Grants of Plan-Based Awards in Fiscal 2014” below and the narrative discussion that follows.
(4) “All Other Compensation” for the named executive officers for 2014 includes the following:

 

    401(k)
Contribution

(a)
    Personal
Use of
Vehicle
(b)
    Group
Term Life
Insurance
Premiums
(c)
    Personal
Use of
Aircraft
(d)
    Financial
Planning
Assistance
(e)
    Dependent
Education
Assistance
(f)
    Club
Dues
(g)
    Tax
Gross-
Up
(h)
    Relocation
Benefits
(i)
    Execucare
(j)
    Parking
(k)
    Stock
Repurchase
(l)
 

R. Limbacher

  $ 20,800      $ —        $ 4,902      $ 821      $ —        $ —        $ 9,730      $ 9,390      $ —        $ 187      $ 900      $ —     

P. Cook

  $ 20,800      $ 3,955      $ 2,622      $ 4,166      $ —        $ —        $ 8,918      $ 13,455      $ —        $ 3,794      $ 900      $ 100,000  

R. Fraley

  $ 20,800      $ —        $ 4,902      $ 7,203      $ —        $ 13,200      $ —        $ 10,224      $ 2,000      $ 5,513      $ 5,910      $ —     

L. Jones

  $ 20,800      $ —        $ 7,368      $ 113      $ 2,800      $ —        $ 50      $ 604     $ —        $ 9,833      $ 900      $ —     

A. Kidd

  $ 20,800      $ 2,670      $ 2,133      $ —        $ —        $ —        $ 9,159     $ 11,561      $ 47,528      $ 8,533      $ 900      $ —     

 

(a) Represents a matching contribution to the executive’s 401(k) plan.
(b) Represents incremental costs associated with the personal use of a company car.
(c) Represents payments of premiums for a group life insurance policy.
(d) Represents incremental costs associated with the personal use of corporate aircraft. The incremental cost was calculated by multiplying the personal aviation hours used by the executive officer and/or his guests by the average variable cost per hour of $1,900 of operating the corporate aircraft. The average variable cost per hour includes costs relating to fuel, trip-related maintenance, inspections, crew travel expenses, contracted crew services, trip-related fees and storage costs, on-board catering, aircraft supplies and deadhead flights. In addition, a cost per hour of $25, representing on-board catering, was included for any personal hours related to guests accompanying an executive officer on a business trip.
(e) Represents actual cost of financial planning assistance provided to our executives.
(f) Represents the actual cost of education assistance provided by us to employees’ dependents.
(g) Represents payments of private club dues and expenses on behalf of the executives.
(h) Represents tax gross-up of imputed income relating to personal use of the corporate aircraft, club dues and relocation benefits, as well as certain other benefits that are provided generally to all salaried employees.
(i) Represents relocation benefits provided to each of Messrs. Fraley and Kidd in connection with his hire. These relocation benefits included our standard relocation benefits. The incremental costs were calculated based on the invoice amounts provided to us.
(j) Represents premiums and claims paid under a supplemental healthcare plan for our executives.
(k) Represents vehicle parking fees paid for our executives.
(l) Represents the amount paid in excess of the fair market value for the repurchase of shares of our stock.

 

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Grants of Plan-Based Awards in Fiscal 2014

The following table provides supplemental information relating to grants of plan-based awards in fiscal 2014.

 

Name

   Approval
Date
    Grant
Date
    All Other
Stock Awards:
Number of
Shares of
Stock or Units
(#)
     All Other Option
Awards: Number
of Securities
Underlying
Options
(#)
     Exercise or
Base Price of
Option Awards
($/Share)
     Grant Date
Fair Value of
Stock and
Option Awards
 

Randy L. Limbacher

     3/24/14        3/24/14        2,500,000         —            $ 5,325,000   
     3/24/14 (1)      3/24/14           10,000,000       $ 2.50       $ 5,558,456 (1) 

Philip W. Cook

     3/24/14        3/24/14        1,300,000         —            $ 2,769,000   
     3/24/14 (1)      3/24/14 (1)         1,200,000       $ 2.50       $ 471,936 (1) 
     3/24/14 (1)      3/24/14 (1)         1,200,000       $ 2.50       $ 316,496 (1) 

Richard E. Fraley

     3/24/14        3/24/14        1,450,000             $ 3,088,500   
     3/24/14        3/24/14           800,000       $ 2.50       $ 846,960   
     3/24/14 (1)      3/24/14 (1)         1,200,000       $ 2.50       $ 316,496 (1) 
     3/24/14 (1)      3/24/14 (1)         1,200,000       $ 2.50       $ 455,814 (1) 

Louis D. Jones

     3/24/14        3/24/14        600,000         —            $ 1,278,000   
     3/24/14 (1)      3/24/14 (1)         1,250,000       $ 2.50       $ 633,067 (1) 
     3/24/14 (1)      3/24/14 (1)         750,000       $ 2.50       $ 466,914 (1) 

Andrew C. Kidd

     3/24/14        3/24/14        1,000,000         —            $ 2,130,000   
     3/24/14 (1)      3/24/14 (1)         1,200,000       $ 2.50       $ 316,496 (1) 
     3/24/14 (1)      3/24/14 (1)         600,000       $ 2.50       $ 227,519 (1) 

 

(1) On March 24, 2014, we repriced outstanding stock options held by each of our named executive officers, other than Mr. Limbacher, to reduce the exercise price per share to an exercise price of $2.50 per share. Additionally, on March 24, 2014, Mr. Limbacher forfeited 250,000 stock options with an exercise price of $4.00 per share and 250,000 stock options with an exercise price of $5.00 per share and the Company the repriced 10,000,000 of his stock options with an initial exercise price of $7.50 per share to an exercise price of $2.50 per share. The incremental fair value with respect to such repriced awards, calculated pursuant to ASC Topic 718 as of the repricing, is included for each named executive officer. For further discussion, see “—Elements of Compensation—Long-Term Equity Incentive Awards and Award Modifications.”

Narrative Disclosure to Summary Compensation Table and Grants of Plan-Based Awards in Fiscal 2014 Table

Employment Agreement with Randy L. Limbacher

We entered into an employment agreement with Randy L. Limbacher, effective as of April 18, 2013, for an initial five-year term. Commencing on the fifth anniversary of the effective date and on each anniversary thereafter, the agreement automatically renews for an additional one-year period, unless we or Mr. Limbacher provide written notice requesting that the agreement not be extended at least 60 days prior to the agreement’s renewal date. The agreement provides that Mr. Limbacher serves as our Chief Executive Officer and President.

Pursuant to this agreement, Mr. Limbacher is entitled to receive a base annual salary of $800,000, subject to annual upward adjustments, at the discretion of the Board of Directors, and he will participate in any annual cash bonus plan applicable to his position that may be adopted by us from time to time. His target annual bonus will be 100% of his base salary, subject to such other terms, conditions and restrictions as may be established by the Board of Directors or the Compensation Committee. Mr. Limbacher is also entitled to participate in the 2011 Plan. In connection with entering into the employment agreement, he was granted (i) options to purchase 6,250,000 shares of our common stock at an exercise price equal to $4.00 per share, (ii) options to purchase 6,250,000 shares of our common stock at an exercise price equal to $5.00 per share, (iii) options to purchase

 

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17,500,000 shares of our common stock at an exercise price equal to $7.50 per share, and (iv) 5,000,000 shares of restricted common stock.

Mr. Limbacher’s employment agreement was amended on April 1, 2014 to provide for (i) the forfeiture by Mr. Limbacher of 250,000 stock options with an exercise price of $4.00 per share, (ii) the forfeiture by Mr. Limbacher of 250,000 stock options with an exercise price of $5.00 per share, (iii) the repricing of 10,000,000 of his stock options with an initial exercise price of $7.50 per share to an exercise price of $2.50 per share and (iv) an amended vesting schedule for his 2013 restricted stock awards to vest annually in four equal tranches beginning in April 2015.

Pursuant to the terms of the Officer Retention Letter Agreement with Mr. Limbacher, all of the stock and options awarded to Mr. Limbacher as of November 14, 2014 will now fully vest as of September 1, 2015, or, his termination date in the event he is terminated by the Company for any reason other than Cause prior to September 1, 2015.

Mr. Limbacher is entitled to participate in all employee benefits plans and arrangements that are generally made available to our executives and perquisites and other benefits that are generally made available to our executives or to him in particular.

Mr. Limbacher’s employment agreement also provides for severance payments and benefits as further described under “—Potential Payments Upon a Termination or a Change in Control—Mr. Limbacher’s Employment Agreement.”

Special Agreement with Philip W. Cook

We entered into a special agreement with Philip W. Cook, our Executive Vice President and Chief Financial Officer, on April 16, 2012. The agreement provides for severance payments and benefits as further described under “—Potential Payments Upon a Termination or a Change in Control—Mr. Cook’s Special Agreement.”

Special Agreements with Richard E. Fraley and Louis D. Jones

We entered into special agreements with Richard Fraley and Louis D. Jones, effective August 1, 2013 and August 5, 2013, respectively. Messrs. Fraley’s and Jones’ special agreements provide for severance payments and benefits as further described under “—Potential Payments Upon Termination or a Change in Control—Special Agreements with Messrs. Fraley and Jones.”

Terms of Option Awards

2012 Options

The following describes the terms of the options granted to Mr. Cook in 2012.

Vesting Terms. Originally, the options vested in four equal annual installments beginning on December 21, 2012, subject to Mr. Cook’s continued employment with us, but would become fully vested upon a “change in control” that occurs during employment with us. Twenty-five percent of the shares subject to the option that would otherwise vest on the next vesting date will vest upon the executive’s termination of employment by the executive for “good reason” or due to death or disability. Pursuant to the terms of the Officer Retention Letter Agreements effective November 14, 2014, all of the options awarded to executives as of November 14, 2014 will fully vest as of September 1, 2015, or, his termination date in the event he is terminated by the Company for any reason other than Cause prior to September 1, 2015. If the executive’s employment is terminated by us for “cause,” both the vested and unvested options will be forfeited. A “change of control” is defined under our 2011 Plan as (i) the sale of all or substantially all of our assets to any person other than KKR, ITOCHU and certain of

 

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our other investors or their respective affiliates or (ii) a merger, recapitalization or sale of equity interests or voting power that results in any person other than KKR, ITOCHU and certain of our other investors or their respective affiliates owning more than 50% of the equity interests or voting power of Samson Resources Corporation, Samson Investment Company or any resulting company (as applicable). Effective September 1, 2015, “change of control” will be defined by our 2011 Plan as (i) the sale of all or substantially all of our assets, as owned as of September 1, 2015 and not then contemplated to be sold, to any person other than KKR, ITOCHU and certain of our other investors or their respective affiliates or (ii) a merger, recapitalization or sale of equity interests or voting power that results in any person other than KKR, ITOCHU and certain of our other investors or their respective affiliates owning more than 50% of the equity interests or voting power of Samson Resources Corporation, Samson Investment Company or any resulting company (as applicable).

Liquidity Program. Beginning in 2016 and each calendar year thereafter, each executive who is still employed with us at such time and each executive who (i) was terminated by us without cause, (ii) resigns for good reason or (iii) resigns without good reason on or after June 21, 2015, has the right to cause us to purchase all or any portion of stock issuable upon exercise of options then held by such executive; provided, however, the executive may not offer to sell in any one calendar year more than 25% of the stock issuable upon exercise of the total amount of options granted to the executive in 2012 under the 2011 Plan.

Option Call Rights. If the executive’s employment is terminated by us without cause, the executive resigns for good reason, the executive’s employment terminates due to death or disability, or the executive resigns without good reason on or after June 21, 2015, in each case, we have the right to purchase from the executive all or any portion of vested options then held by the executive at a price equal to the excess, if any, of the fair market value of the underlying shares, over the exercise price for such options and all outstanding unvested options will terminate without payment. Additionally, pursuant to the Officer Retention Letter Agreements, beginning September 2, 2015 we were to have temporary rights to repurchase from the executive all or any portion of vested options at a price equal to the excess, if any, of the fair market value of the underlying shares. The call rights under the officer Retention Letter Agreements were terminated pursuant to the Release Letter Agreements to be effective April 1, 2015. For further discussion see “—Officer Retention Letter Agreements.”

Option Put Rights. If the executive’s employment is terminated by reason of death or disability, the executive has the right to cause us to all of the vested options in an amount equal to the sum of the excess, if any of the fair market value on the repurchase calculation date over the exercise price. If such sum is zero or a negative number, the options automatically terminate without payment. Additionally, pursuant to the Officer Retention Letter Agreements, options owned by the executive are subject to temporary out rights commencing September 2, 2015. The put rights under the Officer Retention Letter Agreements were terminated pursuant to the Release Letter Agreements to be effective March 31, 2015. For further discussion on the temporary put rights, see “—Potential Payments Upon a Termination or a Change of Control—Officer Letter Retention Agreements” and “—Recent Compensation Actions in 2015.”

Restrictive Covenants. As a condition of purchasing our common stock and receiving the options, our named executive officers agreed to certain restrictive covenants, including confidentiality of information, an 18-month post-termination non-solicitation of employees covenant and a non-compete covenant for up to 18 months post-termination, which are contained in the related 2012 management stockholder’s agreements. The non-solicitation covenant is applicable for each month that the executive receives cash severance payments of no less than the sum total of (i) his then current monthly cash compensation at the time of such termination plus (ii) the amount of the Company’s continued payment for health benefits to the executive. In the event of a breach of such restrictive covenants, the purchased stock and options will be treated as described above as if such executive was terminated for cause. On March 24, 2014, the option award agreements were amended such that any obligation by the executive not to compete with the Company after his termination of employment (for any reason) was removed, but preserving the confidentiality and non-solicitation provisions.

 

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2013 Options

The following describes the terms of the options granted to our named executive officers in fiscal year 2013.

Options Granted to Mr. Limbacher. Twenty-one percent of the shares subject to the options granted to Mr. Limbacher had an exercise price that equaled the grant date fair market value of the underlying shares of our common stock (the “2013 FMV Options”), twenty-one percent of the shares subject to the option had an exercise price that was greater than the grant date fair market value of our common stock (the “2013 Base Price Options”) and fifty-eight percent of the shares subject to the option had an exercise price equal to 1.5x the Base Price Options (the “2013 1.5x Base Price Options”). Mr. Limbacher’s employment agreement was amended on April 1, 2014 to provide for (i) the forfeiture by Mr. Limbacher of 250,000 of the 2013 FMV Options, (ii) the forfeiture by Mr. Limbacher of 250,000 of the 2013 Base Price Options, and (iii) the repricing of 10,000,000 of his 2013 1.5x Base Price Options to an exercise price of $2.50 per share.

Originally, twenty percent of each of the 2013 FMV Options, the 2013 Base Price Options and 2013 1.5x Base Price Options were to vest on each of the first five anniversaries of April 18, 2013, subject to Mr. Limbacher’s continued employment with us on each vesting date. However, pursuant to the terms of the November 14, 2014 Officer Retention Letter Agreement with Mr. Limbacher, all of the options awarded to Mr. Limbacher as of November 14, 2014 will fully vest as of September 1, 2015, or, his termination date in the event he is terminated by the Company for any reason other than Cause prior to September 1, 2015. Additionally, pursuant to the Mr. Limbacher’s employment agreement, the options will become fully vested upon a change of control that occurs during his employment with us. In the event Mr. Limbacher resigns with “good reason” (as such term is defined in his employment agreement and as described below) subsequent to April 18, 2014 and following our initial public offering, affiliates of KKR, ITOCHU and certain other investors (the “Sponsors”) beneficially own less than 40% of our common stock (as measured against the number of shares the Sponsors held on April 18, 2013), then 100% of the shares subject to the option will vest immediately prior to such termination. Any options that remain unvested upon termination of employment and do not vest as described above will be forfeited.

Options Granted to Messrs. Cook, Fraley, Jones and Kidd. On March 24, 2014, we repriced outstanding stock options (including 2013 Options) held by each of our named executive officers, other than Mr. Limbacher, to reduce the exercise price per share to an exercise price of $2.50 per share. All new options granted to named executive officers in 2014 were granted at an exercise price of $2.50 per share.

Twenty percent of each the options vested on December 31, 2013 and December 31, 2014. The options will become fully vested as of September 1, 2015 (pursuant to the Officer Letter Retention Agreements), upon a change of control that occurs during employment with us, or, upon his termination date in the event he is terminated by the Company for any reason other than Cause prior to September 1, 2015. Any options that remain unvested upon termination of employment and do not vest as described above will be forfeited.

Option Put Rights and Option Call Rights. The options granted in 2013 have substantially the same put and call rights that are applicable to the options granted in 2012 described above, other than with respect to the applicable trigger dates for call rights in the event the employee resigns without good reason. However, such options are not entitled to the liquidity program rights applicable to the options awarded in 2012 as described above.

Restrictive Covenants. As a condition of receiving the 2013 options, our named executive officers agreed to certain restrictive covenants, including confidentiality of information, an 18-month post termination non-solicitation of employees covenant, and a 12-month non-compete covenant (in the event of termination for cause or termination with good reason) or an 18-month non-compete covenant (in the event of termination without cause or termination with good reason), which are contained in the related 2013 management stockholder’s agreements. In the event of a breach of the non-solicitation covenant, the options will be treated as described above as if such executive was terminated for cause, and the Company will be entitled to cause any severance

 

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payments or benefits then provided to the executive to immediately cease and if the Company made any payments pursuant to exercise of its call rights, the executive has to repay to the Company any net after tax amounts received from the Company in respect of such vested options and stock. On March 24, 2014, the option award agreements were amended such that any obligation by the executive not to compete with the Company after his termination of employment (for any reason) was removed, but preserving the confidentiality and non-solicitation provisions.

2014 Options

Options Granted to Mr. Fraley. On March 24, 2014, Mr. Fraley was granted 800,000 options at an exercise price of $2.50 per share. 20% of these options vested on March 24, 2015. Pursuant to the terms of the Officer Retention Letter Agreement, the options will fully vest as of September 1, 2015, or, his termination date in the event he is terminated by the Company for any reason other than Cause prior to September 1, 2015. The options will also become fully vested upon a change of control that occurs during employment with us. Any options that remain unvested upon termination of employment and do not vest as described above will be forfeited.

Option Put Rights and Option Call Rights. The options granted in 2014 have substantially the same put and call rights that are applicable to the options granted in 2012 and 2013 described above, other than with respect to the applicable trigger dates for call rights in the event the employee resigns without good reason. However, such options are not entitled to the liquidity program rights applicable to the options awarded in 2012 as described above.

Terms of Restricted Stock Awards

Restricted Stock Granted to Mr. Limbacher. On April 18, 2013, we granted Mr. Limbacher 5,000,000 shares of restricted stock that initially vested with respect to one-third of the shares on each of the third, fourth and fifth anniversaries of April 18, 2013, subject to his continued employment with us on each vesting date. In the event he was terminated by us without “cause” or he resigned with “good reason” at least six months after April 18, 2013 but prior to April 18, 2014, then 20% of the shares would vest as of immediately prior to such termination. If such termination occurred on or after April 18, 2014 but prior to April 18, 2016, Mr. Limbacher would vest, as of the termination date, in the number of shares of restricted stock that would have vested if the vesting schedule was the first five anniversaries of April 18, 2013; provided, however, that if such termination occurs on or subsequent to April 18, 2014 and following our initial public offering, the Sponsors beneficially own less than 40% of our common stock (as measured against the number of shares such investors held on April 18, 2013), then 100% of the shares will vest on the date of such termination. The vesting terms to the 2013 restricted stock awards held by Mr. Limbacher were amended on March 24, 2014, such that the restricted stock awards would vest annually in four equal tranches beginning in April 1, 2015. However, pursuant to the terms of the Officer Retention Letter Agreement, all of Mr. Limbacher’s restricted stock will fully vest as of September 1, 2015, or, his termination date in the event he is terminated by the Company for any reason other than Cause prior to September 1, 2015. All of the shares of restricted stock will also vest in full upon a change of control that occurs during Mr. Limbacher’s employment with us.

On March 24, 2014, we granted Mr. Limbacher 2,500,000 shares of restricted stock, which were originally set to vest with respect to one-fifth of the shares on each of the first, second, third, fourth, and fifth anniversaries of April 1, 2014, subject to Mr. Limbacher’s continued employment with us on each vesting date. In the event he was terminated by us without “cause” or he resigned for “good reason” at least six months after March 24, 2014 but prior to March 24, 2015, then 20% of the shares would vest as of immediately prior to such termination. If such termination occurred on or after March 24, 2015, but prior to March 24, 2018, Mr. Limbacher would vest, as of the termination date, in the number of shares of restricted stock that would have vested if the vesting schedule was the first five anniversaries of March 24, 2014; provided, however, that if such termination occurred on or subsequent to April 1, 2015 and following an initial public offering in which the Sponsors beneficially own less than 40% of our common stock (as measured against the number of shares the Sponsors held on March 24,

 

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2014), then 100% of the shares will vest on the date of such termination. However, pursuant to the terms of his Officer Retention Letter Agreement, all of Mr. Limbacher’s restricted stock will fully vest as of September 1, 2015, or, his termination date in the event he is terminated by the Company for any reason other than Cause prior to September 1, 2015. All of the shares of restricted stock will also vest in full upon a change of control that occurs during Mr. Limbacher’s employment with us. Any shares of that remain unvested upon termination of employment and do not vest as described above will be forfeited.

Restricted Stock Granted to Messrs. Cook, Fraley, Jones and Kidd. We granted 400,000 shares of restricted stock to Mr. Cook on May 20, 2013, and we granted 400,000 shares of restricted stock to Mr. Fraley on July 29, 2013 and 400,000 shares of restricted stock to Mr. Jones on August 5, 2013. The restricted stock granted to Messrs. Fraley and Jones initially was scheduled to vest with respect to one-third of the shares on each of September 4, 2016, September 4, 2017 and September 4, 2018, and the restricted stock granted to Mr. Cook was scheduled to vest with respect to one-third of the shares on each of January 1, 2016, January 1, 2017 and January 1, 2018, subject to the executives’ continued employment with us on each applicable vesting date. In the event the executive was terminated by us without “cause”, the number of shares that would vest on such termination date is determined as if the restricted shares were scheduled to vest with respect to 20% of the shares on each of the first five anniversaries of the applicable vesting commencement date. The vesting terms to the 2013 restricted stock awards held by the executives were amended on March 24, 2014, such that (i) all such restricted stock awards (other than those held by Mr. Limbacher) will immediately vest in the event that the employee’s employment is terminated by us without “cause” or the employee resigns for “good reason,” in each case, within two years of a change in control, and (ii) the 2013 restricted stock awards would vest annually in four equal tranches beginning in April 2015. However, pursuant to the November 14, 2014 Officer Retention Letter Agreements, all of the executive’s restricted stock will fully vest as of September 1, 2015, or, his termination date in the event he is terminated by the Company for any reason other than Cause prior to September 1, 2015. Any shares that remain unvested upon termination of employment and do not vest as described above will be forfeited.

We granted 1,300,000, 1,450,000, 600,000 and 1,000,000 shares of restricted stock to each of Messrs. Cook, Fraley, Jones and Kidd, respectively, on March 24, 2014. The restricted stock granted to these named executive officers will vest 20% on each of the first, second, third, fourth, and fifth anniversaries of April 1, 2014, subject to the named executive officer’s continued employment with us on each vesting date. In the event the named executive officer’s employment terminates due to death or disability, then 20% of the shares that would otherwise vest on the next vesting date will vest upon the date of such termination. In addition, in the event that the named executive officer’s employment is terminated by us other than for “cause” or the named executive officer resigns for “good reason”, in each case, within two years of a change of control, 100% of the shares will vest. However, pursuant to the November 14, 2014 Officer Retention Letter Agreements, all of the executive’s restricted stock will fully vest as of September 1, 2015, or, his termination date in the event he is terminated by the Company for any reason other than Cause prior to September 1, 2015. Any shares that remain unvested upon termination of employment and do not vest as described above will be forfeited.

Put Rights. The restricted stock granted in 2013 and 2014 is subject to a put right if the executive’s employment terminates due to death or disability. In that event, for a specified period following the termination date, the executive (or his estate, as applicable) has the right to cause us to purchase on one occasion all stock at a price equal to fair market value. Additionally, pursuant to the Officer Retention Letter Agreements, if the executive remains employed with the company through September 1, 2015 or is terminated by the company for any reason other than cause prior to September 1, 2015, the restricted stock was to be subject to a temporary put right beginning September 2, 2015. The put rights under the Officer Retention Letter Agreements were terminated pursuant to the Release Letter Agreements to be effective March 31, 2015. For further discussion see “Potential Payments Upon a Termination or a Change of Control —Officer Retention Letter Agreements” and “—Recent Compensation Actions in 2015.”

Call Rights. The stock is also subject to certain call rights in favor of us. If the executive’s employment is terminated by us without cause, the executive resigns for good reason or the executive resigns without good

 

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reason on or after a specified date, we have the right to purchase from the executive all or any portion of the stock then held by the executive at a price equal to fair market value. If the executive’s employment is terminated by us for cause or the executive resigns without good reason prior to such specified date, the repurchase price will be the lesser of the price paid for the shares (which would be zero) or fair market value. Additionally, pursuant to the Officer Retention Letter Agreements, if the executive remains employed with the company through September 1, 2015 or is terminated by the company for any reason other than cause prior to September 1, 2015, the restricted stock was to be subject to a temporary call right beginning September 2, 2015. The call rights under the Officer Retention Letter Agreements were terminated pursuant to the Release Letter Agreements to be effective March 31, 2015. For further discussion see “Potential Payments Upon a Termination or a Change of Control —Officer Retention Letter Agreements” and “—Recent Compensation Actions in 2015.”

Outstanding Equity Awards at 2014 Fiscal Year End

The following table provides information regarding outstanding awards made to our named executive officers as of December 31, 2014.

 

  Option Awards(1)   Stock Awards  

Name

Option
Grant
Date
  Number of
Securities
Underlying
Unexercised
Options
(#)
Exercisable
  Number of
Securities
Underlying
Unexercised
Options
(#)
Unexercisable
  Option
Exercise
Price
($)
  Option
Expiration
Date
  Stock
Award
Grant
Date
  Number of
Shares or
Units of
Stock That
Have Not
Vested
(#)
  Market Value
of Shares or
Units of
Stock That
Have Not
Vested
($)
 

Randy L. Limbacher

  4/18/13      1,200,000      4,800,000 (2)  $ 5.00      4/18/2023      3/24/14      2,500,000 (6)    625,000   
  4/18/13      2,000,000      8,000,000 (2)  $ 2.50      4/18/2023      4/18/13      5,000,000 (5)    1,250,000   
  4/18/13      1,200,000      4,800,000 (2)  $ 4.00      4/18/2023   
  4/18/13      1,500,000      6,000,000 (2)  $ 7.50      4/18/2023   

Philip W. Cook

  5/20/13      480,000      720,000    $ 2.50      5/20/2023      3/24/14      1,300,000 (8)    325,000   
  4/16/12      900,000      300,000 (3)  $ 2.50      4/16/2022      5/20/13      400,000 (7)    100,000   

Richard E. Fraley

  3/24/14      —        800,000 (4)  $ 2.50      3/24/2024      3/24/14      1,450,000 (8)    362,500   
  7/29/13      480,000      720,000    $ 2.50      7/29/2023      7/29/13      400,000 (7)    100,000   
  7/29/13      480,000      720,000    $ 2.50      7/29/2023   

Louis D. Jones

  8/5/13      500,000      750,000    $ 2.50      8/5/2023      3/24/14      600,000 (8)    150,000   
  8/5/13      300,000      450,000    $ 2.50      8/5/2023      8/5/13      400,000 (7)    100,000   

Andrew C. Kidd

  9/9/13      480,000      720,000    $ 2.50      9/9/2023      3/24/14      1,000,000 (8)    250,000   
  9/9/13      240,000      360,000    $ 2.50      9/9/2023   

 

(1) Unless otherwise noted, options vested 20% on December 31, 2013 and 20% on December 31, 2014, and will fully vest on September 1, 2015 or the executive’s termination date in the event he is terminated by the Company for any reason other than Cause prior to September 1, 2015. All options will also vest upon a change of control that occurs during employment with us.
(2) These options vested 20% on April 18, 2014, will vest another 20% on April 18, 2015, and will fully vest on September 1, 2015 or the executive’s termination date in the event he is terminated by the Company for any reason other than Cause prior to September 1, 2015. All options will also vest upon a change in control that occurs during the executive’s employment with us.
(3) These options vested 25% on each of December 21, 2012, December 21, 2013 and December 21, 2014, and will fully vest on September 1, 2015 or the executive’s termination date in the event he is terminated by the Company for any reason other than Cause prior to September 1, 2015. All options will also vest upon a change of control that occurs during employment with us.
(4) These options vested 20% on March 24, 2015, and will fully vest on September 1, 2015 or the executive’s termination date in the event he is terminated by the Company for any reason other than Cause prior to September 1, 2015. All options will also vest upon a change of control that occurs during employment with us.
(5) The stock will vest 25% on April 1, 2015 and will be fully vest on September 1, 2015 or the executive’s termination date in the event he is terminated by the Company for any reason other than Cause prior to September 1, 2015. All of the stock will also vest upon a change of control that occurs during employment with us.

 

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(6) The stock will vest 20% on April 1, 2015 and will fully vest on September 1, 2015 or the executive’s termination date in the event he is terminated by the Company for any reason other than Cause prior to September 1, 2015. All of the stock will also vest upon a change of control that occurs during employment with us.
(7) The stock will vest 25% on April 1, 2015 and will be fully vest on September 1, 2015 or the executive’s termination date in the event he is terminated by the Company for any reason other than Cause prior to September 1, 2015. All of the stock will also vest if, within two years following a change in control, the executive resigns for “good reason.”
(8) The stock will vest 20% on April 1, 2015 and will be fully vest on September 1, 2015 or the executive’s termination date in the event he is terminated by the Company for any reason other than Cause prior to September 1, 2015.All of the stock will also vest if, within two years following a change in control, the executive resigns for “good reason.”

Option Exercises and Stock Vested in Fiscal Year 2014

None of our named executive officers had any stock option exercises or stock vested during 2014.

Pension Benefits

We do not currently provide pension benefits to our employees.

Nonqualified Deferred Compensation

We do not currently provide nonqualified deferred compensation benefits to our employees.

Potential Payments Upon a Termination or a Change of Control

Change in Control Severance Plan for Officers

Under the terms of the Samson Resources Corporation Change in Control Severance Plan for Officers, effective as of January 1, 2014, if (i) the participant’s (which includes all of the named executive officers other than Mr. Limbacher) employment is terminated by the Company without “cause,” or (ii) the participant resigns for “good reason” during the period beginning on the date upon which the definitive agreement that results in the Change in Control (as defined in the Change in Control Severance Plan) takes effect until the date that is two years following the date of the Change in Control, such participant is entitled to receive the following payments, subject to the participant’s execution and non-revocation of a valid release:

 

    A pro-rated portion of the participant’s target bonus for the year of termination, determined by multiplying such target bonus by a fraction, the numerator of which equals the number of days in the relevant fiscal year elapsed through the termination date and the denominator of which equals 365;

 

    A cash payment (the “Cash Payment”) equal to the sum of two times the participant’s (i) annual base salary in effect immediately prior to the date of termination of employment, or, if higher, in effect immediately prior to the first occurrence of an event constituting good reason, plus (ii) three-year average annual bonus received for the three full completed fiscal years preceding (or a lesser number of full years for participants who have not been employed for that long) the change in control; and

 

    Provided that the participant timely elects of continued COBRA coverage, the Company’s reimbursement of COBRA premiums for medical, dental, and vision coverage for the participant and any of his eligible dependents covered as of the participant’s date of termination, for the period of time beginning on his date of termination and continuing for up to 24 months thereafter.

The Cash Payment will be paid in 12 equal monthly installments, with the first installment being paid on the 60th day following the termination date. The Participant will receive the Cash Payment in lieu of any other

 

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severance benefit to which the Participant would be otherwise entitled under any other agreements or arrangements with the Company, excluding those payments and benefits required by law.

The participant’s eligibility to receive these payments is contingent upon him not violating a one-year covenant not to solicit Company employees, and indefinite non-disparagement and confidentiality covenants.

The Change in Control Severance Plan also provides that, in the event that any payment received or to be received by a participant in connection with either a change in control or any termination of a participant’s employment would be subject (in whole or in part) to the excise tax imposed under Section 4999 of the Internal Revenue Code, such payment will be reduced to the extent necessary to avoid any such applicable tax, but only if such reduction would result in greater or equal net after-tax receipt of payments and benefits to the participant.

On November 14, 2014, the Change in Control Severance Plan was amended such that effective September 1, 2015 “Change of Control” shall mean:

(i) the sale of all or substantially all of the assets (i.e., at least 80%) (in one transaction or a series of related transactions) of Samson Resources Corporation (“SRC”), a corporation controlled by affiliates of Kohlberg Kravis Roberts & Co. L.P., Itochu Corporation, Natural Gas Partners L.P. and Crestview Partners II GP, L.P. (together, the “Sponsors”) or Samson Investment Company (“SIC”), as applicable, which, based on transactions consummated as of September 1, 2015, are held by SRC, SIC or any of their respective Subsidiaries or any entity that is controlled by SRC or SIC and are not as of such date contemplated for sale, to any Person (or group of Persons acting in concert), other than to the Sponsors or their affiliates; or (ii) a merger, recapitalization or other sale (in one transaction or a series of related transactions) by SRC, the Sponsors or any of their respective affiliates (which includes, for the avoidance of doubt, SIC), to a Person (or group of Persons acting in concert) of equity interests or voting power that results in any Person (or group of Persons acting in concert) (other than the Sponsors or their affiliates) owning more than 50% of the equity interests or voting power of SRC or SIC, as applicable (or any resulting company after a merger). For purposes of determining if an asset is sold under clause (i) above, the sale of primary equity securities in a direct or indirect subsidiary of SRC or SIC to the public or a third party shall not be deemed to be an asset sale; provided, however, that a sale of secondary equity securities in any such subsidiary shall be considered an asset sale to the extent of such sale. For the avoidance of doubt, none of an initial public offering, stock dividend, stock split or any other similar corporate event shall alone constitute a Change of Control.

Pursuant to its terms, the Change in Control Severance Plan may be amended or terminated by our Compensation Committee at any time, provided that any amendment or termination that materially reduces benefits to, or eliminates, participants, will not be effective until one year after we provide written notice to participants.

Mr. Limbacher’s Employment Agreement

Under the terms of the employment agreement Mr. Limbacher entered into with us, effective as of April 18, 2013, as amended in August 2014, if Mr. Limbacher’s employment is terminated by us without “cause”, he resigns for “good reason” after September 1, 2015, in connection with a “change of control” or upon non-renewal of the agreement by the Company, he will be entitled to receive:

 

    200% of his annual base salary as of the termination date;

 

    200% of the greater of (i) the annual bonus earned in respect of the immediately preceding fiscal year (other than the Special Bonus) and (ii) his target bonus for the current fiscal year; and

 

    a pro-rated portion of his target bonus for the current fiscal year, determined by multiplying such target bonus by a fraction, the numerator of which equals the number of days in the relevant fiscal year elapsed through his termination date and the denominator of which equals 365.

 

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Such cash severance payments would be payable in substantially equal monthly installments over the twenty-four (24) month period beginning on the termination date (the “severance period”); provided that if such termination occurs upon or within two years following a “change of control,” such amount would be payable as a lump sum on the 60th day following his termination date. During the severance period, Mr. Limbacher will also receive reimbursement for the difference between the monthly premium paid by him for continuation coverage under COBRA and the monthly premium charged to our active senior executives for health insurance coverage, subject to earlier cut off if he becomes eligible for health insurance coverage under a subsequent employer’s plan.

Restrictive Covenants. Under the terms of his employment agreement, Mr. Limbacher has agreed not to disclose our confidential information at any time during his employment with us or thereafter, and, for the period during which he is employed with us and for the twenty-four month period following his termination date, he has also agreed not to solicit our employees or anyone engaged to perform services for us. Our obligations to provide cash severance payments under the termination scenarios described above are subject to Mr. Limbacher’s compliance with the confidentiality and non-solicitation covenants unless his termination occurs after a change in control. In addition, if he competes with our business during the severance period, our obligation to make such cash severance payments would end upon the later of 12 months after his termination date and the date on which he first engaged in such restricted activities unless his termination occurs after a change in control.

For purposes of Mr. Limbacher’s employment agreement, “cause” generally means Mr. Limbacher’s (i) commission of any serious crime involving fraud, dishonesty or a breach of trust as to us, (ii) material violation of any our confidential and proprietary information policies or applicable code of conduct policy, (iii) conviction, guilty plea or no contest plea regarding any felony or any crime involving moral turpitude, or (iv) intentional and repeated failure to perform his duties in any material respect (other than due to physical or mental illness or disability) or his gross negligence or intentional misconduct in the performance of his duties. “Good reason” means a material diminution in Mr. Limbacher’s base salary or target bonus opportunity, a relocation of his current place of employment to a location that is more than 25 miles away, or a material diminution in Mr. Limbacher’s duties and responsibilities with us. A “change of control” has the meaning ascribed to such term under our 2011 Plan and is described above under “—Narrative Disclosure to Summary Compensation Table and Grants of Plan-Based Awards in Fiscal 2014 Table—Terms of Option Awards.”

Mr. Cook’s Special Agreement

Under the terms of the special agreement Mr. Cook entered into with us, effective April 16, 2012, as amended in August 2014, if Mr. Cook is terminated without cause or for “good reason” within one year following our “change of control,” he will be entitled to a cash lump sum payment equal to 200% of his annual base salary as of the termination date plus an amount equal to the last annual bonus Mr. Cook received prior to the termination date (other than the Special Bonus). Under the agreement, “good reason” includes and of the following occurring after September 1, 2015: (i) a diminution in Mr. Cook’s annual base salary or opportunity to earn an annual bonus; (ii) relocation of Mr. Cook’s primary place of employment to a location more than 50 miles from his primary place of employment as of immediately prior to such relocation; (iii) a material breach by us of any of our obligations under this agreement; or (iv) the assignment of duties and responsibilities on a continuing basis to Mr. Cook that are materially inconsistent with his position or title prior to such assignment. A “change of control” has the meaning ascribed to such term under our 2011 Plan and is described above under “—Narrative Disclosure to Summary Compensation Table and Grants of Plan-Based Awards in Fiscal 2014 Table—Terms of Option Awards.” As consideration for any severance under this agreement, Mr. Cook must execute, deliver and not revoke a release of claims in favor of us within 60 days following his termination and continue to comply with our confidential information and material policy and our business and ethics code of conduct policy.

Special Agreements with Messrs. Fraley and Jones

Under the terms of the special agreement each of Mr. Fraley and Mr. Jones entered into with us, effective August 1, 2013 and August 5, 2013, respectively, and each as amended in August 2014, if each such executive is

 

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terminated (i) without cause within two years from the date of the agreement or (ii) without cause or for “good reason” within one year following a “change of control,” each will be entitled to a cash lump sum payment equal to 150% of his annual cash compensation as of the termination date, which includes both annual base salary and annual bonus.

Under the special agreement, “good reason” includes a diminution in Mr. Fraley’s or Mr. Jones’ annual base salary or opportunity to earn an annual bonus; relocation of Mr. Fraley’s or Mr. Jones’ primary place of employment to a location more than 50 miles from his primary place of employment as of immediately prior to such relocation; a material breach by us of any of our obligations under this agreement; or the assignment of duties and responsibilities on a continuing basis to Mr. Fraley or Mr. Jones that are materially inconsistent with his position or title prior to such assignment. A “change of control” has the meaning ascribed to such term under our 2011 Plan and is described above under “—Narrative Disclosure to Summary Compensation Table and Grants of Plan-Based Awards in Fiscal 2014 Table—Terms of Option Awards.” As consideration for any severance under this agreement, each executive must execute, deliver and not revoke a release of claims in favor of us within 60 days following his termination and continue to comply with our confidential information and material policy and our business and ethics code of conduct policy.

Additionally, in 2014, Mr. Jones’ special agreement was amended such that in the event of retirement or permanent disability, he has the ability to retain the then vested portion of any restricted stock or stock options (which may be exercised at any time during the term of such options). Mr. Jones employment with the Company was terminated effective March 31, 2015.

Officer Retention Letter Agreements

In order to further incentivize the retention of our officers, including each of our named executive officers, on November 14, 2014, the Company entered into a retention letter agreement with each named executive officer, which provides for, among other things:

 

    If such named executive officer remains employed by the Company through September 1, 2015 (the “Retention Date”) and satisfies the other terms and conditions of the letter agreement, a retention award (the “Retention Award”) having a value equal to two times the sum of such named executive officer’s (1) annual base salary and (2) target bonus for 2015 (the “Retention Award Amount”);

 

    If such executive officer continues employment with the Company after the Retention Date (“Remaining Officer”) he will receive his respective Retention Award in the form of a grant of shares of fully vested stock having a value equal to the Retention Award Amount, which stock will not be subject to forfeiture or repurchase for less than fair market value. Officers that voluntarily terminate their employment as of the Retention Date (“Departing Officer”) will receive their respective Retention Award in the form of cash pursuant to the terms of the Officer Voluntary Severance Plan as described further below.

Both Remaining Officers and Departing Officers receive the accelerated vesting of 100% of all shares of restricted stock and stock options held by such named executive officer as of November 14, 2014, with vesting occurring as of the Retention Date; and

 

    Special “put” and “call” rights with respect to vested shares of restricted stock and stock options that may be exercised within a 30-day period following the Retention Date (with respect to Remaining Officers) or within a 90-day period following the Retention Date (with respect to Departing Officers), which will entitle such officer or the Company, as applicable, to cause the repurchase of such shares and options by the Company in an amount equal to their fair market value on the repurchase date (less the exercise price, in the case of options). At the end of such exercise period, the put and call rights provided for under the retention letter agreements will terminate, and any put, call or other similar rights relating to named executive officer’s equity awards will be governed by the terms and conditions of the 2011 Plan and the related stockholder’s agreements.

 

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The retention letter agreements also provide that if an named executive officer’s employment is terminated by the Company other than for “cause” prior to the Retention Date, such named executive officer will be entitled to, in addition to certain accrued rights, a pro-rated target bonus for the year of termination, (1) subject to executing a release of claims, a cash severance award, paid in 13 substantially equal semi-monthly installments but in no eve