10-K 1 d268745d10k.htm FORM 10-K FORM 10-K
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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

 

Form 10-K

 

 

(Mark One)

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

For the fiscal year ended December 31, 2011

OR

 

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

For the transition period from            to            

Commission File Number: 001-33784

 

 

SANDRIDGE ENERGY, INC.

(Exact name of registrant as specified in its charter)

 

 

 

Delaware   20-8084793

(State or other jurisdiction of

incorporation or organization)

 

(I.R.S. Employer

Identification No.)

123 Robert S. Kerr Avenue

Oklahoma City, Oklahoma

  73102
(Address of principal executive offices)   (Zip Code)

(405) 429-5500

(Registrant’s telephone number, including area code)

 

 

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

 

Title of Each Class

 

Name of Each Exchange on Which Registered

Common Stock, $0.001 par value   New York Stock Exchange

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

None

 

 

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

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

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  þ    No  ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes  þ    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. (Check one):

 

Large accelerated filer  þ   Accelerated filer                    ¨
Non-accelerated filer    ¨ (Do not check if 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  þ

The aggregate market value of our common stock held by non-affiliates on June 30, 2011 was approximately $3.9 billion based on the closing price as quoted on the New York Stock Exchange. As of February 17, 2012, there were 415,391,090 shares of our common stock outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the Company’s definitive proxy statement for the 2011 Annual Meeting of Stockholders are incorporated by reference in Part III.

 

 

 


Table of Contents

SANDRIDGE ENERGY, INC.

2011 ANNUAL REPORT ON FORM 10-K

TABLE OF CONTENTS

 

Item

        Page  
   PART I   

1.

   Business      1   

1A.

   Risk Factors      33   

1B.

   Unresolved Staff Comments      51   

2.

   Properties      51   

3.

   Legal Proceedings      51   

4.

   Mine Safety Disclosures      52   
   PART II   

5.

   Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities      53   

6.

   Selected Financial Data      54   

7.

   Management’s Discussion and Analysis of Financial Condition and Results of Operations      56   

7A.

   Quantitative and Qualitative Disclosures About Market Risk      79   

8.

   Financial Statements and Supplementary Data      82   

9.

   Changes in and Disagreements with Accountants on Accounting and Financial Disclosure      83   

9A.

   Controls and Procedures      83   

9B.

   Other Information      83   
   PART III   

10.

   Directors, Executive Officers and Corporate Governance      84   

11.

   Executive Compensation      84   

12.

   Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters      84   

13.

   Certain Relationships and Related Transactions and Director Independence      84   

14.

   Principal Accounting Fees and Services      84   
   PART IV   

15.

   Exhibits and Financial Statement Schedules      85   


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Information Regarding Forward-Looking Statements

Various statements contained in this report, including those that express a belief, expectation, or intention, as well as those that are not statements of historical fact, are 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”). These forward-looking statements may include projections and estimates concerning 2012 capital expenditures, the Company’s liquidity and capital resources, the timing and success of specific projects, outcomes and effects of litigation, claims and disputes, elements of the Company’s business strategy, statements regarding the Company’s pending acquisition of Dynamic Offshore Resources, LLC (“Dynamic”), and other statements concerning the Company’s operations, economic performance and financial condition. Forward-looking statements are generally accompanied by words such as “estimate,” “assume,” “target,” “project,” “predict,” “believe,” “expect,” “anticipate,” “potential,” “could,” “may,” “foresee,” “plan,” “goal,” “should,” “intend” or other words that convey the uncertainty of future events or outcomes. The Company has based these forward-looking statements on its current expectations and assumptions about future events. These statements are based on certain assumptions and analyses made by the Company in light of its experience and its perception of historical trends, current conditions and expected future developments as well as other factors it believes are appropriate under the circumstances. The actual results or developments anticipated may not be realized or, even if substantially realized, they may not have the expected consequences to, or effects on the Company’s business or results. The forward-looking statements in this report speak only as of the date hereof. The Company disclaims any obligation to update or revise these statements unless required by law, and it cautions readers not to rely on them unduly. While the Company’s management considers these expectations and assumptions to be reasonable, they are inherently subject to significant business, economic, competitive, regulatory and other risks, contingencies and uncertainties relating to, among other matters, the risks discussed in “Risk Factors” in Item 1A of this report, including the following:

 

   

risks associated with drilling oil and natural gas wells;

 

   

the volatility of oil and natural gas prices;

 

   

uncertainties in estimating oil and natural gas reserves;

 

   

the need to replace the oil and natural gas the Company produces;

 

   

the Company’s ability to execute its growth strategy by drilling wells as planned;

 

   

risks to the Company’s ability to drill productive, economically viable oil and natural gas wells;

 

   

risks and liabilities associated with acquired properties and risks related to the integration of acquired businesses;

 

   

amount, nature and timing of capital expenditures, including future development costs, required to develop the Company’s undeveloped areas;

 

   

concentration of operations in the Mid-Continent and west Texas;

 

   

economic viability of certain natural gas production in west Texas due to high CO2 content;

 

   

availability of natural gas production for the Company’s midstream services operations;

 

   

limitations of seismic data;

 

   

the potential adverse effect of commodity price declines on the carrying value of the Company’s oil and natural gas properties;

 

   

severe or unseasonable weather that may adversely affect production;

 

   

availability of satisfactory oil and natural gas marketing and transportation;

 

   

availability and terms of capital to fund capital expenditures;

 

   

amount and timing of proceeds of asset sales and asset monetizations;

 

   

substantial existing indebtedness;


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limitations on operations resulting from debt restrictions and financial covenants;

 

   

potential financial losses or earnings reductions from commodity derivatives;

 

   

potential elimination or limitation of tax incentives;

 

   

competition in the oil and natural gas industry;

 

   

general economic conditions, either internationally or domestically or in the jurisdictions in which the Company operates;

 

   

costs to comply with current and future governmental regulation of the oil and natural gas industry, including environmental, health and safety laws and regulations, and regulations with respect to hydraulic fracturing; and

 

   

the need to maintain adequate internal control over financial reporting.


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PART I

 

Item 1. Business

GENERAL

SandRidge Energy, Inc. (including its consolidated subsidiaries and variable interest entities of which it is the primary beneficiary, the “Company” or “SandRidge”) is an independent oil and natural gas company headquartered in Oklahoma City, Oklahoma, concentrating on development and production activities related to the exploitation of its significant holdings in the Mid-Continent area of Oklahoma and Kansas and in west Texas. The Company’s primary focus in the Mid-Continent area is the Mississippian formation, a shallow hydrocarbon system in northern Oklahoma and Kansas, where it had approximately 1,329,000 net acres under lease at December 31, 2011. The Company’s primary area of focus in west Texas is the Permian Basin, where it had approximately 225,000 net acres under lease at December 31, 2011. The Company’s oil properties in the Permian Basin include properties acquired from Forest Oil Corporation and one of its subsidiaries (collectively, “Forest”) in December 2009 (the “Forest Acquisition”) and properties owned by Arena Resources, Inc. (“Arena”), which was acquired by the Company in July 2010 (the “Arena Acquisition”). The Company also owns and operates other interests in the Mid-Continent, West Texas Overthrust (the “WTO”), Gulf Coast and Gulf of Mexico.

As of December 31, 2011, the Company’s total estimated proved reserves were 470.6 MMBoe, of which approximately 52% were oil and approximately 49% were proved developed. As of December 31, 2011, the Company had 5,043 gross (4,266.9 net) producing wells, substantially all of which it operates, and approximately 2,695,000 gross (2,047,000 net) total acres under lease. As of December 31, 2011, the Company had 21 rigs drilling in the Mid-Continent and 15 rigs drilling in the Permian Basin.

The Company also operates businesses that are complementary to its primary development and production activities, including gas gathering and processing facilities, an oil and natural gas marketing business and an oil field services business, including its wholly owned drilling rig business, Lariat Services, Inc. (“Lariat”). As of December 31, 2011, the Company’s drilling rig fleet consisted of 30 operational rigs. The Company also captures and transports carbon dioxide (“CO2”) to the Permian Basin for use in tertiary recovery projects. “SandRidge CO2” refers to the Company’s wholly owned subsidiary SandRidge CO2, LLC. These complementary businesses provide the Company with operational flexibility and an advantageous cost structure by reducing the Company’s dependence on third parties for these services.

The Company’s principal executive offices are located at 123 Robert S. Kerr Avenue, Oklahoma City, Oklahoma 73102 and the Company’s telephone number is (405) 429-5500. SandRidge makes available free of charge on its website at http://www.sandridgeenergy.com its annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports as soon as reasonably practicable after the Company electronically files such material with, or furnishes it to, the Securities and Exchange Commission (“SEC”). Any materials that the Company has filed with the SEC may be read and copied at the SEC’s Public Reference Room at 100 F Street, N.E., Room 1580, Washington D.C. 20549 or accessed via the SEC’s website address at http://www.sec.gov.

This report includes terms commonly used in the oil and natural gas industry, which are defined in the “Glossary of Oil and Natural Gas Terms” beginning on page 28.

BUSINESS STRATEGY

The Company’s primary objectives are to achieve long-term growth and maximize stockholder value over multiple business cycles by pursuing the following strategies:

 

   

Concentrate in Core Operating Areas. The Company’s primary areas of operation are (1) the Mid-Continent area of Oklahoma and Kansas and (2) west Texas. Concentrating the Company’s

 

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drilling and producing activities in these core areas allows the Company to further build and utilize its technical expertise in order to interpret specific geological and operational trends. By concentrating in these core areas, the Company is able to (i) achieve economies of scale and breadth of operations, both of which help to control costs, and (ii) opportunistically grow its holdings and operations in these areas in order to achieve production and reserve growth.

 

   

Focus on Conventional Reservoirs. The Company focuses its development efforts primarily in areas with conventional, shallow, low-cost, permeable carbonate reservoirs with decades of production history. The nature of these reservoirs allows the Company to execute low-risk, repeatable drilling programs with predictable production profiles and a higher certainty of economic returns. Further, due to these low pressure and shallow characteristics, the Company is able to mitigate rising service costs.

 

   

Pursue Opportunistic Acquisitions. The Company occasionally reviews acquisition targets to complement its existing asset base. Accordingly, the Company selectively identifies such targets based on several factors including relative value, oil content, location and, when appropriate, seeks to acquire them at a discount to other opportunities.

 

   

Maintain Flexibility. The Company has multi-year inventories of both oil and natural gas drilling locations within its core operating areas. Additionally, the Company maintains its own fleet of drilling rigs through Lariat. Maintaining inventories of both oil and natural gas drilling locations as well as its own drilling rigs allows the Company to efficiently direct capital toward projects with the most attractive returns.

 

   

Mitigate Commodity Price Risk. The Company enters into derivative contracts in order to mitigate commodity price volatility inherent in the oil and natural gas industry. By increasing the predictability of cash inflows for a portion of its future production, the Company is better able to ensure funding for its longer term development plans and rates of return on its capital projects.

 

   

Monetize Assets. The Company periodically evaluates its properties to identify opportunities to monetize assets in order to fund or accelerate development within its areas of focus. Proceeds realized from such transactions may be used to pay down amounts outstanding under the Company’s senior secured revolving credit facility (the “senior credit facility”), to fund its drilling program or for general corporate purposes.

2011 DEVELOPMENTS

Divestitures

Sale of Wolfberry Assets. In July 2011, the Company sold its Wolfberry assets in the Permian Basin for $151.6 million, net of fees and post-closing adjustments. The divested properties included approximately 18,000 net acres with production at the time of sale of approximately 1,600 Boe/d.

Sale of New Mexico Assets. In August 2011, the Company sold certain oil and natural gas properties in Lea County and Eddy County, New Mexico, for $199.0 million, net of fees and post-closing adjustments. The divested properties included approximately 23,000 net acres with production at the time of sale of approximately 1,500 Boe/d.

Sale of Working Interest in Mississippian Properties. In September 2011, the Company sold to Atinum MidCon I, LLC (“Atinum”) a 13.2% non-operated working interest, equal to approximately 113,000 net acres, in the Mississippian formation in northern Oklahoma and southern Kansas for approximately $287.0 million, subject to post-closing adjustments. Atinum will fund a drilling carry of 13.2% of SandRidge’s share of drilling and completion costs for wells drilled within an area of mutual interest up to $250.0 million, which is expected to occur over a three-year period.

 

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Sale of East Texas Properties. In November 2011, the Company sold its east Texas natural gas properties in Gregg, Harrison, Rusk and Panola counties for $231.0 million, subject to post-closing adjustments. The divested properties included over 23,000 net acres with production at the time of sale of approximately 4,100 Boe/d.

Royalty Trust Offerings

SandRidge Mississippian Trust I. In April 2011, SandRidge Mississippian Trust I (the “Mississippian Trust I”) completed its initial public offering of 17,250,000 common units representing approximately 61.6% of the beneficial interest in the Mississippian Trust I. Net proceeds to the Mississippian Trust I, after certain offering expenses, were $336.9 million. Concurrent with the closing of the offering, the Company conveyed certain royalty interests to the Mississippian Trust I in exchange for the net proceeds of the offering and 10,750,000 units, representing approximately 38.4% of the beneficial interest, in the Mississippian Trust I.

The Company and one of its wholly owned subsidiaries entered into a development agreement with the Mississippian Trust I that obligates the Company to drill, or cause to be drilled, a specified number of wells within an area of mutual interest, which are also subject to the royalty interest granted to the Mississippian Trust I, within a specified period. One of the Company’s wholly owned subsidiaries also granted a lien to the Mississippian Trust I on the Company’s interests in the properties where the development wells will be drilled in order to secure the estimated amount of the drilling costs for the wells.

The Company has determined that the Mississippian Trust I is a variable interest entity (“VIE”) and the Company is its primary beneficiary. As such, the Company began consolidating the activities of the Mississippian Trust I into its results of operations in April 2011. See Note 3 to the Company’s consolidated financial statements included in Item 8 of this report for further discussion regarding the Company’s consolidation of the Mississippian Trust I.

SandRidge Permian Trust. In August 2011, SandRidge Permian Trust (the “Permian Trust”) completed its initial public offering of 34,500,000 common units representing approximately 65.7% of the beneficial interest in the Permian Trust. Net proceeds to the Permian Trust, after certain offering expenses, were $580.6 million. Concurrent with the closing, the Company conveyed certain royalty interests to the Permian Trust in exchange for the net proceeds of the offering and 18,000,000 units, representing approximately 34.3% of the beneficial interest in the Permian Trust.

The Company and one of its wholly owned subsidiaries entered into a development agreement with the Permian Trust that obligates the Company to drill, or cause to be drilled, a specified number of wells within an area of mutual interest, which are also subject to the royalty interest granted to the Permian Trust, within a specified period. One of the Company’s wholly owned subsidiaries also granted a lien to the Permian Trust on the Company’s interests in the properties where the development wells will be drilled in order to secure the estimated amount of the drilling costs for the wells.

The Company has determined that the Permian Trust is a VIE and the Company is its primary beneficiary. As such, the Company began consolidating the activities of the Permian Trust into its results of operations in August 2011. See Note 3 to the Company’s consolidated financial statements included in Item 8 of this report for further discussion regarding the Company’s consolidation of the Permian Trust.

Debt Transactions

Issuance of 7.5% Senior Notes. In March 2011, the Company issued $900.0 million of unsecured 7.5% Senior Notes due 2021 (the “7.5% Senior Notes”) pursuant to Rule 144A and Regulation S under the Securities Act. Net proceeds from the offering were used to fund the tender offer for and the redemption of the 8.625% Senior Notes due 2015 (the “8.625% Senior Notes”), discussed below. As a result of this issuance, the Company’s borrowing base under its senior credit facility was reduced from $850.0 million to $790.0 million.

 

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Repurchase and Redemption of 8.625% Senior Notes. In March 2011, the Company purchased approximately 94.5%, or $614.2 million, of the 8.625% Senior Notes, originally issued in an aggregate principal amount of $650.0 million, through a cash tender offer. In April 2011, the Company redeemed the remaining outstanding $35.8 million aggregate principal amount of the 8.625% Senior Notes.

2012 DEVELOPMENTS

Sale of Working Interest in Mississippian Properties. In January 2012, SandRidge sold to Repsol E&P USA Inc. (“Repsol”) an approximate 25% non-operated working interest, equal to approximately 250,000 net acres, in the Mississippian formation in western Kansas, and an approximate 16% non-operated working interest, equal to approximately 114,000 net acres and a proportionate share of existing salt water disposal facilities in the Mississippian formation in northern Oklahoma and southern Kansas for approximately $272.5 million. In addition, Repsol will pay for its working interest share of development costs and will fund a portion of SandRidge’s development costs equal to 200% of Repsol’s working interest for wells within an area of mutual interest up to $750.0 million, which is expected to occur over a five-year period.

Proposed Royalty Trust Offering. On January 5, 2012, the Company and SandRidge Mississippian Trust II (the “Mississippian Trust II”), a newly formed Delaware statutory trust, filed a joint registration statement with the SEC for the proposed public offering of common units representing beneficial interests in the Mississippian Trust II. In connection with the offering, the Company intends to convey certain royalty interests to the Mississippian Trust II in exchange for the net proceeds of the offering and units, representing a beneficial interest in the Mississippian Trust II. The royalty interests to be conveyed to the Mississippian Trust II are in certain existing wells and wells to be drilled on certain oil and natural gas properties leased by the Company in the Mississippian formation in northern Oklahoma and Kansas. There can be no assurance that the Company will complete this transaction, as it is subject to market conditions and other uncertainties, as well as completion of the SEC review process. If the transaction is completed, the Company intends to use the net proceeds from the offering for general corporate purposes, including to fund its 2012 capital expenditure program.

Dynamic Acquisition. On February 1, 2012, the Company entered into an agreement to acquire Dynamic, an oil and natural gas exploration, development and production company with operations in the Gulf of Mexico for approximately $1.3 billion, comprised of approximately $680.0 million in cash and approximately 74 million shares of the Company’s common stock. The acquisition, which is expected to close in the second quarter of 2012, is subject to customary closing conditions, including compliance with the applicable waiting period under the Hart-Scott-Rodino Antitrust Improvements Act. The Company has secured $725.0 million in committed financing for the acquisition that it may use to fund the cash portion of the acquisition.

Sale of Trust Units. On February 21, 2012, the Company sold approximately 1.6 million of its Mississippian Trust I common units in a transaction exempt from registration under Rule 144 under the Securities Act for proceeds of $52.3 million.

BUSINESS SEGMENTS AND PRIMARY OPERATIONS

The Company operates in three business segments: exploration and production, drilling and oil field services and midstream gas services. Financial information regarding each segment is provided in Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations.” The information below includes the activities of the Mississippian Trust I and the Permian Trust, including amounts attributable to noncontrolling interest, all of which are included in the exploration and production segment.

Exploration and Production

The Company explores for, develops and produces oil and natural gas reserves, with a primary focus on increasing its reserves and production in the Mid-Continent and Permian Basin. The Company operates substantially all of its wells in these areas and also operates leasehold positions in the WTO, Gulf Coast and Gulf of Mexico.

 

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The following table presents certain information concerning the Company’s exploration and production business as of December 31, 2011, unless otherwise noted.

 

     Estimated Net
Proved
Reserves
(MMBoe)
     PV-10
(in  millions)(1)
     Daily
Production
(MBoe/d)(2)
     Reserves/
Production
(Years)(3)
     Gross
Acreage
     Net
Acreage
 

Area

                 

Mid-Continent

     145.5       $ 2,265.1         19.3         20.7         1,698,222         1,332,292   

Permian Basin

     187.0         3,939.2         30.4         16.8         318,754         224,902   

WTO

     102.5         131.9         10.6         26.5         544,218         419,153   

Gulf Coast

     5.8         83.1         2.2         7.3         65,828         34,160   

Gulf of Mexico

     6.1         44.8         1.3         12.9         56,511         27,772   

Other

     23.7         411.8         0.8         76.1         11,326         9,139   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total

     470.6       $ 6,875.9         64.6         19.9         2,694,859         2,047,418   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

 

(1)

PV-10 generally differs from the Standardized Measure of Discounted Net Cash Flows (“Standardized Measure”) because it does not include the effects of income taxes on future net revenues. For a reconciliation of PV-10 to Standardized Measure, see “—Proved Reserves.” The Company’s total Standardized Measure was $5.2 billion at December 31, 2011.

(2)

Average daily net production for the month of December 2011.

(3)

Estimated net proved reserves as of December 31, 2011 divided by production for the year ended December 31, 2011.

Properties

Mid-Continent

The Company held interests in approximately 1,698,000 gross (1,332,000 net) leasehold and option acres in Oklahoma and Kansas at December 31, 2011. Associated proved reserves at December 31, 2011 totaled 145.5 MMBoe, 41% of which were proved developed reserves, based on estimates prepared by Netherland Sewell & Associates, Inc. (“Netherland Sewell”) and the Company’s internal engineers. The Company’s interests in the Mid-Continent as of December 31, 2011 included 836 gross (408.8 net) producing wells with an average working interest of 49.5%. Average daily net production from the Mid-Continent area was approximately 19.3 MBoe for the month of December 2011. The Company had 21 rigs operating in the Mid-Continent as of December 31, 2011, three of which were drilling saltwater disposal wells, and drilled 167 horizontal wells during 2011.

Mississippian Formation. The Company’s primary focus within the Mid-Continent area is the Mississippian formation, which is an expansive carbonate hydrocarbon system located on the Anadarko Shelf in northern Oklahoma and Kansas. The top of this formation is encountered between approximately 4,000 and 7,000 feet and lies stratigraphically between the Pennsylvanian-aged Morrow formation and the Devonian-aged Woodford Shale formation. The Mississippian formation can reach 1,000 feet in gross thickness and the targeted porosity zone is between 50 and 100 feet in thickness. The formation’s geology is well understood as a result of the thousands of vertical wells drilled and produced there since the 1940s. At December 31, 2011, the Company had approximately 1,692,000 gross (1,329,000 net) acres under lease, of which approximately 49,600 gross (42,000 net) acres were included in the Mississippian Trust I’s area of mutual interest.

In 2007, the application of horizontal cased-hole drilling and multi-stage hydraulic fracturing treatments demonstrated the potential for extracting significant additional quantities of oil and natural gas from the formation. Since the beginning of 2009, there have been over 400 horizontal wells drilled in the Mississippian formation in northern Oklahoma and Kansas, including 205 drilled by the Company as of December 31, 2011. From December 31, 2010 to December 31, 2011, the number of the Company’s producing horizontal wells in the Mississippian formation increased from 44 to 174. As of December 31, 2011, there were approximately

 

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43 horizontal rigs drilling in the formation, with 18 of those rigs drilling for the Company. The Company drilled a total of 167 horizontal wells in the Mississippian formation during 2011, including 48 wells subject to the Mississippian Trust I’s royalty interest.

Permian Basin

The Permian Basin extends throughout southwestern Texas and southeastern New Mexico over an area approximately 250 miles wide and 300 miles long. It is one of the largest, most active and longest-producing oil basins in the United States. In 2010, production from the Permian Basin accounted for approximately 17% of total United States crude oil production, making this basin the second largest oil producing area in the continental United States after the Gulf of Mexico. The Permian Basin has been producing oil for over 80 years resulting in cumulative production of approximately 29 billion barrels.

The Company held interests in approximately 319,000 gross (225,000 net) leasehold acres in the Permian Basin at December 31, 2011, of which approximately 17,500 gross (16,000 net) acres were included in the Permian Trust’s area of mutual interest. Associated proved reserves at December 31, 2011 were 187.0 MMBoe, 58% of which were proved developed reserves, based on estimates provided by independent oil and natural gas consulting firms, Netherland Sewell and Lee Keeling and Associates, Inc. (“Lee Keeling”). The Company’s interests in the Permian Basin as of December 31, 2011 included 3,125 gross (2,976.0 net) producing wells with an average working interest of 96.2%. The Company’s average daily net production was approximately 30.4 MBoe for the month of December 2011. The Company had 15 rigs operating in the Permian Basin as of December 31, 2011 and drilled 803 wells in this area during 2011, of which 195 were subject to the Permian Trust’s royalty interest.

Central Basin Platform. The Company significantly expanded its holdings in the Permian Basin, specifically the Central Basin Platform (“CBP”) where it drilled all of its Permian Basin wells in 2011, through the Forest Acquisition in December 2009 and the Arena Acquisition in July 2010. These acquisitions added significant Permian Basin production from the Midland and Delaware Basins in Texas as well as the Northwest Shelf in New Mexico. Reserves and associated production in this area are predominantly oil. The primary reservoirs in the CBP are the dolomites and limestones of the Grayburg-San Andres and Clear Fork formations. To date, the San Andres and Clear Fork zones have produced more than 4.0 and 1.8 billion barrels of oil, respectively, with well depths typically ranging from 4,500 to 7,500 feet. The Company’s properties in the CBP are positioned for infill and step-out drilling to target these reservoirs in several of the major CBP fields, such as the Fuhrman-Mascho, Goldsmith, Fullerton, Tex-Mex, Brooklaw and Robertson Fields.

West Texas Overthrust

The Company has drilled and developed natural gas in the WTO since 1986. This area is located in Pecos and Terrell counties in west Texas and is associated with the Marathon-Ouachita fold and thrust belt that extends east-northeast across the United States into the Appalachian Mountain Region. The primary reservoir rocks in the WTO range in depth from 2,000 to 17,000 feet and range in geologic age from the Permian to the Devonian. The imbricate stacking of these conventional gas-prone reservoirs provides for multi-pay exploration and development opportunities. Despite these opportunities, the WTO has historically been under-explored. The high CO2 content of the natural gas, lack of infrastructure in the region and historical limitations of conventional subsurface geological and geophysical methods have combined to discourage exploration of the area. Additionally, low natural gas prices continue to limit activity in this area.

The Company held interests in approximately 544,000 gross (419,000 net) leasehold acres in the WTO at December 31, 2011. Associated proved reserves at December 31, 2011 were 102.5 MMBoe, 45% of which were proved developed reserves, based on estimates provided by Netherland Sewell. The Company’s interests in the WTO as of December 31, 2011 included 880 gross (745.4 net) producing wells with an average working interest of 95.3%. The Company’s average daily net production was approximately 10.6 MBoe for the month of December 2011.

 

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Century Plant. In order to facilitate expansion of CO2 treating capacity in the WTO, the Company is constructing a CO2 treatment plant in Pecos County, Texas (the “Century Plant”), and associated compression and pipeline facilities pursuant to an agreement with Occidental Petroleum Corporation (“Occidental”). Under the terms of the agreement, Occidental will pay the Company a minimum of 100% of the contract price, or $800.0 million, plus any subsequently agreed-upon revisions, through periodic cost reimbursements based upon the percentage of the project completed by the Company. The Company expects to complete the Century Plant in two phases. Phase I is in the commissioning process with completion and transfer of title to Occidental expected in early 2012, and Phase II is under construction and expected to be completed in 2012. Upon completion of each phase of the Century Plant, Occidental will take ownership of the related assets and will operate the Century Plant for the purpose of separating and removing CO2 from delivered natural gas. Contract losses on the construction of the Century Plant are recorded as development costs within the Company’s oil and natural gas properties as part of the full cost pool, when it is determined that a loss will be incurred. Contract gains, if any, are recorded at the end of the project. As of December 31, 2011, the Company had recorded additions of $130.0 million to its oil and natural gas properties for the estimated loss identified based on current projections of the costs to be incurred in excess of contract amounts.

Pursuant to a 30-year treating agreement executed simultaneously with the construction agreement to build the Century Plant, Occidental will remove CO2 from the Company’s delivered natural gas production volumes. Under this agreement, the Company will be required to deliver certain CO2 volumes annually once Occidental takes title of Phase I, and will have to compensate Occidental to the extent such requirements are not met. Based upon current natural gas production levels, the Company expects to accrue between approximately $17.0 million and $21.0 million during the year ending December 31, 2012 for amounts related to the Company’s shortfall in meeting its delivery obligations based on the projected completion date of Phase I of the Century Plant. Due to the sensitivity of natural gas production to prevailing market prices, the Company is unable to estimate additional amounts it may be required to pay under this agreement in subsequent periods. The Company will retain all methane gas from the natural gas it delivers to the Century Plant.

Gulf Coast

As of December 31, 2011, the Company owned oil and natural gas interests in approximately 66,000 gross (34,000 net) acres in the Gulf Coast area, which encompasses the large coastal plain from the southernmost tip of Texas through the southern portion of Louisiana. As of December 31, 2011, the Company’s estimated net proved reserves in the Gulf Coast area was 5.8 MMBoe with average daily net production of approximately 2.2 MBoe for the month of December 2011.

Gulf of Mexico

As of December 31, 2011, the Company owned oil and natural gas interests in approximately 57,000 gross (28,000 net) acres in state and federal waters off the coasts of Texas and Louisiana. As of December 31, 2011, the Company’s estimated net proved reserves in the Gulf of Mexico was 6.1 MMBoe with average daily net production of approximately 1.3 MBoe for the month of December 2011. The Company’s operations in the Gulf of Mexico extend from the coast to more than 100 miles offshore and occur in waters ranging from 30 to 1,100 feet.

Tertiary Oil Recovery

The Company currently operates three enhanced recovery projects, consisting of one active CO2 flood and two waterfloods in which CO2 pilot projects are currently under development. All three floods are located in the Permian Basin area of west Texas. The Wellman Unit, located in Terry County, is an active CO2 flood in which CO2 injection was re-initiated in November 2005. The two prospective CO2 pilot waterfloods are the George Allen Unit and the South Mallet Unit, located in Gaines and Hockley Counties. Injection is expected to begin into the George Allen pilot in 2012 and into the South Mallet pilot in 2013. The three enhanced recovery projects had average daily net production of approximately 0.8 MBoe for the month of December 2011 and have

 

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produced a total of 113.4 MMBoe to date. As of December 31, 2011, net proved reserves attributable to the three projects were 23.6 MMBoe. Expansion opportunities exist in all three projects and will be evaluated based on early performance results.

Proved Reserves

The oil and natural gas reserves in this report are based on reserve reports, substantially all of which were prepared by independent petroleum engineers. The process to review and estimate the reserves begins with one of the Company’s staff reservoir engineers collecting and verifying all pertinent data, including but not limited to well test data, production data, historical pricing, cost information, property ownership interests, reservoir data, geosciences data and non-confidential production data of relevant wells and operations in the area. This data was reviewed by various levels of management for accuracy, before consultation with independent petroleum engineers. Such consultation includes review of properties, assumptions and any new data available. Internal reserves estimates and methodologies were compared to those prepared by independent petroleum engineers to test the reserves estimates and conclusions before the reserves estimates were included in this report.

SandRidge’s Executive Vice President—Reservoir Engineering is the technical person primarily responsible for overseeing the preparation of the Company’s reserves estimates. He has a Bachelor of Science degree in Mechanical Engineering with over 30 years of practical industry experience, including over 25 years of estimating and evaluating reserve information. In addition, the Company’s Executive Vice President—Reservoir Engineering has been a certified professional engineer in the state of Oklahoma since 1988 and a member of the Society of Petroleum Engineers since 1980.

SandRidge’s Reservoir Engineering Department continually monitors asset performance, making reserves estimate adjustments, as necessary, to ensure the most current reservoir information is reflected in reserves estimates. Reserve information includes production histories as well as other geologic, economic, ownership and engineering data. The department currently has a total of 19 full-time employees, comprised of eight degreed engineers and 11 engineering analysts/technicians with a minimum of a four-year degree in mathematics, economics, finance or other business or science field.

The Company maintains a continuous education program for its engineers and technicians on new technologies and industry advancements and also offers refresher training on basic skill sets.

In order to ensure the reliability of reserves estimates, internal controls observed within the reserve estimation process include:

 

   

No employee’s compensation is tied to the amount of reserves booked.

 

   

Reserves estimates are prepared by experienced reservoir engineers or under their direct supervision.

 

   

The Reservoir Engineering Department reports directly to the Company’s President, independently from all of the Company’s operating divisions.

 

   

The Reservoir Engineering Department follows comprehensive SEC-compliant internal policies to determine and report proved reserves including:

 

   

confirming that reserves estimates include all properties owned and are based upon proper working and net revenue interests;

 

   

reviewing and using in the estimation process data provided by other departments within the Company such as Accounting; and

 

   

comparing and reconciling internally generated reserves estimates to those prepared by third parties.

 

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Each quarter, the Executive Vice President—Reservoir Engineering presents the status of the Company’s reserves to a committee of executives, which subsequently approves all changes. In the event the quarterly updated reserves estimates are disclosed, the aforementioned review process is evidenced by signatures from the Executive Vice President—Reservoir Engineering and the Chief Financial Officer.

The Reservoir Engineering Department works closely with its independent petroleum consultants at each fiscal year end to ensure the integrity, accuracy and timeliness of annually developed independent reserves estimates. These independently developed reserves estimates are adopted as the Company’s corporate reserves and are reviewed by the Audit Committee, as well as the Chief Financial Officer, Senior Vice President of Accounting, Vice President of Internal Audit, Vice President of Financial Reporting, Treasurer and General Counsel. In addition to reviewing the independently developed reserve reports, the Audit Committee annually interviews the third-party engineer at Netherland Sewell who is primarily responsible for the reserve report. The Audit Committee also periodically interviews the other independent petroleum consultants used to prepare estimates of proved reserves.

The table below shows the percentage of the Company’s total proved reserves for which each of the independent petroleum consultants prepared reports of estimated proved reserves of oil and natural gas for the years shown.

 

     December 31,  
     2011     2010     2009  

Netherland, Sewell & Associates, Inc.

     80.5     71.9     51.7

Lee Keeling and Associates, Inc.

     15.6     20.3     33.7

DeGolyer and MacNaughton

     —          4.3     9.6
  

 

 

   

 

 

   

 

 

 

Total

     96.1     96.5     95.0
  

 

 

   

 

 

   

 

 

 

The remaining 3.9%, 3.5% and 5.0% of the Company’s estimated proved reserves as of December 31, 2011, 2010 and 2009, respectively, were based on internally prepared estimates.

Copies of the reports issued by the Company’s independent petroleum consultants with respect to the Company’s oil and natural gas reserves as of December 31, 2011 are filed with this report as Exhibits 99.1 – 99.2. The geographic location of the Company’s estimated proved reserves prepared by each of the independent petroleum consultants as of December 31, 2011 is presented below.

 

    

Geographic Locations—by Area by State

Netherland, Sewell & Associates, Inc.

  

Permian Basin—KS, OK, TX

Mid-Continent—KS, OK

WTO—TX

Gulf Coast—LA, TX

Gulf of Mexico

Tertiary recovery—TX

Other—AL, MS, ND

Lee Keeling and Associates, Inc.

   Permian Basin—NM, TX

The qualifications of the technical person at each of these firms primarily responsible for overseeing the firm’s preparation of the Company’s reserves estimates included in this report are set forth below. These qualifications meet or exceed the Society of Petroleum Engineers standard requirements to be a professionally qualified Reserve Estimator and Auditor.

Netherland, Sewell & Associates, Inc.

 

   

more than 30 years of practical experience in petroleum engineering and almost 15 years estimating and evaluating reserve information;

 

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a registered professional engineer in the states of Texas, Louisiana and Wyoming; and

 

   

a Bachelor of Science Degree in Civil Engineering and Masters in Business Administration.

Lee Keeling and Associates, Inc.

 

   

57 years of practical experience in petroleum engineering and more than 48 years estimating and evaluating reserve information;

 

   

a registered professional engineer in the state of Oklahoma; and

 

   

a Bachelor of Science Degree in Petroleum Engineering.

DeGolyer and MacNaughton

 

   

35 years of experience in oil and gas reservoir studies and reserve evaluations at the time of its most recent report;

 

   

a registered professional engineer in the state of Texas; and

 

   

a Bachelor of Science Degree in Petroleum Engineering.

The following estimates of proved oil and natural gas reserves are based on reserve reports as of December 31, 2011, 2010 and 2009, substantially all of which were prepared by independent petroleum engineers. The estimates include reserves attributable to the Mississippian Trust I and the Permian Trust, including amounts associated with noncontrolling interest. The PV-10 values shown in the table below are not intended to represent the current market value of the Company’s estimated oil and natural gas reserves as of the dates shown. The reserve reports were based on the Company’s drilling schedule and the average price during the 12-month period ended December 31, 2011, 2010 and 2009, using first-day-of-the-month prices for each month. The Company estimates that approximately 73% of its current proved undeveloped reserves will be developed by 2013 and all of its current proved undeveloped reserves will be developed by 2014. See “Critical Accounting Policies and Estimates” in Item 7 of this report for further discussion of uncertainties inherent to the reserves estimates. See Note 25 in Item 8 of this report for reserve and standardized measure of discounted net cash flows amounts attributable to noncontrolling interests.

 

     December 31,  
     2011      2010      2009  

Estimated Proved Reserves(1)

        

Developed

        

Oil (MMBbls)

     118.7         92.0         38.3   

Natural gas (Bcf)(2)

     670.4         784.3         592.8   
  

 

 

    

 

 

    

 

 

 

Total proved developed (MMBoe)

     230.4         222.7         137.1   

Undeveloped

        

Oil (MMBbls)

     126.1         160.1         67.0   

Natural gas (Bcf)(2)

     684.7         978.4         87.3   
  

 

 

    

 

 

    

 

 

 

Total proved undeveloped (MMBoe)

     240.2         323.2         81.6   

Total Proved

        

Oil (MMBbls)

     244.8         252.1         105.3   

Natural gas (Bcf)(2)

     1,355.1         1,762.7         680.1   
  

 

 

    

 

 

    

 

 

 

Total proved (MMBoe)(3)

     470.6         545.9         218.7   
  

 

 

    

 

 

    

 

 

 

PV-10 (in millions)(4)

   $ 6,875.9       $ 4,509.2       $ 1,561.0   

Standardized Measure of Discounted Net Cash Flows (in millions)(3)(5)

   $ 5,216.3       $ 3,683.5       $ 1,561.0   

 

(1)

The Company’s estimated proved reserves and the future net revenues, PV-10 and Standardized Measure were determined using a 12-month average price for oil and natural gas. The prices used in the Company’s

 

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external and internal reserve reports yield weighted average wellhead prices, which are based on index prices and adjusted for transportation and regional price differentials. The index prices and the equivalent weighted average wellhead prices are shown in the table below.

 

       Weighted average wellhead prices        Index prices  
     Oil (per Bbl)      Natural gas
(per Mcf)
     Oil (per Bbl)      Natural gas
(per Mcf)
 

December 31, 2011

   $ 85.77       $ 4.06       $ 92.71       $ 4.12   

December 31, 2010

   $ 66.93       $ 3.80       $ 75.96       $ 4.38   

December 31, 2009

   $ 49.98       $ 3.41       $ 57.65       $ 3.87   

 

(2)

The Company’s production from the WTO contains natural gas that is high in CO2 content. These amounts are net of CO2 volumes that exceed pipeline quality specifications.

(3)

At December 31, 2011, estimated total proved reserves and Standardized Measure attributable to noncontrolling interests were approximately 26.3 MMBoe and approximately $932.8 million, respectively. There were no proved reserves or Standardized Measure attributable to noncontrolling interest at December 31, 2010 or 2009.

(4)

PV-10 is a non-GAAP financial measure and represents the present value of estimated future cash inflows from proved oil and natural gas reserves, less future development and production costs, discounted at 10% per annum to reflect timing of future cash flows and using 12-month average prices for the years ended December 31, 2011, 2010 and 2009. PV-10 differs from Standardized Measure because it does not include the effects of income taxes on future net revenues. Due to the full valuation allowance on the Company’s net deferred tax asset at December 31, 2009 that reduced to zero a tax benefit that otherwise would result from the tax effects of PV-10, there was no effect of income taxes on Standardized Measure at December 31, 2009. Neither PV-10 nor Standardized Measure represents an estimate of fair market value of the Company’s oil and natural gas properties. PV-10 is used by the industry and by the Company’s management as an arbitrary reserve asset value measure to compare against past reserve bases and the reserve bases of other business entities that are not dependent on the taxpaying status of the entity. The following table provides a reconciliation of the Company’s Standardized Measure to PV-10:

 

     December 31,  
     2011      2010      2009  
     (In millions)  

Standardized Measure of Discounted Net Cash Flows

   $ 5,216.3       $ 3,683.5       $ 1,561.0   

Present value of future income tax discounted at 10%

     1,659.6         825.7         —     
  

 

 

    

 

 

    

 

 

 

PV-10

   $ 6,875.9       $ 4,509.2       $ 1,561.0   
  

 

 

    

 

 

    

 

 

 

 

(5)

Standardized Measure represents the present value of estimated future cash inflows from proved oil and natural gas reserves, less future development and production costs, and income tax expenses, discounted at 10% per annum to reflect timing of future cash flows and using the same pricing assumptions used to calculate PV-10. Standardized Measure differs from PV-10 as Standardized Measure includes the effect of future income taxes. Due to the full valuation allowance on the Company’s net deferred tax asset at December 31, 2009 that reduced to zero a tax benefit that otherwise would result from the tax effects of PV-10, there was no effect of income taxes on Standardized Measure at December 31, 2009.

Technologies. Under SEC rules, proved reserves are 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 known reservoirs from a given date forward, 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. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. The term “reasonable certainty” implies a high degree of confidence that the quantities of oil and/or natural gas actually

 

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recovered will equal or exceed the estimate. Reasonable certainty can be established using techniques that have been proved effective by actual production from projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology that establishes reasonable certainty. Reliable technology is a grouping of one or more technologies (including computational methods) that have been field tested and have been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.

The area of a reservoir considered proved includes (i) the area identified by drilling and limited by fluid contacts, if any, and (ii) adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or natural gas on the basis of available geoscience and engineering data. In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons as seen in a well penetration unless geoscience, engineering or performance data and reliable technology establish a lower contact with reasonable certainty.

Where direct observation from well penetrations has defined a highest known oil elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering or performance data and reliable technology establish the higher contact with reasonable certainty.

Reserves that can be produced economically through application of improved recovery techniques (such as fluid injection) are included in the proved classification when (i) successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir, or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based and (ii) the project has been approved for development by all necessary parties and entities, including governmental entities.

Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. In determining the amount of proved reserves, the price used must be the average price during the 12-month period prior to the ending date of the period covered by the reserve report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

The estimates of proved developed reserves included in the reserve report were prepared using decline curve analysis to determine the reserves of individual producing wells. After estimating the reserves of each proved developed well, it was determined that a reasonable level of certainty exists with respect to the reserves that can be expected from close offset undeveloped wells in the field.

Proved reserves in the Mid-Continent, primarily the Mississippian formation, increased from 63.0 MMBoe at December 31, 2010 to 145.5 MMBoe at December 31, 2011, which comprises a significant portion of the additions to the Company’s proved reserves. For the Company’s Mississippian formation development, continuity of the formation across the development area was established by reviewing electric well logs, geologically mapping the analogous reservoir and reviewing extensive production data from more than 1,400 vertical and 178 horizontal wells. The reserves attributable to producing wells and the continuity of the formation over the development area further supports proved undeveloped classification within close proximity to the producing wells. Data from both the Company and offset operators with which it has exchanged technical data demonstrate a consistency in this formation and the in situ fluids over an area much larger than the development area. In addition, direct measurement from other producing wells was also used to confirm consistency in reservoir properties such as porosity, thickness and stratigraphic conformity. While vertical well control exists across all of the development area most of the existing producing horizontal wells were drilled without benefit of a direct offset producing lateral section. These wells all encountered proven reserves in the Mississippian formation. The proved undeveloped locations within the development area are generally direct parallel offsets to the horizontal wells drilled and producing to date.

 

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Proved Undeveloped Reserves. During 2011, the Company drilled 855 wells and approximately $817.0 million of its drilling capital expenditures were used to convert approximately 50.3 MMBoe of proved undeveloped reserves to proved developed reserves. At December 31, 2011, 763 of these wells were classified as proved developed producing properties with the remaining wells still in progress. During 2010, the Company drilled 424 wells and approximately $480.7 million of its drilling capital expenditures were used to convert approximately 37.4 MMBoe of proved undeveloped reserves to proved developed reserves. At December 31, 2010, 392 of these wells were classified as proved developed producing properties with the remaining wells still in progress. During 2009, the Company drilled 104 wells and approximately $128.6 million of its drilling capital expenditures were used to convert approximately 8.7 MMBoe of proved undeveloped reserves to proved developed reserves. At December 31, 2009, 92 of these wells were classified as proved developed producing properties with the remaining wells still in progress.

Excluding asset sales, the Company recognized a net addition to oil and natural gas reserves associated with proved undeveloped properties in 2011. Additional reserves attributable to extensions and discoveries, primarily in the Permian Basin and Mid-Continent areas as a result of successful drilling, more than offset downward revisions of reserve quantities from the Piñon Field as a result of lower natural gas index prices. The 12-month average natural gas index price of $4.38 per Mcf for 2010 decreased to $4.12 per Mcf for 2011. For additional information, see Note 25 to the Company’s consolidated financial statements in Item 8 of this report.

In 2010, the Company recognized additional oil and natural gas reserves attributable to extensions and discoveries as a result of successful drilling in the Permian Basin and Mid-Continent areas. The 12-month average natural gas index price of $4.38 per Mcf used in the estimation of natural gas reserves as of December 31, 2010, compared to the 12-month average natural gas index price of $3.87 per Mcf for 2009, resulted in upward revisions of quantities associated with the Company’s proved undeveloped properties. There were no downward revisions as a result of the 12-month average oil index price used in the estimation of reserves as of December 31, 2010.

The 12-month average natural gas index price of $3.87 per Mcf used in the estimation of reserves as of December 31, 2009 resulted in downward revisions of quantities associated with the Company’s proved undeveloped properties as a significant number of properties generated no PV-10 value resulting in the elimination of associated reserve quantities and a shortening of the productive lives of certain proved properties that became uneconomic earlier in their lives with the use of lower natural gas prices compared to prices used in the estimation of reserves in previous periods.

Fields. Three fields, the Mississippi Lime Horizontal, the Fuhrman-Mascho and the Piñon, each contained more than 15% of the Company’s total proved reserves at December 31, 2011. These fields are described further below.

Mississippi Lime Horizontal Field. The Mississippi Lime Horizontal Field is located on the Anadarko Shelf in northern Oklahoma and Kansas and produces from the Mississippian formation. The Company has estimated proved oil and natural gas reserves in the Mississippi Lime Horizontal Field of 128 MMBoe as of December 31, 2011. The Company’s interests in the Mississippi Lime Horizontal Field as of December 31, 2011 included 200 gross (147.9 net) producing wells and a 73.9% average working interest in the producing area.

Fuhrman-Mascho Field. The Fuhrman-Mascho Field is located near the center of the CBP in the Permian Basin and produces from the Grayburg-San Andres formation from average depths of approximately 4,000 to 5,000 feet. The Fuhrman-Mascho Field is the fifth largest producing field in the Permian Basin and has produced approximately 142 MMBoe since its discovery in 1930. The Company has estimated proved oil and natural gas reserves in the Fuhrman-Mascho Field of 89 MMBoe as of December 31, 2011. The Company’s interests in the Fuhrman-Mascho Field as of December 31, 2011 included 1,761 gross (1,709.9 net) producing wells and a 97.1% average working interest in the producing area.

 

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Piñon Field. The Piñon Field lies along the leading edge of the WTO in Pecos County, Texas. The primary reservoirs are the Tesnus sands (depths ranging from 3,500 to 5,000 feet), the Warwick Caballos chert (depths ranging from 5,000 to 8,000 feet) and the Dugout Creek Caballos chert (depths ranging from 7,000 to 10,000 feet). As of December 31, 2011, the Company’s estimated proved oil and natural gas reserves in the Piñon Field were 102.4 MMBoe. The Company’s interests in the Piñon Field as of December 31, 2011 included 870 gross (738.1 net) producing wells and a 95.6% average working interest in the producing area.

The following table presents oil and natural gas production for the years presented, for fields containing more than 15% of the Company’s total proved reserves in that year.

 

     2011  
     Oil
(MBbls)
     Natural Gas
(Bcf)
     Total
(MBoe)
 

Field

        

Mississippi Lime Horizontal

     1,209.5         8.3         2,598.2   

Fuhrman-Mascho

     3,768.5         1.6         4,040.7   

Piñon

     41.0         28.2         4,748.7   

 

     2010  
     Oil
(MBbls)
     Natural Gas
(Bcf)
     Total
(MBoe)
 

Fuhrman-Mascho(1)

     1,468.4         0.7         1,587.3   

Piñon

     60.8         40.3         6,779.9   

 

     2009  
     Oil
(MBbls)
     Natural Gas
(Bcf)
     Total
(MBoe)
 

Piñon

     108.1         52.2         8,812.8   

 

(1)

Production is from date property was acquired, or July 16, 2010, through December 31, 2010.

Production and Price History

The following tables set forth information regarding the Company’s net oil and natural gas production and certain price and cost information for each of the periods indicated. Because of the relatively high volumes of CO2 produced with natural gas in certain areas of the WTO, the Company’s reported sales and reserves volumes and the related unit prices received for natural gas in these areas are reported net of CO2 volumes removed at the gas treating plants. The gas treating plant fees for removing CO2 from the Company’s natural gas that has high CO2 content are included in the Company’s lease operating expenses as processing, treating and gathering fees. All natural gas delivered to sales points with CO2 levels within pipeline specifications is included in sales and reserves volumes.

 

     Year Ended December 31,  
     2011      2010      2009  

Production Data

        

Oil (MBbls)(1)

     11,830         7,386         2,894   

Natural gas (MMcf)

     69,306         76,226         87,461   

Total volumes (MBoe)

     23,381         20,090         17,471   

Average daily total volumes (MBoe/d)

     64.1         55.0         47.9   

 

     Year Ended December 31,  
     2011      2010      2009  

Average Prices(2)

        

Oil (per Bbl)(1)

   $ 83.21       $ 66.89       $ 55.62   

Natural gas (per Mcf)

   $ 3.50       $ 3.68       $ 3.36   

Total (per Boe)

   $ 52.47       $ 38.56       $ 26.03   

 

(1)

Includes natural gas liquids.

 

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(2)

Prices represent actual average prices for the periods presented and do not include effects of derivative transactions.

 

     Year Ended December 31,  
     2011      2010      2009  

Expenses per Boe

        

Lease operating expenses

        

Transportation

   $ 0.71       $ 0.60       $ 0.66   

Processing, treating and gathering(1)

     1.59         1.92         2.17   

Other lease operating expenses

     10.73         8.54         6.29   
  

 

 

    

 

 

    

 

 

 

Total lease operating expenses

   $ 13.03       $ 11.06       $ 9.12   
  

 

 

    

 

 

    

 

 

 

Production taxes(2)

   $ 1.97       $ 1.45       $ 0.23   
  

 

 

    

 

 

    

 

 

 

Ad valorem taxes

   $ 0.78       $ 0.78       $ 0.60   
  

 

 

    

 

 

    

 

 

 

 

(1)

Includes costs attributable to gas treatment to remove CO2 and other impurities from natural gas.

(2)

Net of severance tax refunds.

Productive Wells

The following table sets forth the number of productive wells in which the Company owned a working interest at December 31, 2011. Productive wells consist of producing wells and wells capable of producing, including oil wells awaiting connection to production facilities and natural gas wells awaiting pipeline connections to commence deliveries. Gross wells are the total number of producing wells in which the Company has an interest and net wells are the sum of the Company’s fractional working interests owned in gross wells.

 

     Oil      Natural Gas      Total  
     Gross      Net      Gross      Net      Gross      Net  

Area

                 

Mid-Continent

     291         187.1         545         221.8         836         408.8   

Permian Basin

     2,964         2,849.6         161         126.4         3,125         2,976.0   

WTO

     18         17.1         862         728.3         880         745.4   

Gulf Coast

     20         9.7         99         63.8         119         73.6   

Gulf of Mexico

     25         15.0         11         7.2         36         22.2   

Other

     47         40.9         —           —           47         40.9   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total

     3,365         3,119.4         1,678         1,147.5         5,043         4,266.9   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Developed and Undeveloped Acreage

The following table sets forth information regarding the Company’s developed and undeveloped acreage at December 31, 2011:

 

     Developed Acreage      Undeveloped Acreage  
     Gross      Net      Gross      Net  

Area

           

Mid-Continent

     261,635         165,512         1,436,587         1,166,780   

Permian Basin

     133,276         109,136         185,478         115,766   

WTO

     36,569         33,969         507,649         385,184   

Gulf Coast

     50,936         29,761         14,892         4,399   

Gulf of Mexico

     56,511         27,772         —           —     

Other

     10,966         8,940         360         199   
  

 

 

    

 

 

    

 

 

    

 

 

 

Total

     549,893         375,090         2,144,966         1,672,328   
  

 

 

    

 

 

    

 

 

    

 

 

 

 

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Many of the leases comprising the undeveloped acreage set forth in the table above will expire at the end of their respective primary terms unless production from the leasehold acreage is established prior to such date, in which event the lease will remain in effect until production has ceased. The following table sets forth as of December 31, 2011 the expiration periods of the gross and net acres that are subject to leases in the undeveloped acreage summarized in the above table.

 

     Acres Expiring  
     Gross      Net  

Twelve Months Ending

     

December 31, 2012

     340,929         208,368   

December 31, 2013

     747,801         603,372   

December 31, 2014

     769,542         635,004   

December 31, 2015 and later

     182,478         153,685   

Other(1)

     104,216         71,899   
  

 

 

    

 

 

 

Total

     2,144,966         1,672,328   
  

 

 

    

 

 

 

 

(1)

Leases remaining in effect until development efforts or production on the developed portion of the particular lease has ceased.

Included in the acreage expiring during the twelve months ending December 31, 2012 above are approximately 278,000 gross (174,000 net) acres in the WTO. The development of this acreage is largely dependent on natural gas prices during this period.

Drilling Activity

The following table sets forth information with respect to wells the Company completed during the periods indicated. The information presented is not necessarily indicative of future performance, and should not be interpreted to present any correlation between the number of productive wells drilled and quantities or economic value of reserves found. Productive wells are those that produce commercial quantities of hydrocarbons, regardless of whether they produce a reasonable rate of return. Gross wells refer to the total number of wells in which the Company had a working interest and net wells refer to gross wells multiplied by the Company’s weighted average working interest. As of December 31, 2011, the Company had 116 gross (104.5 net) operated wells drilling, completing or awaiting completion.

 

     2011     2010     2009  
     Gross      Percent     Net      Percent     Gross      Percent     Net      Percent     Gross      Percent     Net      Percent  

Completed Wells

                              

Development

                              

Productive

     895         99.7     850.0         99.7     579         95.7     538.8         95.7     147         97.4     117.2         97.9

Dry

     3         0.3     2.9         0.3     26         4.3     24.3         4.3     4         2.6     2.5         2.1
  

 

 

    

 

 

   

 

 

    

 

 

   

 

 

    

 

 

   

 

 

    

 

 

   

 

 

    

 

 

   

 

 

    

 

 

 

Total

     898         100.0     852.9         100.0     605         100.0     563.1         100.0     151         100.0     119.7         100.0

Exploratory

                              

Productive

     38         100.0     33.7         100.0     15         83.3     14.9         83.2     9         100.0     8.6         100.0

Dry

     —           0.0     —           0.0     3         16.7     3.0         16.8     —           —          —           —     
  

 

 

    

 

 

   

 

 

    

 

 

   

 

 

    

 

 

   

 

 

    

 

 

   

 

 

    

 

 

   

 

 

    

 

 

 

Total

     38         100.0     33.7         100.0     18         100.0     17.9         100.0     9         100.0     8.6         100.0

Total

                              

Productive

     933         99.7     883.7         99.7     594         95.3     553.7         95.3     156         97.5     125.8         98.1

Dry

     3         0.3     2.9         0.3     29         4.7     27.3         4.7     4         2.5     2.5         1.9
  

 

 

    

 

 

   

 

 

    

 

 

   

 

 

    

 

 

   

 

 

    

 

 

   

 

 

    

 

 

   

 

 

    

 

 

 
     936         100.0     886.6         100.0     623         100.0     581.0         100.0     160         100.0     128.3         100.0
  

 

 

    

 

 

   

 

 

    

 

 

   

 

 

    

 

 

   

 

 

    

 

 

   

 

 

    

 

 

   

 

 

    

 

 

 

 

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Drilling Rigs

The following table sets forth information with respect to the rigs operating on the Company’s acreage by area as of December 31, 2011.

 

     Owned      Third-Party      Total  

Mid-Continent

     8         13         21   

Permian Basin

     12         3         15   
  

 

 

    

 

 

    

 

 

 

Total

     20         16         36   
  

 

 

    

 

 

    

 

 

 

Marketing and Customers

The Company sells oil, natural gas and natural gas liquids to a variety of customers, including utilities, oil and natural gas companies and trading and energy marketing companies. The Company had two customers that individually accounted for more than 10% of its total revenue during 2011. See Note 23 to the Company’s consolidated financial statements in Item 8 of this report for additional information on its major customers. The number of readily available purchasers for the Company’s products makes it unlikely that the loss of a single customer in the areas in which the Company sells its products would materially affect its sales. The Company does not have any commitments to deliver fixed and determinable quantities of oil and natural gas in the future under existing sales contracts or agreements.

Title to Properties

As is customary in the oil and natural gas industry, the Company initially conducts a preliminary review of the title to its properties for which it does not have proved reserves. Prior to the commencement of drilling operations on those properties, the Company conducts a thorough title examination and performs curative work with respect to significant defects. To the extent drilling title opinions or other investigations reflect title defects on those properties, the Company is typically responsible for curing any title defects at its expense. The Company generally will not commence drilling operations on a property until it has cured any material title defects on such property. In addition, prior to completing an acquisition of producing oil and natural gas leases, the Company performs title reviews on the most significant leases, and depending on the materiality of properties, the Company may obtain a drilling title opinion or review previously obtained title opinions. To date, the Company has obtained drilling title opinions on substantially all of its producing properties and believes that it has good and defensible title to its producing properties. The Company’s oil and natural gas properties are subject to customary royalty and other interests, liens for current taxes and other burdens, which the Company believes does not materially interfere with the use of or affect its carrying value of the properties.

Capital Expenditures

The Company’s capital expenditures for 2011 related to its exploration and production segment were $1.7 billion, including amounts spent to develop wells in the Mississippian Trust I and the Permian Trust areas of mutual interest. The Company has budgeted approximately $1.5 billion in capital expenditures, excluding acquisitions and capital expenditures associated with properties to be acquired from Dynamic, in 2012 for its exploration and production segment.

Drilling and Oil Field Services

The drilling and related oil field services that the Company provides to its exploration and production business and to third parties are described below.

Drilling Operations

The Company drills for its own account primarily in west Texas, northwestern Oklahoma and Kansas through its drilling and oil field services subsidiary, Lariat. In addition, the Company also drills wells for other

 

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oil and natural gas companies, primarily in west Texas. The Company believes that drilling with its own rigs allows it to control costs and maintain operating flexibility. The Company’s rig fleet is designed to drill in its specific areas of operation and has an average of over 800 horsepower and an average depth capacity of greater than 10,500 feet. As of December 31, 2011, the Company’s drilling rig fleet consisted of 30 operational rigs with 20 of these rigs working on Company-owned properties in the Mid-Continent and Permian Basin.

Types of Drilling Contracts

The Company obtains its contracts for drilling oil and natural gas wells either through competitive bidding or through direct negotiations with customers. The Company’s drilling contracts generally provide for compensation on a daywork or footage basis. The contract terms the Company offers generally depend on the complexity and risk of operations, the on-site drilling conditions, the type of equipment used, the anticipated duration of the work to be performed and prevailing market rates. For a discussion of these contracts, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Segment Overview—Drilling and Oil Field Services Segment” in Item 7 of this report.

Oil Field Services

The Company’s oil field services business conducts operations that, together with its drilling services, complement its exploration and production business. Oil field services include providing pulling units, trucking, rental tools, location and road construction and roustabout services to the Company as well as to third parties.

Customers

During 2011, the Company performed approximately 74% of its drilling and oil field services in support of its exploration and production business. For the years ended December 31, 2011, 2010 and 2009, the Company generated revenues of $103.3 million, $28.6 million and $23.6 million, respectively, for drilling and oil field services performed for third parties.

Capital Expenditures

The Company’s capital expenditures for 2011 related to its drilling and oil field services were $25.7 million. The Company has budgeted approximately $20.0 million in capital expenditures in 2012 for its drilling and oil field services segment.

Midstream Gas Services

The Company provides gathering, compression and treating services of natural gas in west Texas. The Company’s midstream operations and assets serve its exploration and production business as well as other oil and natural gas companies. The following tables set forth information regarding the Company’s primary midstream assets as of December 31, 2011:

 

     Plant  Capacity
(MMcf/d)(1)
     Average
Utilization(2)
    Third-Party
Usage
 

Gas Treating Plants

       

Pike’s Peak

     85         25     <1

Grey Ranch

     220         26     6

 

(1)

Based on a 69% CO2 natural gas stream.

(2)

Average utilization for the year ended December 31, 2011.

 

     CO2  Compression
Capacity (MMcf/d)
     Average
Utilization(1)
 

SandRidge CO2 Compression Facilities

     

Pike’s Peak

     36.0         29

Mitchell

     26.5         28

Grey Ranch

     64.0         20

Terrell

     28.0         73

 

(1)

Average utilization for the year ended December 31, 2011.

 

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West Texas

The Company owns and operates the Pike’s Peak gas treating plant in Pecos County, Texas, which has the capacity to treat 85 MMcf per day of natural gas for the removal of CO2 from production in the Piñon Field and nearby areas. The Company also owns the Grey Ranch gas treating plant located in Pecos County and has a 50% interest in the partnership that leases the plant from the Company under a lease expiring in 2020. The treating capacity for both the Pike’s Peak and Grey Ranch plants is dependent upon the quality of natural gas being treated.

The Company’s two west Texas gas treating plants remove CO2 from natural gas production and deliver residue gas into the Atmos Lone Star and Enterprise Energy Services pipelines. These pipelines are operated on fixed fees based upon throughput of natural gas. In addition, the Company has access of up to 30 MMcf per day of treating capacity at Hoover Energy Partners’ Mitchell Plant under a long-term fixed fee arrangement.

The Company also owns or operates over 1,700 miles of gas gathering pipelines and numerous dehydration units. Within the Piñon Field, the Company operates separate gathering systems for sweet natural gas and produced natural gas containing high percentages of CO2. In addition to servicing the Company’s exploration and production business, these assets also service other oil and natural gas companies.

The majority of the produced natural gas gathered by the Company’s midstream assets in west Texas requires compression from the wellhead to the final sales meter. As of December 31, 2011, the Company owned or operated approximately 75,000 horsepower of gas compression in west Texas.

The Century Plant, in Pecos County, Texas, will add 400 MMcf per day in available treating capacity when fully commissioned. During 2011, the Company continued with the operational assessment phase of the Century Plant, including diverting some of the Company’s natural gas from the Company’s existing gas treating plants and CO2 compression facilities and processing it at the Century Plant. As a result of the assessments, the Century Plant has been taken off line from time to time to resolve certain operational issues. The Company is currently in the process of diverting its high CO2 natural gas production to the Century Plant and commencing performance testing for Phase I. Upon successful completion of the performance testing, the use of the Company’s existing gas treating plants and CO2 compression facilities in west Texas may be limited. The extent of such limitation will depend on a variety of factors, including natural gas prices and the expected need for such plants and facilities to supplement treating capacity at the Century Plant going forward. During the second quarter of 2011, the Company evaluated its gas treating plants and CO2 compression facilities for impairment in connection with the operational assessment of Phase I of the Century Plant and concluded no impairment was necessary. The Company continued to monitor the status of the Century Plant, the related impact on its gas treating plants and CO2 compression facilities and natural gas prices during the second half of 2011. As of December 31, 2011, no impairment of these plants or facilities was deemed necessary.

In conjunction with the June 2009 sale of the Company’s gathering and compression assets located in the Piñon Field, the Company entered into a gas gathering agreement and an operations and maintenance agreement with Piñon Gathering Company, LLC. Under the gas gathering agreement, the Company has dedicated the Piñon Field acreage for priority gathering services for a period of 20 years and will pay a fee that was negotiated at arms’ length for such services. See Note 16 to the Company’s consolidated financial statements in Item 8 of this report for additional information on the contractual fees associated with the gas gathering agreement.

Other Areas

As of December 31, 2011, the Company owned approximately 50 miles of pipeline in the Mid-Continent area and owned approximately 54 miles of pipeline gathering systems and operated over 2,500 horsepower of gas compression in the Gulf Coast area.

 

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Capital Expenditures

The growth of the Company’s midstream assets is driven by its oil and natural gas exploration and development operations. Historically, pipeline and facility expansions are made when warranted by the increase in production or the development of additional acreage. During 2011, the Company spent $93.1 million in capital expenditures to install pipeline and compression infrastructure and for other general corporate purposes. The Company has budgeted approximately $135.0 million in 2012 capital expenditures for its midstream gas services segment and other general corporate purposes.

Marketing

Through Integra Energy, L.L.C., a wholly owned subsidiary, the Company buys and sells natural gas from wells it operates and wells operated by third parties within its west Texas operations. The Company generally buys and sells natural gas on “back-to-back” contracts using a portfolio of baseload and spot sales agreements. Identical volumes are bought and sold on monthly and daily contracts using a combination of published pricing indices to eliminate price exposure.

The Company periodically buys and sells third-party natural gas. The Company conducts thorough credit checks with all potential purchasers and minimizes its exposure by contracting with multiple parties each month. The Company does not engage in any hedging activities with respect to these contracts. The Company manages several interruptible natural gas transportation agreements in order to take advantage of price differentials or to secure available markets when necessary. The Company currently has 50,000 MMBtu per day of firm transportation service subscribed on the Oasis Pipeline for a portion of its Piñon Field production for 2012, 75,000 MMBtu per day on the Mid-Continent Express Pipeline through August 2014 and 50,000 MMBtu per day on Mid-Continent Express Pipeline through August 2019.

Customers

During 2011, the Company performed approximately 65% of its midstream services in support of its exploration and production business. For the years ended December 31, 2011, 2010 and 2009, the Company generated revenues of $65.2 million, $98.5 million and $83.9 million, respectively, from midstream services performed for third parties.

Other Operations

The Company’s CO2 capturing operations are conducted through SandRidge CO2. As of December 31, 2011, SandRidge CO2 owned 240 miles of CO2 pipelines in west Texas with approximately 56,000 horsepower of owned and leased CO2 compression available and currently operational. The captured CO2 is primarily used for tertiary oil recovery operations.

COMPETITION

The Company believes that its leasehold acreage position, drilling and oil field services businesses, midstream assets, CO2 supply and technical and operational capabilities generally enable the Company to compete effectively. The Company believes its geographic concentration of operations and vertical integration enables it to compete effectively with other exploration and production operations. However, the oil and natural gas industry is intensely competitive, and the Company faces competition in each of its business segments.

The Company competes with major oil and natural gas companies and independent oil and natural gas companies for leases, equipment, personnel and markets for the sale of oil and natural gas. Many of these competitors are financially stronger than the Company, but even financially troubled competitors can affect the market because of their need to sell oil and natural gas at any price to attempt to maintain cash flow. Certain

 

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companies may be able to pay more for producing properties and undeveloped acreage. In addition, these companies may have a greater ability to continue exploration activities during periods of low oil and natural gas market prices. The Company’s larger or fully integrated competitors may be able to absorb the burden of any existing and future federal, state and local laws and regulations more easily than the Company can, which would adversely affect its competitive position. The Company’s ability to acquire additional properties and to discover reserves in the future depends on its ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. In addition, because the Company has fewer financial and human resources than many companies in its industry, the Company may be at a disadvantage in bidding for exploratory prospects and producing oil and natural gas properties.

Oil and natural gas compete with other forms of energy available to customers, primarily based on price. These alternate forms of energy include electricity, coal and fuel oils. Changes in the availability or price of oil and natural gas or other forms of energy, as well as business conditions, conservation, legislation, regulations and the ability to convert to alternate fuels and other forms of energy may affect the demand for oil and natural gas.

With respect to the Company’s drilling business, the Company believes the type, age and condition of its drilling rigs, the quality of its crews and the responsiveness of its management generally enable the Company to compete effectively. However, to the extent the Company drills for third parties, it encounters substantial competition from other drilling contractors. The Company’s primary market area is highly competitive. The drilling contracts the Company competes for are usually awarded on the basis of competitive bids. The Company may, based on the economic environment at the time, determine that market conditions and profit margins are such that contract drilling for third parties is not a beneficial use of its resources.

The Company believes pricing and rig availability are the primary factors its potential customers consider in determining which drilling contractor to select. While the Company must be competitive in its pricing, its competitive strategy generally emphasizes the quality of its equipment and the experience of its rig crews to differentiate it from its competitors. This strategy is less effective when demand for drilling services is weak or there is an oversupply of rigs. These conditions usually result in increased price competition, which makes it more difficult for the Company to compete on the basis of factors other than price. Many of the Company’s competitors have greater financial, technical and other resources than the Company does. Their greater capabilities in these areas may enable them to better withstand industry downturns and better retain skilled rig personnel.

The Company believes its geographic concentration of operations enables it to compete effectively in its midstream business. Most of the Company’s midstream assets are integrated with its production. However, with respect to third-party natural gas and acquisitions, the Company competes with companies that have greater financial and personnel resources than it does. These companies may have a greater ability to price their services below the Company’s prices for similar services.

SEASONAL NATURE OF BUSINESS

Generally, demand for oil and natural gas decreases during the summer months and increases during the winter months. Certain natural gas users utilize natural gas storage facilities and purchase some of their anticipated winter requirements during the summer, which can lessen seasonal demand fluctuations. Seasonal weather conditions and lease stipulations can limit the Company’s drilling and producing activities and other oil and natural gas operations in a portion of its operating areas. These seasonal anomalies can pose challenges for meeting the Company’s well drilling objectives and can increase competition for equipment, supplies and personnel during the spring and summer months, which could lead to shortages and increase costs or delay the Company’s operations.

ENVIRONMENTAL REGULATIONS

General

The exploration, development and production of oil and natural gas are subject to stringent and comprehensive federal, state, tribal, regional and local laws and regulations governing the discharge of materials

 

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into the environment or otherwise relating to environmental protection or to employee health and safety. These laws and regulations may, among other things, require permits to conduct drilling, water withdrawal and waste disposal operations; govern the amounts and types of substances that may be disposed or released into the environment; limit or prohibit construction or drilling activities in sensitive areas such as wetlands, wilderness areas or areas inhabited by endangered or threatened species; require investigatory and remedial actions to mitigate pollution conditions arising from the Company’s operations or attributable to former operations; impose restrictions designed to protect employees from exposure to hazardous substances; and impose obligations to reclaim and abandon well sites and pits. Failure to comply with these laws and regulations may result in the assessment of sanctions, including monetary penalties, the imposition of remedial obligations and the issuance of orders enjoining operations in affected areas. Pursuant to such laws, regulations and permits, the Company may be subject to operational restrictions and have made and expect to continue to make capital and other compliance expenditures.

Increasingly, restrictions and limitations are being placed on activities that may affect the environment. Any changes in environmental laws and regulations or re-interpretation of enforcement policies that result in more stringent and costly construction, drilling, water management, completion, waste handling, storage, transport, disposal, or remediation requirements or emission or discharge limits could have a material adverse effect on the Company. Moreover, accidental releases or spills may occur in the course of the Company’s operations, and there can be no assurance that the Company will not incur significant costs and liabilities as a result of such releases or spills, including any third-party claims for damage to property and natural resources or personal injury.

The following is a summary of the more significant existing environmental and employee, health and safety laws and regulations applicable to the oil and natural gas industry and for which compliance may have a material adverse impact on the Company.

Hazardous Substances and Wastes

The Company currently owns, leases, or operates, and in the past has owned, leased, or operated, properties that have been used to explore for and produce oil and natural gas. The Company believes it has utilized operating and disposal practices that were standard in the industry at the applicable time, but hydrocarbons and wastes may have been disposed or released on or under the properties owned, leased, or operated by the Company or on or under other locations where these hydrocarbons and wastes have been taken for treatment or disposal. In addition, certain of these properties have been operated by third parties whose treatment and disposal or release of hydrocarbons and wastes were not under the Company’s control. These properties and wastes disposed thereon may be subject to the Comprehensive Environmental Response, Compensation, and Liability Act, as amended (“CERCLA”), the Resource Conservation and Recovery Act, as amended (“RCRA”) and analogous state laws. Under these laws, the Company could be required to remove or remediate previously disposed wastes, to investigate and clean up contaminated property and to perform remedial operations to prevent future contamination or to pay some or all of the costs of any such action.

CERCLA, also known as the Superfund law, and comparable state laws impose joint and several liability without regard to fault or legality of conduct on certain classes of persons who are considered to be responsible for the release of a “hazardous substance” into the environment. These persons include current and prior owners or operators of the site where the release occurred and entities that disposed or arranged for the disposal of the hazardous substances at the site. Under CERCLA, these “responsible persons” may be subject to strict, joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain environmental and health studies. In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury, natural resource damage, and property damage allegedly caused by the release of hazardous substances into the environment. CERCLA also authorizes the Environmental Protection Agency (“EPA”) and, in some instances,

 

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third parties to act in response to threats to the public health or the environment and to seek recovery from the responsible classes of persons the costs they incur. The Company uses and generates materials in the course of its operations that may be regulated as hazardous substances. To date, no Company-owned or operated site has been designated as a Superfund site, and the Company has not been identified as a responsible party for any Superfund site.

The Company also generates wastes that are subject to the requirements of RCRA and comparable state statutes. RCRA imposes strict requirements on the generation, transportation, treatment, storage, disposal and cleanup of hazardous and non-hazardous wastes. Drilling fluids, produced waters and many of the other wastes associated with the exploration, production and development of crude oil and natural gas are currently exempt from regulation as hazardous wastes under RCRA. However, it is possible that certain oil and natural gas exploration and production wastes now classified as non-hazardous could be classified as hazardous wastes in the future. In September 2010, the Natural Resources Defense Council filed a petition for rulemaking with the EPA requesting reconsideration of the RCRA exemption for exploration, production, and development wastes. To date, the EPA has not taken any action on the petition. Any change in the RCRA exemption for such wastes could result in an increase in costs to manage and dispose of wastes. In the course of the Company’s operations, it generates petroleum hydrocarbon wastes and ordinary industrial wastes that are subject to regulation under the RCRA. The Company is in substantial compliance with all regulations regarding the handling and disposal of oil and natural gas wastes from its operations.

Air Emissions

The Clean Air Act, as amended, and comparable state laws and regulations restrict the emission of air pollutants from many sources and also impose various permitting, monitoring and reporting requirements. These laws and regulations may require the Company to obtain pre-approval for the construction or modification of certain projects or facilities expected to produce or significantly increase air emissions, obtain and strictly comply with air permit requirements or utilize specific equipment or technologies to control emissions. Obtaining permits has the potential to delay the development of oil and natural gas projects. The Company may be required to incur certain capital expenditures for air pollution control equipment or other air emissions-related issues as a result of such requirements. In July 2011, the EPA proposed a range of new regulations that would establish new air emission controls for oil and natural gas production and natural gas processing, including, among other things, a new source performance standard for volatile organic compounds that would apply to newly hydraulically fractured wells, existing wells that are re-fractured, compressors, pneumatic controllers, condensate and crude oil storage tanks and natural gas processing plants. The EPA is under a court order to finalize these proposed regulations by April 3, 2012.

Water Discharges

The Federal Water Pollution Act, as amended (the “Clean Water Act”), and analogous state laws impose restrictions and strict controls regarding the discharge of pollutants into navigable waters. Pursuant to the Clean Water Act and analogous state laws, permits must be obtained to discharge produced waters and sand, drilling fluids, drill cuttings and other substances related to the oil and gas industry into onshore, coastal and offshore waters of the United States or state waters. Any such discharge of pollutants into regulated waters must be performed in accordance with the terms of the permit issued by EPA or the analogous state agency. In addition, spill prevention, control and countermeasure requirements under federal law require appropriate containment berms and similar structures to help prevent the contamination of navigable waters in the event of a petroleum hydrocarbon tank spill, rupture or leak. In addition, the Clean Water Act and analogous state laws require individual permits or coverage under general permits for discharges of storm water runoff from certain types of facilities.

 

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Climate Change

In December 2009, the EPA published its findings that emissions of carbon dioxide, methane and certain other greenhouse gases (“GHGs”) present an endangerment to public health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the Earth’s atmosphere and other climatic changes. These findings allow the EPA to adopt and implement regulations that restrict emissions of GHGs under existing provisions of the Clean Air Act. Accordingly, the EPA has adopted rules that require a reduction in emissions of GHGs from motor vehicles and also trigger Clean Air Act construction and operating permit review for GHG emissions from certain stationary sources. The EPA’s rules relating to emissions of GHGs from stationary sources of emissions are currently subject to a number of legal challenges, but the federal courts have thus far declined to issue any injunctions to prevent the EPA from implementing, or requiring state environmental agencies to implement, the rules. In addition, the EPA has adopted rules requiring the reporting of GHG emissions from onshore oil and natural gas production facilities in the United States on an annual basis. The adoption and implementation of any regulations imposing reporting obligations on, or limiting emissions of GHG gases from, the Company’s equipment and operations could require it to incur additional costs to reduce emissions of GHGs associated with its operations or could adversely affect demand for the oil and natural gas it produces. Finally, some scientists have concluded that increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, floods and other climatic events. If any such effects were to occur, they could have a material adverse effect on the Company and potentially subject the Company to further regulation.

In addition, Congress has considered legislation to reduce emissions of GHGs and almost one-half of the states have begun taking actions to control and/or reduce emissions of GHGs, primarily through the planned development of GHG emission inventories and/or regional GHG cap and trade programs. Any future federal laws or implemented regulations that may be adopted to address GHG emissions could require the Company to incur increased operating costs, adversely affect demand for the oil and natural gas that the Company produces and have a material adverse effect on the Company’s business, financial condition and results of operations.

Endangered Species

The federal Endangered Species Act (the “ESA”) restricts activities that may affect endangered or threatened species or their habitats. The Company believes its operations are in substantial compliance with the ESA. If endangered species are located in areas of the underlying properties where the Company wishes to conduct seismic surveys, development activities or abandonment operations, the work could be prohibited or delayed or expensive mitigation may be required. Moreover, as a result of a settlement approved by the U.S. District Court for the District of Columbia on September 9, 2011, the U.S. Fish and Wildlife Service is required to consider listing more than 250 species as endangered under the ESA. Under the September 9, 2011 settlement, the federal agency is required to make a determination on listing of the species as endangered or threatened over the next six years, through the agency’s 2017 fiscal year. The designation of previously unprotected species as threatened or endangered in areas where underlying property operations are conducted could cause the Company to incur increased costs arising from species protection measures or could result in limitations on its exploration and production activities that could have an adverse impact on its ability to develop and produce reserves.

Employee Health and Safety

The Company’s operations are subject to a number of federal and state laws and regulations, including the federal Occupational Safety and Health Act, as amended (“OSHA”), and comparable state statutes, whose purpose is to protect the health and safety of workers. In addition, the OSHA hazard communication standard, the EPA community right-to-know regulations under Title III of the federal Superfund Amendment and Reauthorization Act and comparable state statutes require that information be maintained concerning hazardous materials used or produced in the Company’s operations and that this information be provided to employees, state and local government authorities and citizens. The Company believes that it is in substantial compliance with all applicable laws and regulations relating to worker health and safety.

 

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State Regulation

The states in which the Company operates regulate the drilling for, and the production and gathering of, oil and natural gas, including requirements relating to drilling permits, the location, spacing and density of wells, unitization and pooling of interests, the method of drilling, casing and equipping of wells, the protection of fresh water sources, the orderly development of common sources of supply of oil and natural gas, the operation of wells, allowable rates of production, the use of fresh water in oil and natural gas operations, saltwater injection and disposal operations, the plugging and abandonment of wells and the restoration of surface properties, the prevention of waste of oil and natural gas resources, the protection of the correlative rights of oil and natural gas owners and, where necessary to avoid unfair, unjust or discriminatory service, the fees, terms and conditions for the gathering of natural gas. The effect of these regulations may be to limit the number of wells that the Company may drill, impact the locations at which the Company may drill wells, restrict the amounts of oil and natural gas that may be produced from the Company’s wells and increase the costs of the Company’s operations.

Hydraulic Fracturing

Oil and natural gas may be recovered from certain of the Company’s oil and natural gas properties through the use of hydraulic fracturing, combined with sophisticated drilling. Hydraulic fracturing, which involves the injection of water, sand and chemicals under pressure into formations to fracture the surrounding rock and stimulate production, is typically regulated by state oil and gas commissions. However, the EPA has asserted federal regulatory authority over certain hydraulic fracturing practices, (i.e., use of diesel, kerosene and similar compounds in the fracturing fluid). Also, legislation has been introduced, but not enacted, in Congress to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the fracturing process. The U.S. Department of the Interior is considering disclosure requirements and other mandates for hydraulic fracturing on federal lands. In addition, some states have adopted, and other states are considering adopting, regulations that could restrict hydraulic fracturing in certain circumstances. Certain states in which the Company operates, including Texas and Oklahoma, and municipalities have adopted, or are considering adopting, regulations that have imposed, or that could impose, more stringent permitting, disclosure, disposal and well construction requirements on hydraulic fracturing operations. For example, in December 2011, the Railroad Commission of Texas finalized regulations requiring public disclosure of all the chemicals in fluids used in the hydraulic fracturing process. Local ordinances or other regulations may regulate or prohibit the performance of well drilling in general and hydraulic fracturing in particular. If new laws or regulations that significantly restrict hydraulic fracturing are adopted at the state level, such legal requirements could cause project delays and make it more difficult or costly for the Company to perform fracturing to stimulate production of oil and natural gas. These delays or additional costs could adversely affect the determination of whether a well is commercially viable. In addition, if hydraulic fracturing is regulated at the federal level, the Company’s fracturing activities could become subject to additional permit requirements, reporting requirements or operational restrictions and also to associated permitting delays and potential increases in costs. Restrictions on hydraulic fracturing could also reduce the amount of oil and natural gas that the Company is ultimately able to produce in commercial quantities.

In addition, a number of federal agencies are analyzing, or have been requested to review, a variety of environmental issues associated with hydraulic fracturing. The White House Council on Environmental Quality is coordinating an administration-wide review of hydraulic fracturing practices, and a committee of the United States House of Representatives has conducted an investigation of hydraulic fracturing practices. The EPA has commenced a study of the potential environmental effects of hydraulic fracturing on drinking water and groundwater, with initial results expected to be available by late 2012 and final results by 2014. Moreover, the EPA announced on October 20, 2011 that it is also launching a study regarding wastewater resulting from hydraulic fracturing activities and currently plans to propose standards by 2014 that such wastewater must meet before being transported to a treatment plant. In addition, the U.S. Department of Energy has conducted an investigation of practices the agency could recommend to better protect the environment from drilling using hydraulic fracturing completion methods and the U.S. Government Accountability Office has investigated how

 

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hydraulic fracturing might adversely affect water resources. Additionally, certain members of Congress have called upon the SEC to investigate the natural gas industry and any possible misleading of investors or the public regarding the economic feasibility of pursuing natural gas deposits in shales by means of hydraulic fracturing and the U.S. Energy Information Administration to provide a better understanding of that agency’s estimates regarding natural gas reserves, including reserves from shale formations, as well as uncertainties associated with those estimates. These ongoing or proposed studies, depending on their degree of pursuit and any meaningful results obtained, could spur initiatives to further regulate hydraulic fracturing under the federal Safe Drinking Water Act or other regulatory mechanisms.

The Company diligently reviews best practices and industry standards, and complies with all regulatory requirements in the protection of potable water sources. Protective practices include, but are not limited to, setting multiple strings of protection pipe across the potable water sources and cementing these pipes from setting depth to surface, continuously monitoring the hydraulic fracturing process in real time and disposing of all non-commercially produced fluids in certified disposal wells at depths below the potable water sources. There have not been any incidents, citations or suits related to the Company’s hydraulic fracturing activities involving environmental concerns.

OTHER REGULATION OF THE OIL AND NATURAL GAS INDUSTRY

The oil and natural gas industry is extensively regulated by numerous federal, state and local authorities, as well as Native American tribes. Legislation affecting the oil and natural gas industry is under constant review for amendment or expansion, frequently increasing the regulatory burden. Also, numerous departments and agencies, both federal and state, and Native American tribes are authorized by statute to issue rules and regulations affecting the oil and natural gas industry and its individual members, some of which carry substantial penalties for noncompliance. Although the regulatory burden on the oil and natural gas industry increases the Company’s cost of doing business and, consequently, affects its profitability, these burdens generally do not affect the Company any differently or to any greater or lesser extent than they affect other companies in the industry with similar types, quantities and locations of production.

The availability, terms and cost of transportation significantly affect sales of oil and natural gas. The interstate transportation and sale for resale of oil and natural gas is subject to federal regulation, including regulation of the terms, conditions and rates for interstate transportation, storage and various other matters, primarily by the Federal Energy Regulatory Commission (“FERC”). Federal and state regulations govern the price and terms for access to oil and natural gas pipeline transportation. The FERC’s regulations for interstate oil and natural gas transmission in some circumstances may also affect the intrastate transportation of oil and natural gas.

Sales of oil and natural gas are not currently regulated and are made at market prices. Although oil and natural gas prices are currently unregulated, Congress historically has been active in the area of oil and natural gas regulation. The Company cannot predict whether new legislation to regulate oil and natural gas might be proposed, what proposals, if any, might actually be enacted by Congress or the various state legislatures, and what effect, if any, the proposals might have on the Company’s operations.

Drilling and Production

The Company’s operations are subject to various types of regulation at federal, state, local and Native American tribal levels. These types of regulation include requiring permits for the drilling of wells, drilling bonds and reports concerning operations. Most states, and some counties, municipalities and Native American tribal areas where the Company operates also regulate one or more of the following activities:

 

   

the location of wells;

 

   

the method of drilling and casing wells;

 

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the timing of construction or drilling activities;

 

   

the rates of production, or “allowables”;

 

   

the surface use and restoration of properties upon which wells are drilled;

 

   

the plugging and abandoning of wells; and

 

   

the notice to surface owners and other third parties.

State laws regulate the size and shape of drilling and spacing units or proration units governing the pooling of oil and natural gas properties. Some states allow forced pooling or integration of tracts to facilitate exploration while other states rely on voluntary pooling of lands and leases. In some instances, forced pooling or unitization may be implemented by third parties and may reduce the Company’s interest in the unitized properties. In addition, state conservation laws establish maximum rates of production from oil and natural gas wells, generally prohibit the venting or flaring of natural gas and impose requirements regarding the ratability of production. These laws and regulations may limit the amount of oil and natural gas the Company can produce from its wells or limit the number of wells or the locations at which the Company can drill. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of oil, natural gas, and natural gas liquids within its jurisdiction.

Federal, state and local regulations provide detailed requirements for the abandonment of wells, closure or decommissioning of production facilities and pipelines, and for site restoration, in areas where the Company operates. Effective October 1, 2011, the Bureau of Ocean Energy Management, Regulation and Enforcement (the “BOEMRE”), the agency within the U.S. Department of the Interior responsible for regulation of offshore energy production, was divided into two agencies, the Bureau of Safety and Environmental Enforcement (the “BSEE”) and the Bureau of Energy Management (the “BOEM”). The BSEE is responsible for the safety and enforcement functions of offshore oil and gas operations, including development and enforcement of safety and environmental regulations, permitting, inspections, offshore regulatory programs, oil spill response and training and environmental compliance programs, while the functions of BOEM include offshore leasing, resource evaluation, review and administration of oil and gas exploration and development plans. Regulations of the BSEE require that owners and operators plug and abandon wells and decommission and remove offshore facilities located in federal offshore lease areas in a prescribed manner. BSEE requires federal leaseholders to post performance bonds or otherwise provide necessary financial assurances to provide for such abandonment, decommissioning and removal. The Oil Conservation Division of the New Mexico Energy, Minerals and Natural Resources Department requires the posting of performance bonds to fulfill financial requirements for owners and operators on state land. The Railroad Commission of Texas has financial responsibility requirements for owners and operators of facilities in state waters to provide for similar assurances. The United States Army Corps of Engineers (“ACOE”) and many other state and local authorities also have regulations for plugging and abandonment, decommissioning and site restoration. Although the ACOE does not require bonds or other financial assurances, some state agencies and municipalities do have such requirements.

Natural Gas Sales and Transportation

Historically, federal legislation and regulatory controls have affected the price of the natural gas the Company produces and the manner in which the Company markets its production. FERC has jurisdiction over the transportation and sale for resale of natural gas in interstate commerce by natural gas companies under the Natural Gas Act of 1938 and the Natural Gas Policy Act of 1978. Various federal laws enacted since 1978 have resulted in the complete removal of all price and non-price controls for sales of domestic natural gas sold in first sales, which include all of the Company’s sales of its own production. Under the Energy Policy Act of 2005, FERC has substantial enforcement authority to prohibit the manipulation of natural gas markets and enforce its rules and orders, including the ability to assess substantial civil penalties.

FERC also regulates interstate natural gas transportation rates and service conditions and establishes the terms under which the Company may use interstate natural gas pipeline capacity, which affects the marketing of

 

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natural gas that the Company produces, as well as the revenues it receives for sales of its natural gas and release of its natural gas pipeline capacity. Commencing in 1985, FERC promulgated a series of orders, regulations and rule makings that significantly fostered competition in the business of transporting and marketing gas. Today, interstate pipeline companies are required to provide nondiscriminatory transportation services to producers, marketers and other shippers, regardless of whether such shippers are affiliated with an interstate pipeline company. FERC’s initiatives have led to the development of a competitive, open access market for natural gas purchases and sales that permits all purchasers of natural gas to buy gas directly from third-party sellers other than pipelines. However, the natural gas industry historically has been very heavily regulated; therefore, the Company cannot guarantee that the less stringent regulatory approach currently pursued by FERC and Congress will continue indefinitely into the future nor can the Company determine what effect, if any, future regulatory changes might have on the Company’s natural gas related activities.

Under FERC’s current regulatory regime, transmission services must be provided on an open-access, nondiscriminatory basis at cost-based rates or at market-based rates if the transportation market at issue is sufficiently competitive. 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, in the past FERC has reclassified certain jurisdictional transmission facilities as non-jurisdictional gathering facilities, which has the tendency to increase the Company’s cost of transporting gas to point-of-sale locations.

EMPLOYEES

As of December 31, 2011, the Company had 2,432 full-time employees, including more than 298 geologists, geophysicists, petroleum engineers, technicians, land and regulatory professionals. Of the Company’s 2,432 employees, 667 are located at the Company’s headquarters in Oklahoma City, Oklahoma, and the remaining employees work in the Company’s various field offices and drilling sites.

GLOSSARY OF OIL AND NATURAL GAS TERMS

The following is a description of the meanings of certain oil and natural gas industry terms used in this report.

2-D seismic or 3-D seismic. Geophysical data that depict the subsurface strata in two dimensions or three dimensions, respectively. 3-D seismic typically provides a more detailed and accurate interpretation of the subsurface strata than 2-D seismic.

Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume, used in this report in reference to oil or other liquid hydrocarbons.

Bcf. Billion cubic feet of natural gas.

Bcfe. Billion cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of oil, condensate or natural gas liquids.

Boe. Barrels of oil equivalent, with six thousand cubic feet of natural gas being equivalent to one barrel of oil. Although an equivalent barrel of condensate or natural gas may be equivalent to a barrel of oil on an energy basis, it is not equivalent on a value basis as there may be a large difference in value between an equivalent barrel and a barrel of oil. For example, based on the commodity prices used to prepare the estimate of the Company’s reserves at year-end 2011 of $4.12/Mcf for natural gas and $92.71/Bbl for oil, the ratio of economic value of oil to gas was approximately 22 to 1, even though the ratio for determining energy equivalency is 6 to 1.

Boe/d. Boe per day.

Btu or British thermal unit. The quantity of heat required to raise the temperature of one pound of water by one degree Fahrenheit.

 

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Completion. The process of treating a drilled well followed by the installation of permanent equipment for the production of oil or natural gas, or in the case of a dry well, the reporting to the appropriate authority that the well has been abandoned.

Condensate. A mixture of hydrocarbons that exists in the gaseous phase at original reservoir temperature and pressure, but that, when produced, is in the liquid phase at surface pressure and temperature.

CO2. Carbon dioxide.

Developed acreage. The number of acres that are assignable to productive wells.

Developed oil and natural gas reserves. Developed oil and natural gas reserves are reserves of any category that can be expected to be recovered (i) through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well and (ii) through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

Development costs. Costs incurred to obtain access to proved reserves and to provide facilities for extracting, treating, gathering and storing the oil and natural gas. More specifically, development costs, including depreciation and applicable operating costs of support equipment and facilities and other costs of development activities, are costs incurred to (i) gain access to and prepare well locations for drilling, including surveying well locations for the purpose of determining specific development drilling sites, clearing ground, draining, road building and relocating public roads, gas lines and power lines, to the extent necessary in developing the proved reserves, (ii) drill and equip development wells, development-type stratigraphic test wells and service wells, including the costs of platforms and of well equipment such as casing, tubing, pumping equipment, and the wellhead assembly, (iii) acquire, construct and install, production facilities such as leases, flow lines, separators, treaters, heaters, manifolds, measuring devices and production storage tanks, natural gas cycling and processing plants, and central utility and waste disposal systems, and (iv) provide improved recovery systems.

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 well. An exploratory, development or extension well that proves to be incapable of producing either oil or natural gas in sufficient quantities to justify completion as an oil or natural gas well.

Environmental Assessment (“EA”). A study to determine whether a federal action significantly affects the environment, which federal agencies may be required by the National Environmental Policy Act or similar state statutes to undertake prior to the commencement of activities that would constitute federal actions, such as oil and natural gas exploration and production activities on federal lands.

Environmental Impact Statement. A more detailed study of the environmental effects of a federal undertaking and its alternatives than an EA, which may be required by the National Environmental Policy Act or similar state statutes, either after the EA has been prepared and determined that the environmental consequences of a proposed federal undertaking, such as oil and natural gas exploration and production activities on federal lands, may be significant, or without the initial preparation of an EA if a federal agency anticipates that a proposed federal undertaking may significantly impact the environment.

Exploratory well. A well drilled to find a new field or to find a new reservoir in a field previously found to produce 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 which are separated vertically by intervening impervious strata, or laterally by local geological barriers, or both. Reservoirs that are associated by being in overlapping or adjacent fields may be treated as a single or

 

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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.

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

High CO2 gas. Natural gas that contains more than 10% CO2 by volume.

Imbricate stacking. A geological formation characterized by multiple layers lying lapped over each other.

MBbls. Thousand barrels of oil or other liquid hydrocarbons.

MBoe. Thousand barrels of oil equivalent.

Mcf. Thousand cubic feet of natural gas.

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

MMBbls. Million barrels of oil or other liquid hydrocarbons.

MMBoe. Million barrels of oil equivalent.

MMBtu. Million British Thermal Units.

MMcf. Million cubic feet of natural gas.

MMcf/d. MMcf per day.

Net acres or net wells. The sum of the fractional working interest owned in gross acres or gross wells, as the case may be.

Plugging and abandonment. Refers to the sealing off of fluids in the strata penetrated by a well so that the fluids from one stratum will not escape into another or to the surface. Regulations of all states require plugging of abandoned wells.

Present value of future net revenues (“PV-10”). The present value of estimated future revenues to be generated from the production of proved reserves, before income taxes, calculated in accordance with SEC guidelines, net of estimated production and future development costs, using prices and costs as of the date of estimation without future escalation and without giving effect to hedging activities, non-property related expenses such as general and administrative expenses, debt service and depreciation, depletion and amortization. PV-10 is calculated using an annual discount rate of 10%.

Production costs.

(i) Costs incurred to operate and maintain wells and related equipment and facilities, including depreciation and applicable operating costs of support equipment and facilities and other costs of operating and maintaining those wells and related equipment and facilities. They become part of the cost of oil and gas produced. Examples of production costs (sometimes called lifting costs) are:

(A) Costs of labor to operate the wells and related equipment and facilities.

(B) Repairs and maintenance.

 

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(C) Materials, supplies, and fuel consumed and supplies utilized in operating the wells and related equipment and facilities.

(D) Property taxes and insurance applicable to proved properties and wells and related equipment and facilities.

(E) Severance taxes.

(ii) Some support equipment or facilities may serve two or more oil and gas producing activities and may also serve transportation, refining and marketing activities. To the extent that the support equipment and facilities are used in oil and gas producing activities, their depreciation and applicable operating costs become exploration, development or production costs, as appropriate. Depreciation, depletion and amortization of capitalized acquisition, exploration, and development costs are not production costs but also become part of the cost of oil and gas produced along with production (lifting) costs identified above.

Productive well. A well that is found to be capable of producing oil or natural gas in sufficient quantities to justify completion as an oil or natural gas well.

Prospect. A specific geographic area that, 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. Reserves that are both proved and developed.

Proved oil and natural gas reserves. Has the meaning given to such term in Rule 4-10(a)(22) of Regulation S-X, which defines proved reserves as:

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 estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

The area of a reservoir considered proved includes (i) the area identified by drilling and limited by fluid contacts, if any, and (ii) adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data. In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons as seen in a well penetration unless geoscience, engineering or performance data and reliable technology establish a lower contact with reasonable certainty.

Where direct observation from well penetrations has defined a highest known oil elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering or performance data and reliable technology establish the higher contact with reasonable certainty.

Reserves that can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when (i) successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir, or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based and (ii) the project has been approved for development by all necessary parties and entities, including governmental entities.

 

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Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

Proved undeveloped reserves. Reserves that are both proved and undeveloped.

Pulling units. Pulling units are used in connection with completions and workover operations.

PV-10. See “Present value of future net revenues” above.

Rental tools. A variety of rental tools and equipment, ranging from trash trailers to blow out preventers to sand separators, for use in the oil field.

Reserves. Estimated remaining quantities of oil and natural gas and related substances anticipated to be economically producible by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and natural gas or related substances to market, and all permits and financing required to implement the project.

Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir, or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).

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.

Roustabout services. The provision of manpower to assist in conducting oil field operations.

Standardized measure or standardized measure of discounted future net cash flows. The present value of estimated future cash inflows from proved oil and natural gas reserves, less future development and production costs and future income tax expenses, discounted at 10% per annum to reflect timing of future cash flows and using the same pricing assumptions as were used to calculate PV-10. Standardized Measure differs from PV-10 because Standardized Measure includes the effect of future income taxes on future net revenues.

Trucking. The provision of trucks to move the Company’s drilling rigs from one well location to another and to deliver water and equipment to the field.

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

Undeveloped oil and natural gas reserves. Reserves of any category 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.

(i) Reserves on undrilled acreage are limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.

 

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(ii) Undrilled locations are classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances justify a longer time.

(iii) Under no circumstances shall estimates for undeveloped reserves attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology establishing reasonable certainty.

Working interest. The operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and receive a share of production and requires the owner to pay a share of the costs of drilling and production operations.

 

Item 1A. Risk Factors

Drilling for and producing oil and natural gas are high risk activities with many uncertainties that could adversely affect the Company’s business, financial condition or results of operations.

The Company’s drilling and operating activities are subject to numerous risks, including the risk that the Company will not discover commercially productive reservoirs. Drilling for oil and natural gas can be unprofitable if dry wells are drilled and if productive wells do not produce sufficient revenues to return a profit. Decisions to develop properties depend in part on the evaluation of data obtained through geophysical and geological analyses, production data and engineering studies, the results of which are often inconclusive or subject to varying interpretations. The estimated cost of drilling, completing and operating wells is uncertain before drilling commences. Overruns in budgeted expenditures are common risks that can make a particular project uneconomical. In addition, the Company’s drilling and producing operations may be curtailed, delayed or canceled as a result of various factors, including the following:

 

   

delays imposed by or resulting from compliance with regulatory requirements including permitting;

 

   

unusual or unexpected geological formations and miscalculations;

 

   

shortages of or delays in obtaining equipment and qualified personnel;

 

   

shortages of or delays in obtaining water for hydraulic fracturing operations;

 

   

equipment malfunctions, failures or accidents;

 

   

lack of available gathering facilities or delays in construction of gathering facilities;

 

   

lack of available capacity on interconnecting transmission pipelines;

 

   

lack of adequate electrical infrastructure;

 

   

unexpected operational events and drilling conditions;

 

   

pipe or cement failures and casing collapses;

 

   

pressures, fires, blowouts and explosions;

 

   

lost or damaged drilling and service tools;

 

   

loss of drilling fluid circulation;

 

   

uncontrollable flows of oil, natural gas, brine, water or drilling fluids;

 

   

natural disasters;

 

   

environmental hazards, such as oil and natural gas leaks, pipeline ruptures and discharges of toxic gases or well fluids;

 

   

adverse weather conditions such as extreme cold, fires caused by extreme heat or lack of rain, and severe storms or tornadoes;

 

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reductions in oil and natural gas prices;

 

   

oil and natural gas property title problems; and

 

   

market limitations for oil and natural gas.

Any of these risks can cause substantial losses, including personal injury or loss of life, damage to or destruction of property, natural resources and equipment, environmental contamination or loss of wells and regulatory fines or penalties.

Oil and natural gas prices fluctuate due to a number of factors that are beyond the control of the Company, and a decline in oil and natural gas prices could significantly affect the Company’s financial results and impede its growth.

The Company’s revenues, profitability and cash flow are highly dependent upon the prices realized from the sale of oil and natural gas. The markets for these commodities are very volatile. Oil and natural gas prices can fluctuate widely in response to a variety of factors that are beyond the Company’s control. These factors include, among others:

 

   

regional, domestic and foreign supply of, and demand for, oil and natural gas, as well as perceptions of supply of, and demand for, oil and natural gas;

 

   

the price and quantity of foreign imports;

 

   

U.S. and worldwide political and economic conditions;

 

   

weather conditions and seasonal trends;

 

   

anticipated future prices of oil and natural gas, alternative fuels and other commodities;

 

   

technological advances affecting energy consumption and energy supply;

 

   

the proximity, capacity, cost and availability of pipeline infrastructure, treating, transportation and refining capacity;

 

   

natural disasters and other acts of force majeure;

 

   

domestic and foreign governmental regulations and taxation;

 

   

energy conservation and environmental measures; and

 

   

the price and availability of alternative fuels.

For oil, from January 1, 2008 through December 31, 2011, the highest monthly NYMEX settled price was $140.00 per Bbl and the lowest was $41.68 per Bbl. For natural gas, from January 1, 2008 through December 31, 2011, the highest monthly NYMEX settled price was $13.11 per MMBtu and the lowest was $2.84 per MMBtu. In addition, the market price of oil and natural gas is generally higher in the winter months than during other months of the year due to increased demand for oil and natural gas for heating purposes during the winter season.

Lower oil and natural gas prices may not only decrease the Company’s revenues on a per share basis, but also may ultimately reduce the amount of oil and natural gas that the Company can produce economically and, therefore, could have a material adverse effect on the Company’s financial condition and results of operations. This also may result in the Company having to make substantial downward adjustments to its estimated proved reserves.

Future price declines may result in further reductions of the asset carrying values of the Company’s oil and natural gas properties.

The Company utilizes the full cost method of accounting for costs related to its oil and natural gas properties. Under this accounting method, all costs for both productive and nonproductive properties are

 

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capitalized and amortized on an aggregate basis over the estimated lives of the properties using the unit-of-production method. However, the amount of these costs that can be carried as capitalized assets is subject to a ceiling, which limits such pooled costs to the aggregate of the present value of future net revenues of proved oil and natural gas reserves attributable to proved properties, discounted at 10%, plus the lower of cost or market value of unevaluated properties. The full cost ceiling is evaluated at the end of each quarter using the most recent 12-month average prices for oil and natural gas, adjusted for the impact of derivatives accounted for as cash flow hedges. In the event any of the Company’s derivatives are accounted for as cash flow hedges, the impact of these derivative contracts will be included in the determination of the Company’s full cost ceiling. The Company had no full cost ceiling impairments during the year ended December 31, 2011 or 2010, while its ceiling limitations during 2009 resulted in non-cash impairment charges totaling $1,693.3 million. Future declines in oil and natural gas prices, without other mitigating circumstances, could result in additional losses of future net revenues, including losses attributable to quantities that cannot be economically produced at lower prices, which could cause the Company to record additional write-downs of capitalized costs of its oil and natural gas properties and non-cash charges against future earnings. The amount of such future write-downs and non-cash charges could be substantial.

The Company has a substantial amount of indebtedness and other obligations and commitments, which may adversely affect the Company’s cash flow and its ability to operate its business.

As of December 31, 2011, the Company’s total indebtedness was $2.8 billion, and it had preferred stock outstanding with an aggregate liquidation preference of $765.0 million. The Company’s substantial level of indebtedness and the dividends payable on its preferred stock outstanding increases the possibility that it may be unable to generate cash sufficient to pay, when due, the principal of, interest on or other amounts due in respect of its indebtedness and/or the preferred stock dividends. The Company’s indebtedness and outstanding preferred stock, combined with its lease and other financial obligations and contractual commitments, such as its obligations to drill development wells for multiple royalty trusts, could have other important consequences to the Company. For example, it could:

 

   

make the Company more vulnerable to adverse changes in general economic, industry and competitive conditions and adverse changes in government regulation;

 

   

require the Company to dedicate a substantial portion of its cash flow from operations to payments on its indebtedness, thereby reducing the availability of the Company’s cash flows to fund working capital, capital expenditures, acquisitions and other general corporate purposes;

 

   

limit the Company’s flexibility in planning for, or reacting to, changes in its business and the industry in which it operates;

 

   

place the Company at a disadvantage compared to its competitors that are less leveraged and, therefore, may be able to take advantage of opportunities that the Company’s indebtedness prevents it from pursuing; and

 

   

limit the Company’s ability to borrow additional amounts for working capital, capital expenditures, acquisitions, debt service requirements, execution of its business strategy or other purposes.

Any of the above listed factors could have a material adverse effect on the Company’s business, financial condition and results of operations.

The Company’s estimated reserves are based on many assumptions that may turn out to be inaccurate. Any significant inaccuracies in these reserve estimates or underlying assumptions could materially affect the quantities and present value of the Company’s reserves. The Company’s current estimates of reserves could change, potentially in material amounts, in the future.

The process of estimating oil and natural gas reserves is complex and inherently imprecise, requiring interpretations of available technical data and many assumptions, including assumptions relating to production

 

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rates and economic factors such as oil and natural gas prices, drilling and operating expenses, capital expenditures, the assumed effect of governmental regulation and availability of funds. Any significant inaccuracies in these interpretations or assumptions could materially affect the estimated quantities and present value of reserves shown in this report. See “Business—The Company’s Businesses and Primary Operations” in Item 1 of this report for information about the Company’s oil and natural gas reserves.

Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves most likely will vary from the Company’s estimates. Any significant variance could materially affect the estimated quantities and present value of reserves shown in this report, which in turn could have a negative effect on the value of the Company’s assets. In addition, from time to time in the future, the Company may adjust estimates of proved reserves, potentially in material amounts, to reflect production history, results of exploration and development, oil and natural gas prices and other factors, many of which are beyond the Company’s control.

The present value of future net cash flows from the Company’s proved reserves will not necessarily be the same as the current market value of its estimated oil and natural gas reserves.

The Company bases the estimated discounted future net cash flows from its proved reserves on 12-month average prices and costs. Actual future net cash flows from its oil and natural gas properties also will be affected by factors such as:

 

   

actual prices the Company receives for oil and natural gas;

 

   

the accuracy of the Company’s reserve estimates;

 

   

the actual cost of development and production expenditures;

 

   

the amount and timing of actual production;

 

   

supply of and demand for oil and natural gas; and

 

   

changes in governmental regulations or taxation.

The timing of both the Company’s production and its incurrence of expenses in connection with the development and production of oil and natural gas properties will affect the timing of actual future net cash flows from proved reserves, and thus their actual present value. In addition, the Company uses a 10% discount factor when calculating discounted future net cash flows, which may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with the Company or the oil and natural gas industry in general.

Unless the Company replaces its oil and natural gas reserves, its reserves and production will decline, which would adversely affect its business, financial condition and results of operations.

The Company’s future oil and natural gas reserves and production, and therefore its cash flow and income, are highly dependent on its success in efficiently developing and exploiting the Company’s current reserves and economically finding or acquiring additional recoverable reserves. The Company may not be able to develop, find or acquire additional reserves to replace its current and future production at acceptable costs.

The Company will not know conclusively prior to drilling whether oil or natural gas will be present in sufficient quantities to be economically producible.

The use of seismic data and other technologies and the study of producing fields in the same area does not enable us to know conclusively prior to drilling whether oil or natural gas will be present or, if present, whether oil or natural gas will be present in sufficient quantities to be economically viable. Even if sufficient amounts of oil or natural gas exist, the Company may damage the potentially productive hydrocarbon bearing formation or

 

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experience mechanical difficulties while drilling or completing the well, resulting in a reduction in production from the well or abandonment of the well. During 2011, the Company completed a total of 936 gross wells, of which 3 were identified as dry wells. If the Company drills additional wells that it identifies as dry wells in its current and future prospects, the Company’s drilling success rate may decline and materially harm its business. In summary, the cost of drilling, completing and operating any well is often uncertain, and new wells may not be productive.

Production of oil, natural gas and natural gas liquids could be materially and adversely affected by natural disasters or severe or unseasonable weather.

Production of oil, natural gas and natural gas liquids could be materially and adversely affected by natural disasters or severe weather. Repercussions of natural disasters or severe weather conditions may include:

 

   

evacuation of personnel and curtailment of operations;

 

   

damage to drilling rigs or other facilities, resulting in suspension of operations;

 

   

inability to deliver materials to worksites; and

 

   

damage to pipelines and other transportation facilities.

In addition, the Company’s hydraulic fracturing operations require significant quantities of water. Certain regions in which the Company operates, including Texas, recently have experienced drought conditions. Any diminished access to water for use in hydraulic fracturing, whether due to usage restrictions or drought or other weather conditions, could curtail the Company’s operations or otherwise result in delays in operations or increased costs.

Volatility in the capital markets could affect the Company’s ability to obtain capital, cause the Company to incur additional financing expense or affect the value of certain assets.

In recent periods, global financial markets and economic conditions have been volatile due to multiple factors, including significant write-offs in the financial services sector and weak economic conditions. In some cases, the markets have produced downward pressure on stock prices and credit capacity for certain issuers without regard to those issuers’ underlying financial and/or operating strength. Due to this volatility, for many companies the cost of raising money in the debt and equity capital markets has been greater in recent periods than has historically been the case. Continued market volatility may from time to time adversely affect the Company’s ability to access capital and credit markets or to obtain funds at low interest rates or on other advantageous terms. These factors may adversely affect the Company’s business, results of operations or liquidity.

These factors may adversely affect the value of certain of the Company’s assets and its ability to draw on its senior credit facility. Adverse credit and capital market conditions may require the Company to reduce the carrying value of assets associated with derivative contracts to account for non-performance by, or increased credit risk from counterparties to those contracts. If financial institutions that have extended credit commitments to the Company are adversely affected by volatile conditions of the United States and international capital markets, they may become unable to fund borrowings under their credit commitments to the Company, which could have a material adverse effect on the Company’s financial condition and its ability to borrow additional funds, if needed, for working capital, capital expenditures and other corporate purposes.

Properties that the Company buys may not produce as projected, and the Company may be unable to determine reserve potential, identify liabilities associated with the properties or obtain protection from sellers against them.

The Company’s initial technical reviews of properties it acquires are inherently incomplete because an in-depth review of every individual property involved in each acquisition generally is not feasible. Even a

 

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detailed review of records and properties may not necessarily reveal existing or potential problems, nor will it 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 soil or ground water contamination, are not necessarily observable even when an inspection is undertaken. Even when problems are identified, the Company may assume certain environmental and other risks and liabilities in connection with acquired properties, and such risks and liabilities could have a material adverse effect on the Company’s results of operations and financial condition.

The development of the Company’s proved undeveloped reserves may take longer and may require higher levels of capital expenditures than it currently anticipates.

As of December 31, 2011, 51% of the Company’s total reserves were proved undeveloped reserves. Development of these reserves may take longer and require higher levels of capital expenditures than the Company currently anticipates. Therefore, ultimate recoveries from these fields may not match current expectations. Delays in the development of the Company’s reserves or increases in costs to drill and develop such reserves will reduce the PV-10 value of its estimated proved undeveloped reserves and future net revenues estimated for such reserves.

A significant portion of the Company’s operations are located in northwest Oklahoma, Kansas and west Texas, making it vulnerable to risks associated with operating in a limited number of major geographic areas.

As of December 31, 2011, approximately 71% of the Company’s proved reserves and approximately 66% of its annual production were located in the Mid-Continent and Permian Basin. This concentration could disproportionately expose the Company to operational and regulatory risk in these areas. This relative lack of diversification in location of the Company’s key operations could expose it to adverse developments in these areas or the oil and natural gas markets, including, for example, transportation or treatment capacity constraints, curtailment of production or treatment plant closures for scheduled maintenance. These factors could have a significantly greater impact on the Company’s financial condition, results of operations and cash flows than if its properties were more diversified.

The Company’s development and exploration operations require substantial capital, and the Company may be unable to obtain needed capital or financing on satisfactory terms, which could lead to a loss of properties and a decline in the Company’s oil and natural gas reserves.

The oil and natural gas industry is capital intensive. The Company makes substantial capital expenditures in its business and operations for the exploration, development, production and acquisition of oil and natural gas reserves. Historically, the Company has financed capital expenditures primarily with proceeds from asset sales and from the sale of equity, debt and cash generated by operations. The Company expects to finance its future capital expenditures with the sale of equity and debt securities, cash flow from operations, asset sales and current and new financing arrangements. The Company’s cash flow from operations and access to capital are subject to a number of variables, including:

 

   

the Company’s proved reserves;

 

   

the level of oil and natural gas it is able to produce from existing wells;

 

   

the prices at which oil and natural gas are sold; and

 

   

the Company’s ability to acquire, locate and produce new reserves.

If the Company’s revenues decrease as a result of lower oil and natural gas prices, operating difficulties, declines in reserves or for any other reason, it may have limited ability to obtain the capital necessary to sustain its operations at current levels. In order to fund the Company’s capital expenditures, it may seek additional

 

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financing. However, the Company’s senior credit facility contains covenants limiting its ability to incur additional indebtedness, which its lenders may withhold in their sole discretion. The Company’s senior note indentures also contain covenants that may restrict its ability to incur additional indebtedness if it does not satisfy certain financial metrics. If the Company is unable to obtain additional financing, it may be necessary for it to reduce or suspend its capital expenditures.

Disruptions in the global financial and capital markets also could adversely affect the Company’s ability to obtain debt or equity financing on favorable terms, or at all. The failure to obtain additional financing could result in a curtailment of the Company’s operations relating to exploration and development of its prospects, which in turn could lead to a possible loss of properties and a decline in the Company’s oil and natural gas reserves.

The agreements governing the Company’s existing indebtedness have restrictions, financial covenants and borrowing base redeterminations which could adversely affect its operations.

The Company’s senior credit facility and the indentures governing its senior notes restrict its ability to obtain additional financing, make investments, lease equipment, sell assets and engage in business combinations. The Company also is required to comply with certain financial covenants and ratios. The Company’s ability to comply with these restrictions and covenants in the future is uncertain and could be affected by the levels of cash flow from its operations and events or circumstances beyond its control. If commodity prices decline, this could adversely affect the Company’s ability to meet such restrictions and covenants. The Company’s failure to comply with any of the restrictions and covenants under the senior credit facility, senior notes or other debt financing could result in a default under those instruments, which could cause all of its existing indebtedness to be immediately due and payable.

The Company’s senior credit facility limits the amounts it can borrow to a borrowing base amount. The borrowing base is subject to review semi-annually; however, the lenders reserve the right to have one additional re-determination of the borrowing base per calendar year. Unscheduled re-determinations may be made at the Company’s request, but is limited to two requests per year. Borrowing base determinations are based upon proved developed producing reserves, proved developed non-producing reserves and proved undeveloped reserves. Outstanding borrowings exceeding the borrowing base must be repaid promptly, or it must pledge other oil and natural gas properties as additional collateral. The Company may not have the financial resources in the future to make any mandatory principal prepayments under the senior credit facility, which is required, for example, when the committed line of credit is exceeded, proceeds of asset sales in new oil and natural gas properties are not reinvested, or indebtedness that is not permitted by the terms of the senior credit facility is incurred. If the indebtedness under the Company’s senior credit facility and senior notes were to be accelerated, its assets may not be sufficient to repay such indebtedness in full.

The Company’s derivative activities could result in financial losses and could reduce its earnings.

To achieve a more predictable cash flow and to reduce the Company’s exposure to adverse fluctuations in the prices of oil and natural gas, the Company currently has, and may in the future, enter into derivative contracts for a portion of its oil and natural gas production, including fixed price swaps, collars and basis swaps. The Company has not and does not plan to designate any of its derivative contracts as hedges for accounting purposes and, as a result, records all derivative contracts on its balance sheet at fair value with changes in the fair value recognized in current period earnings. Accordingly, the Company’s earnings may fluctuate significantly as a result of changes in fair value of its derivative contracts. Derivative contracts also expose the Company to the risk of financial loss in some circumstances, including when:

 

   

production is less than expected;

 

   

the counterparty to the derivative contract defaults on its contract obligations; or

 

   

there is a change in the expected differential between the underlying price in the derivative contract and actual prices received.

 

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In addition, these types of derivative contracts limit the benefit the Company would receive from increases in the prices for oil and natural gas.

All of the Company’s consolidated drilling and services revenues are derived from companies in the oil and natural gas industry.

Companies to which the Company provides drilling and related services are affected by the oil and natural gas industry risks mentioned above. Market prices of oil and natural gas, limited access to capital and reductions in capital expenditures could result in oil and natural gas companies canceling or curtailing their drilling programs, which could reduce the demand for the Company’s drilling and related services. Any prolonged reduction in the overall level of exploration and development activities, whether resulting from changes in oil and natural gas prices or otherwise, could impact the Company’s drilling and services segment by negatively affecting:

 

   

revenues, cash flow and profitability;

 

   

the Company’s ability to retain skilled rig personnel whom it would need in the event of an upturn in the demand for drilling and related services; and

 

   

the fair value of the Company’s rig fleet.

A significant or prolonged decrease in natural gas production in the Company’s areas of operations, due to declines in production from existing wells, depressed commodity prices or otherwise, would adversely affect its ability to satisfy certain contractual obligations and revenues and cash flow from the Company’s midstream gas services segment.

In June 2009, the Company sold an entity, Piñon Gathering Company, LLC (“PGC”), holding its gathering and compression assets located in the Piñon Field, which is part of the WTO in Pecos County, Texas, to an unaffiliated third party. In conjunction with the sale, the Company entered into a gas gathering agreement pursuant to which it dedicated its Piñon Field acreage to PGC for gathering services for 20 years. During that period, the Company has minimum throughput and delivery obligations to PGC. In addition, the Company continues to construct gathering and compression assets in the Piñon Field. Most of the reserves supporting the Company’s contractual obligations to PGC and its own midstream assets are operated by the Company’s exploration and production segment. A material decrease in natural gas production in the Company’s areas of operation would result in a decline in the volume of natural gas delivered to PGC and the Company’s pipelines and facilities for gathering, transporting and treating. The Company has no control over many factors affecting production activity, including prevailing and projected energy prices, demand for hydrocarbons, the level of reserves, geological considerations, governmental regulation and the availability and cost of capital. The Company is obligated to pay minimum fees under the gas gathering agreement with PGC if it does not satisfy the contractual throughput and delivery commitments to PGC, due, for example, to the Company’s failure to connect new wells to PGC’s gathering systems or when there is a decline in the amount of natural gas that the Company produces from the Piñon Field. See Note 16 in Item 8 of this report for contractual amounts due under this agreement. In addition, if the Company fails to connect new wells to its own gathering systems, the amount of natural gas it gathers, transports and treats will decline substantially over time and could, upon exhaustion of the current wells, cause the Company to abandon its gathering systems and, possibly cease gathering, transporting and treating operations.

Many of the Company’s prospects in the WTO may contain natural gas that is high in CO2 content, which can negatively affect the Company’s economics.

The reservoirs of many of the Company’s prospects in the WTO may contain natural gas that is high in CO2 content. The natural gas produced from these reservoirs must be treated for the removal of CO2 prior to marketing. If the Company cannot obtain sufficient capacity at treatment facilities for its natural gas with a high

 

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CO2 concentration, or if the cost to obtain such capacity significantly increases, the Company could be forced to delay production and development or experience increased production costs. The Company will not know the amount of CO2 that it will encounter in any well until it is drilled. As a result, sometimes the Company encounters CO2 levels in its wells that are higher than expected. Since the treatment expenses are incurred on a Mcf basis, the Company will incur a higher effective treating cost per MMBtu of natural gas sold for natural gas with a higher CO2 content. As a result, high CO2 gas wells must produce at much higher rates than low CO2 gas wells to be economic, especially in a low natural gas price environment.

Furthermore, when the Company treats the gas for the removal of CO2, some of the methane is used to run the treatment plant as fuel gas and other methane and heavier hydrocarbons, such as ethane, propane and butane, cannot be separated from the CO2 and is lost. This is known as plant shrink. Historically the Company’s plant shrink has been approximately 6% in the WTO. After giving effect to plant shrink, as many as 3.5 Mcf of high CO2 natural gas must be produced to sell one MMBtu of natural gas. The Company reports its volumes of natural gas reserves and production net of CO2 volumes that are removed prior to sales.

The Company’s use of 2-D and 3-D seismic data is subject to interpretation and may not accurately identify the presence of oil and natural gas. In addition, the use of such technology requires greater predrilling expenditures, which could adversely affect the results of the Company’s drilling operations.

A significant aspect of the Company’s exploration and development plan involves seismic data. Even when properly used and interpreted, 2-D and 3-D seismic data and visualization techniques are only tools used to assist geoscientists in identifying subsurface structures and hydrocarbon indicators and do not enable the interpreter to know whether hydrocarbons are present in those structures. Other geologists and petroleum professionals, when studying the same seismic data, may have significantly different interpretations than the Company’s professionals.

In addition, the use of 2-D and 3-D seismic and other advanced technologies requires greater predrilling expenditures than traditional drilling strategies, and the Company could incur losses due to such expenditures. As a result, the Company’s drilling activities may not be geologically successful or economical, and the Company’s overall drilling success rate or its drilling success rate for activities in a particular area may not improve.

The Company may often gather 2-D and 3-D seismic data over large areas. The Company’s interpretation of seismic data delineates for it those portions of an area that it believes are desirable for drilling. Therefore, the Company may choose not to acquire option or lease rights prior to acquiring seismic data, and in many cases, it may identify hydrocarbon indicators before seeking option or lease rights in the location. If the Company is not able to lease those locations on acceptable terms, it will have made substantial expenditures to acquire and analyze 2-D and 3-D seismic data without having an opportunity to attempt to benefit from those expenditures.

Oil and natural gas wells are subject to operational hazards that can cause substantial losses for which the Company may not be adequately insured.

There are a variety of operating risks inherent in oil and natural gas production and associated activities, such as fires, leaks, explosions, mechanical problems, major equipment failures, blowouts, uncontrollable flow of oil, natural gas and natural gas liquids, water or drilling fluids, casing collapses, abnormally pressurized formations and natural disasters. The occurrence of any of these or similar accidents that temporarily or permanently halt the production and sale of oil and natural gas at any of the Company’s properties could have a material adverse impact on its business activities, financial condition and results of operations.

Additionally, if any of such risks or similar accidents occur, the Company could incur substantial losses as a result of injury or loss of life, severe damage or destruction of property, natural resources and equipment, regulatory investigation and penalties and environmental damage and clean-up responsibility. If the Company

 

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experiences any of these problems, its ability to conduct operations could be adversely affected. While the Company maintains insurance coverage it deems appropriate for these risks, the Company’s operations may result in liabilities exceeding such insurance coverage or liabilities not covered by insurance.

Shortages or increases in costs of equipment, services and qualified personnel could adversely affect the Company’s ability to execute its exploration and development plans on a timely basis and within its budget.

The demand for qualified and experienced personnel to conduct field operations, geologists, geophysicists, engineers and other professionals in the oil and natural gas industry can fluctuate significantly, often in correlation with oil and natural gas prices, causing periodic shortages. Historically, there have been shortages of drilling rigs and other equipment as demand for rigs and equipment has increased along with the number of wells being drilled. These factors also cause significant increases in costs for equipment, services and personnel. Higher oil and natural gas prices generally stimulate demand and result in increased prices for drilling rigs, crews and associated supplies, equipment and services. Shortages of field personnel and equipment or price increases could significantly affect the Company’s ability to execute its exploration and development plans as projected.

Market conditions or operational impediments may hinder the Company’s access to oil and natural gas markets or delay its production.

Market conditions or a lack of satisfactory oil and natural gas transportation arrangements may hinder the Company’s access to oil and natural gas markets or delay its production. The availability of a ready market for the Company’s oil and natural gas production depends on a number of factors, including the demand for and supply of oil and natural gas and the proximity of reserves to pipelines and terminal facilities. The Company’s ability to market its production depends, in substantial part, on the availability and capacity of gathering systems, pipelines and treating facilities. For example, in 2009 the Company experienced capacity limitations on high CO2 gas treating in the Piñon Field. The Company’s failure to obtain such services on acceptable terms in the future or expand the Company’s midstream assets could have a material adverse effect on its business. The Company may be required to shut in wells for a lack of a market or because access to natural gas pipelines, gathering system capacity or treating facilities may be limited or unavailable. The Company would be unable to realize revenue from any shut-in wells until production arrangements were made to deliver the production to market.

Competition in the oil and natural gas industry is intense, which may adversely affect the Company’s ability to succeed.

The oil and natural gas industry is intensely competitive, and the Company competes with companies that have greater resources than it does. Many of these companies not only explore for and produce oil and natural gas, but also conduct refining operations and market petroleum and other products on a regional, national or worldwide basis. These companies may be able to pay more for productive oil and natural gas properties and exploratory prospects or identify, evaluate, bid for and purchase a greater number of properties and prospects than the Company’s financial or human resources permit. In addition, these companies may have a greater ability to continue exploration activities during periods of low oil and natural gas market prices. The Company’s larger competitors may be able to absorb the burden of present and future federal, state, local and other laws and regulations more easily than the Company can, which would adversely affect the Company’s competitive position. The Company’s ability to acquire additional properties and to discover reserves in the future will be dependent upon its ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. In addition, because the Company has fewer financial and human resources than many companies in its industry, the Company may be at a disadvantage in bidding for exploratory prospects and producing oil and natural gas properties. See “Business—Competition” in Item 1 of this report.

Downturns in oil and natural gas prices can result in decreased oil field activity, which, in turn, can result in an oversupply of service providers and drilling rigs. This oversupply can result in severe reductions in prices received for oil field services or a complete lack of work for crews and equipment.

 

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The cost to construct the Century Plant may exceed estimated costs, and the Company may not be able to satisfy its CO2 volume delivery requirements.

The Company is constructing the Century Plant, a CO2 treatment plant in Pecos County, Texas, and associated compression and pipeline facilities pursuant to an agreement with a subsidiary of Occidental. The Century Plant will be owned and operated by Occidental for the purpose of separating and removing CO2 from natural gas delivered by the Company. The cost to construct the Century Plant may exceed current estimated costs, which exceeded the contract amount by approximately $130.0 million as of December 31, 2011. Pursuant to a 30-year treating agreement executed simultaneously with the construction agreement, Occidental will remove CO2 from the Company’s delivered production volumes, with the Company required to deliver certain minimum volumes annually and compensate Occidental to the extent such requirements are not met. The Company may not be able to find, produce and deliver enough high CO2 gas to meet its delivery obligations. As of December 31, 2011, the Company expects to accrue between approximately $17.0 million and $21.0 million during the year ending December 31, 2012 for amounts related to the Company’s shortfall in meeting its natural gas delivery obligations. In addition, there are significant risks associated with the operation and performance of a facility such as the Century Plant with no guarantee that the Century Plant will operate at its designed capacity or otherwise perform as anticipated.

The Company is subject to complex federal, state, local and other laws and regulations that could adversely affect the cost, manner or feasibility of conducting its operations or expose it to significant liabilities.

The Company’s oil and natural gas exploration, production, transportation and treatment operations are subject to complex and stringent laws and regulations. In order to conduct its operations in compliance with these laws and regulations, the Company must obtain and maintain numerous permits, approvals and certificates from various federal, state and local governmental authorities. The Company may incur substantial costs in order to maintain compliance with these existing laws and regulations. Further, in light of the explosion and fire on the drilling rig Deepwater Horizon in the Gulf of Mexico, as well as recent incidents involving the release of oil and natural gas and fluids as a result of drilling activities in the United States, there has been a variety of regulatory initiatives at the federal and state levels to restrict oil and natural gas drilling operations in certain locations. Any increased regulation or suspension of oil and natural gas exploration and production, or revision or reinterpretation of existing laws and regulations, that arises out of these incidents or otherwise could result in delays and higher operating costs. Such costs or significant delays could have a material adverse effect on the Company’s business, financial condition and results of operations. The Company must also comply with laws and regulations prohibiting fraud and market manipulations in energy markets. To the extent the Company is a shipper on interstate pipelines, it must comply with the tariffs of such pipelines and with federal policies related to the use of interstate capacity.

Laws and regulations governing oil and natural gas exploration and production may also affect production levels. The Company is required to comply with federal and state laws and regulations governing conservation matters, including provisions related to the unitization or pooling of the oil and natural gas properties; the establishment of maximum rates of production from wells; the spacing of wells; and the plugging and abandonment of wells. These and other laws and regulations can limit the amount of oil and natural gas the Company can produce from its wells, limit the number of wells it can drill, or limit the locations at which it can conduct drilling operations.

New laws or regulations, or changes to existing laws or regulations may unfavorably impact the Company, could result in increased operating costs and have a material adverse effect on its financial condition and results of operations. For example, Congress has recently considered, and may continue to consider, legislation that, if adopted in its proposed form, would subject companies involved in oil and natural gas exploration and production activities to, among other items, additional regulation of and restrictions on hydraulic fracturing of wells, and the elimination of most U.S. federal tax incentives and deductions available to oil and natural gas exploration and production activities. In addition, the Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”) and rules promulgated thereunder could reduce trading positions in the energy

 

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futures or swaps markets and materially reduce hedging opportunities for the Company, which could adversely affect its revenues and cash flows during periods of low commodity prices, and which could adversely affect the ability to restructure the Company’s hedges when it might be desirable to do so.

Additionally, state and federal regulatory authorities may expand or alter applicable pipeline safety laws and regulations, compliance with which may require increased capital costs on the part of the Company and third-party downstream oil and natural gas transporters. These and other potential regulations could increase the Company’s operating costs, reduce its liquidity, delay its operations, increase direct and third-party post production costs or otherwise alter the way it conducts its business, which could have a material adverse effect on the Company’s financial condition, results of operations and cash flows and which could reduce cash received by or available for distribution, including any amounts paid by the Company for transportation on downstream interstate pipelines.

The Company’s operations are subject to environmental laws and regulations that could adversely affect the cost, manner or feasibility of conducting operations or result in significant costs and liabilities.

The Company’s oil and natural gas exploration and production operations are subject to stringent and comprehensive federal, state, tribal, regional and local laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. These laws and regulations may impose numerous obligations that are applicable to the Company’s operations, including the acquisition of a permit before conducting drilling; water withdrawal or waste disposal activities; the restriction of types, quantities and concentration of materials that can be released into the environment; the limitation or prohibition of drilling activities on certain lands lying within wilderness, wetlands and other protected areas; impose regulations designed to protect employees from exposure to hazardous substances; and the imposition of substantial liabilities for pollution resulting from operations. Numerous governmental authorities, such as the EPA and analogous state agencies, have the power to enforce compliance with these laws and regulations and the permits issued under them, often requiring difficult and costly actions. Failure to comply with these laws and regulations may result in litigation; the assessment of administrative, civil or criminal penalties; the imposition of investigatory or remedial obligations; and the issuance of injunctions limiting or preventing some or all of the Company’s operations.

There is inherent risk of incurring significant environmental costs and liabilities in the performance of the Company’s operations due to its handling of petroleum hydrocarbons and wastes, because of air emissions and wastewater discharges related to its operations, and as a result of historical industry operations and waste disposal practices. Under certain environmental laws and regulations, the Company could be subject to joint and several strict liability for the investigation, removal or remediation of previously released materials or property contamination regardless of whether it was responsible for the release or contamination and whether its operations were in compliance with all applicable laws at the time those actions were taken. Private parties, including the owners of properties upon which the Company’s wells are drilled and facilities where the Company’s 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 contamination even in the absence of non-compliance, with environmental laws and regulations or for personal injury, natural resources damage or property damage. In addition, the risk of accidental spills or releases could expose the Company to significant liabilities that could have a material adverse effect on the Company’s financial condition or results of operations. Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent or costly construction, drilling, water management, completion, waste handling, storage, transport, disposal or cleanup requirements could require the Company to incur significant expenditures to attain and maintain compliance and may otherwise have a material adverse effect on its results of operations, competitive position or financial condition. The Company may not be able to recover some or any of these costs from insurance. As a result of the increased cost of compliance, the Company may decide to discontinue drilling.

 

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Repercussions from terrorist activities or armed conflict could harm the Company’s business.

Terrorist activities, anti-terrorist efforts or other armed conflict involving the United States or its interests abroad may adversely affect the United States and global economies and could prevent the Company from meeting its financial and other obligations. If events of this nature occur and persist, the attendant political instability and societal disruption could reduce overall demand for oil and natural gas, potentially putting downward pressure on prevailing oil and natural gas prices and causing a reduction in the Company’s revenues. Oil and natural gas production facilities, transportation systems and storage facilities could be direct targets of terrorist attacks, and or operations could be adversely impacted if infrastructure integral to the Company’s operations is destroyed by such an attack. Costs for insurance and other security may increase as a result of these threats, and some insurance coverage may become more difficult to obtain, if available at all.

If the Company fails to maintain an adequate system of internal control over financial reporting, it could adversely affect the Company’s ability to accurately report its results.

Management is responsible for establishing and maintaining adequate internal control over financial reporting. The Company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements in accordance with generally accepted accounting principles. A material weakness is a deficiency, or a combination of deficiencies, in its internal control over financial reporting that results in a reasonable possibility that a material misstatement of the annual or interim financial statements will not be prevented or detected on a timely basis. Effective internal controls are necessary for the Company to provide reliable financial reports and deter and detect any material fraud. If the Company cannot provide reliable financial reports or prevent material fraud, its reputation and operating results would be harmed. The Company’s efforts to develop and maintain its internal controls may not be successful, and it may be unable to maintain adequate controls over its financial processes and reporting in the future, including future compliance with the obligations under Section 404 of the Sarbanes-Oxley Act of 2002. Any failure to develop or maintain effective controls, or difficulties encountered in their implementation, including those related to acquired businesses, or other effective improvement of the Company’s internal controls could harm its operating results. Ineffective internal controls could also cause investors to lose confidence in the Company’s reported financial information.

Certain U.S. federal income tax preferences currently available with respect to oil and natural gas production may be eliminated as a result of future legislation.

In recent years, the Obama administration’s budget proposals and other proposed legislation have included the elimination of certain key U.S. federal income tax incentives currently available to oil and gas exploration and production. If enacted into law, these proposals would eliminate certain tax preferences applicable to taxpayers engaged in the exploration or production of natural resources. These changes include, but are not limited to (i) the repeal of the percentage depletion allowance for oil and gas properties, (ii) the elimination of current deductions for intangible drilling and development costs, (iii) the elimination of the deduction for U.S. production activities and (iv) the increase in the amortization period from two years to seven years for geophysical costs paid or incurred in connection with the exploration for or development of, oil and gas within the United States. It is unclear whether any such changes will be enacted or how soon any such changes would become effective. The passage of any legislation as a result of these proposals or any other similar changes in U.S. federal income tax laws could negatively affect the Company’s financial condition and results of operations.

New derivatives legislation and regulation could adversely affect the Company’s ability to hedge risks associated with its business.

The Dodd-Frank Act creates a new regulatory framework for oversight of derivatives transactions by the Commodity Futures Trading Commission (the “CFTC”) and the SEC. Among other things, the Dodd-Frank Act subjects certain swap participants to new capital, margin and business conduct standards. In addition, the Dodd-

 

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Frank Act contemplates that where appropriate in light of outstanding exposures, trading liquidity and other factors, swaps (broadly defined to include most hedging instruments other than futures) will be required to be cleared through a registered clearing facility and traded on a designated exchange or swap execution facility. The Dodd-Frank Act also establishes a new Energy and Environmental Markets Advisory Committee to make recommendations to the CFTC regarding matters of concern to exchanges, firms, end users and regulators with respect to energy and environmental markets and also expands the CFTC’s power to impose position limits on specific categories of swaps (excluding swaps entered into for bona fide hedging purposes).

There are some exceptions to these requirements for entities that use swaps to hedge or mitigate commercial risk. While the Company may qualify for one or more of such exceptions, the scope of these exceptions is uncertain and will be further defined through rulemaking proceedings at the CFTC and SEC. Further, although the Company may qualify for exceptions, its derivatives counterparties may be subject to new capital, margin and business conduct requirements imposed as a result of the new legislation, which may increase the Company’s transaction costs or make it more difficult for it to enter into hedging transactions on favorable terms. The Company’s inability to enter into hedging transactions on favorable terms, or at all, could increase its operating expenses and put it at increased exposure to risks of adverse changes in oil and natural gas prices, which could adversely affect the predictability of cash flows from sales of oil and natural gas.

In November 2011, the CFTC finalized rules to establish a position limits regime on certain “core” physical-delivery contracts and their economically equivalent derivatives, some of which reference major energy commodities, including oil and natural gas. The final rules became effective on January 17, 2012 and compliance with the rules shall be required 60 days after the CFTC completes certain definitional rulemaking, which is expected to occur later in 2012. Therefore, it is not possible at this time to predict the consequences that will arise from the new position limits regime. Regulations that subject the Company or its derivatives counterparties to limits on commodity positions could have an adverse effect on the Company’s ability to hedge risks associated with its business or on the cost of its hedging activity.

Federal and state legislative and regulatory initiatives as well as governmental reviews relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays as well as adversely affect the Company’s level of production.

Hydraulic fracturing is an important and common practice that is used to stimulate production of hydrocarbons from tight formations, such as shales. The process involves the injection of water, sand and chemicals under pressure into formations to fracture the surrounding rock and stimulate production. The process is typically regulated by state oil and gas commissions. However, the EPA has asserted federal regulatory authority over certain hydraulic fracturing practices. Also, legislation has been introduced, but not enacted, in Congress to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the fracturing process. Certain states in which the Company operates, including Texas and Oklahoma, and municipalities have adopted, or are considering adopting, regulations that have imposed, or that could impose, more stringent permitting, disclosure, disposal and well construction requirements on hydraulic fracturing operations. For example, in December 2011, the Railroad Commission of Texas finalized regulations requiring public disclosure of all the chemicals in fluids used in the hydraulic fracturing process. Local ordinances or other regulations may regulate or prohibit the performance of well drilling in general and hydraulic fracturing in particular. If new laws or regulations that significantly restrict or regulate hydraulic fracturing are adopted, such legal requirements could cause project delays and make it more difficult or costly for the Company to perform fracturing to stimulate production from a formation. These delays or additional costs could adversely affect the determination of whether a well is commercially viable. Restrictions on hydraulic fracturing could also reduce the amount of oil and natural gas that the Company is ultimately able to produce in commercial quantities.

In addition, a number of federal agencies are analyzing, or have been requested to review, a variety of environmental issues associated with hydraulic fracturing. The White House Council on Environmental Quality is coordinating an administration-wide review of hydraulic fracturing practices, and a committee of the United

 

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States House of Representatives has conducted an investigation of hydraulic fracturing practices. The EPA has commenced a study of the potential environmental effects of hydraulic fracturing on drinking water and groundwater, with initial results expected to be available by late 2012 and final results by 2014. Moreover, the EPA announced on October 20, 2011 that it is also launching a study regarding wastewater resulting from hydraulic fracturing activities and currently plans to propose standards by 2014 that such wastewater must meet before being transported to a treatment plant. In addition, the U.S. Department of Energy is conducting an investigation of practices the agency could recommend to better protect the environment from drilling using hydraulic fracturing completion methods. Also, the U.S. Department of the Interior is considering disclosure requirements or other mandates for hydraulic fracturing on federal lands. Additionally, certain members of Congress have called upon the U.S. Government Accountability Office to investigate how hydraulic fracturing might adversely affect water resources; the SEC to investigate the natural gas industry and any possible misleading of investors or the public regarding the economic feasibility of pursuing natural gas deposits in shales by means of hydraulic fracturing; and the U.S. Energy Information Administration to provide a better understanding of that agency’s estimates regarding natural gas reserves, including reserves from shale formations, as well as uncertainties associated with those estimates. These ongoing or proposed studies, depending on their degree of pursuit and any meaningful results obtained, could spur initiatives to further regulate hydraulic fracturing under the federal Safe Drinking Water Act or other regulatory mechanisms.

Climate change laws and regulations restricting emissions of “greenhouse gases” could result in increased operating costs and reduced demand for the oil and natural gas that the Company produces while the physical effects of climate change could disrupt its production and cause the Company to incur significant costs in preparing for or responding to those effects.

In December 2009, the EPA published its findings that emissions of GHGs present a danger to public health and the environment. These findings allow the agency to adopt and implement regulations that would restrict emissions of GHGs under existing provisions of the Clean Air Act. Accordingly, the EPA has adopted rules that require a reduction in emissions of GHGs from motor vehicles and also trigger Clean Air Act construction and operating permit review for GHG emissions from certain stationary sources. The EPA’s rules relating to emissions of GHGs from stationary sources of emissions are currently subject to a number of political and legal challenges, but the federal courts have thus far declined to issue any injunctions to prevent the EPA from implementing, or requiring state environmental agencies to implement, the rules. In addition, the EPA has adopted rules requiring the reporting of GHG emissions from onshore oil and natural gas production facilities in the United States on an annual basis. Both houses of Congress have from time to time considered legislation to reduce emissions of GHGs and almost one-half of the states, either individually or through multi-state regional initiatives, already have begun implementing legal measures to reduce emissions of GHGs. The adoption and implementation of any regulations imposing reporting obligations on, or limiting emissions of GHGs from, the Company’s equipment and operations could require it to incur additional costs to reduce emissions of GHGs associated with its operations or could adversely affect demand for the oil and natural gas that it produces. Finally, some scientists have concluded that increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that could have significant physical effects, such as increased frequency and severity of storms, droughts, and floods and other climatic events; if any such effects were to occur, they could have an adverse effect on the Company’s assets and operations.

Risks Related to the Company’s Acquisition of Dynamic Offshore Resources, LLC

If the Company completes its pending acquisition of Dynamic, its business and prospects will be subject to additional risks relating to Dynamic’s offshore operations in the Gulf of Mexico, and risks relating to offshore operations generally may become more significant to the operation of the Company’s business as a whole.

The Company may not realize the anticipated benefits of its pending acquisition of Dynamic or other future acquisitions, and integration of acquisitions may disrupt the Company’s business and management.

 

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The Company’s acquisition of Dynamic is pending and the Company may acquire other companies or large asset packages in the future, as it has done in the past. The Company may not realize the anticipated benefits of the Dynamic acquisition or other future acquisitions, and each acquisition has numerous risks. These risks include:

 

   

difficulty in assimilating the operations and personnel of the acquired company;

 

   

difficulty in maintaining controls, procedures and policies during the transition and integration;

 

   

disruption of the Company’s ongoing business and distraction of its management and employees from other opportunities and challenges;

 

   

difficulty integrating the acquired company’s accounting, management information systems, human resources and other administrative systems;

 

   

inability to retain key personnel of the acquired business;

 

   

inability to achieve the financial and strategic goals for the acquired and combined businesses;

 

   

inability to take advantage of anticipated tax benefits;

 

   

potential failure of the due diligence processes to identify significant problems, liabilities or other shortcomings or challenges of an acquired business;

 

   

exposure to litigation and other potential liabilities in connection with environmental laws regulating exploration and production activities related to entities that the Company acquires, or that were previously acquired by such entities;

 

   

exposure to litigation or other claims in connection with, or inheritance of claims or litigation risk as a result of, an acquisition, including but not limited to, claims from terminated employees, customers, former stockholders or other third-parties;

 

   

potential inability to assert that internal controls over financial reporting are effective; and

 

   

potential incompatibility of business cultures.

If the Company completes the Dynamic acquisition, Dynamic’s offshore operations will involve special risks that could adversely affect operations.

Offshore operations are subject to a variety of operating risks specific to the marine environment, such as capsizing, collisions and damage or loss from hurricanes or other adverse weather conditions. These conditions can cause substantial damage to facilities and interrupt production. As a result, if the Company completes the Dynamic acquisition, it could incur substantial liabilities that could reduce or eliminate the funds available for exploration, development or leasehold acquisitions or result in loss of equipment and properties.

In addition, if the Company completes the Dynamic acquisition, an oil spill on or related to offshore properties and operations could expose the Company to joint and several strict liability, without regard to fault, under applicable law for all containment and oil removal costs and a variety of public and private damages including, but not limited to, the costs of responding to a release of oil, natural resource damages, and economic damages suffered by persons adversely affected by an oil spill. If an oil discharge or substantial threat of discharge were to occur, the Company may be liable for costs and damages, which costs and damages could be material to its business, financial condition or results of operations.

If the Company completes the Dynamic acquisition, reserves associated with Gulf of Mexico properties would have relatively short production periods or reserve lives.

High production rates generally result in recovery of a relatively higher percentage of reserves from properties in the Gulf of Mexico during the initial few years when compared to other regions in the United States.

 

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Due to high initial production rates, production of reserves from reservoirs in the Gulf of Mexico generally decline more rapidly than from other producing reservoirs. As a result, if the Company completes the Dynamic acquisition, its reserve replacement needs from new prospects in the Gulf of Mexico may be greater than reserve replacement needs for other properties with longer-life reserves in other producing areas. Also, expected revenues and return on capital for Gulf of Mexico properties will depend on prices prevailing during these relatively short production periods.

If the Company completes the Dynamic acquisition, its operations in the Gulf of Mexico may face broad adverse consequences resulting from increased regulation of offshore drilling operations as a result of the Deepwater Horizon incident, some of which may be unforeseeable.

The April 2010 explosion and fire on the drilling rig Deepwater Horizon and resulting major oil spill produced significant economic, environmental and natural resource damage in the Gulf Coast region. In response to the explosion and spill, there have been many proposals by governmental and private constituencies to address the direct impact of the disaster and to prevent similar disasters in the future. The BOEMRE issued a series of “Notices to Lessees and Operators” (“NTLs”), which imposed a variety of new safety measures and permitting requirements, and implemented a temporary moratorium on deepwater drilling activities in the Gulf of Mexico that effectively shut down deepwater drilling activities for six months in 2010. Despite the fact that the drilling moratorium was lifted, this spill and its aftermath have led to delays in obtaining drilling permits from the BOEMRE. If the Company completes the Dynamic acquisition, it will be required to interact with both BOEM and BSEE to obtain approval of exploration and development plans and issuance of drilling permits for Dynamic’s properties, which may result in added plan approval or drilling permit delays. While legislation has been introduced in the U.S. Congress to expedite the process for obtaining offshore permits that include limitations on the timeframe for environmental and judicial review, there is no guarantee that this or similar legislation will pass.

In addition to the drilling restrictions, new safety measures and permitting requirements issued by the BOEMRE, there have been numerous additional proposed changes in laws, regulations, guidance and policy in response to the Deepwater Horizon explosion and oil spill that could affect offshore operations and cause the Company to incur substantial losses or expenditures if it completes the Dynamic acquisition. Implementation of any one or more of the various proposed responses to the disaster could materially adversely affect operations in the Gulf of Mexico by raising operating costs, increasing insurance premiums, delaying drilling operations and increasing regulatory costs, and, further, could lead to a wide variety of other unforeseeable consequences that could make operations in the Gulf of Mexico more difficult, time consuming and costly.

If the Company completes the Dynamic acquisition, new regulatory requirements could significantly delay the Company’s ability to obtain permits to drill new wells in offshore waters.

Following the Deepwater Horizon incident, the BOEMRE issued a series of NTLs and other regulatory requirements imposing new standards and permitting procedures for new wells to be drilled in federal waters of the Outer Continental Shelf. These requirements include the following:

 

   

The Environmental NTL, which imposes new and more stringent requirements for documenting the environmental impacts potentially associated with the drilling of a new offshore well and significantly increases oil spill response requirements.

 

   

The Compliance and Review NTL, which imposes requirements for operators to secure independent reviews of well design, construction and flow intervention processes, and also requires certifications of compliance from senior corporate officers.

 

   

The Drilling Safety Rule, which prescribes tighter cementing and casing practices, imposes standards for the use of drilling fluids to maintain wellbore integrity, and stiffens oversight requirements relating to blowout preventers and their components, including shear and pipe rams.

 

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The Workplace Safety Rule, which requires operators to have a comprehensive safety and environmental management system (“SEMS”) in order to reduce human and organizational errors as root causes of work-related accidents and offshore spills.

On September 14, 2011, BOEMRE proposed rules that would amend the Workplace Safety Rule by requiring the imposition of certain added safety procedures to a company’s SEMS not covered by the original rule and revising existing obligations that a company’s SEMS be audited by requiring the use of an independent third party auditor who has been pre-approved by the agency to perform the auditing task.

As a result of the issuance of these new regulatory requirements, the BSEE has been taking much longer than in the past to review and approve permits for drilling operations. If the Company completes the Dynamic acquisition, it may encounter increased costs associated with regulatory compliance and delays in obtaining permits for other operations such as recompletions, workovers and abandonment activities. The Company is unsure what long-term effect, if any, additional regulatory requirements and permitting procedures will have on offshore operations. Consequently, if the Company completes the Dynamic acquisition, the Company may become subject to a variety of unforeseen adverse consequences arising directly or indirectly from the Deepwater Horizon incident.

If the Company completes the Dynamic acquisition, new regulatory requirements could significantly impact the Company’s estimates of future asset retirement obligations from period to period.

If the Company completes the Dynamic acquisition, it will be responsible for plugging and abandoning wellbores and decommissioning associated platforms, pipelines and facilities on Dynamic’s oil and natural gas properties. In addition to the NTLs discussed previously, the BOEMRE issued an NTL that became effective in October 2010, which establishes more stringent requirements for the timely decommissioning of wells, platforms and pipelines that are no longer producing or serving exploration or support functions related to an operator’s lease in the Gulf of Mexico. This NTL requires that any well that has not been used during the past five years for exploration or production on an active lease and is no longer capable of producing in paying quantities must be permanently plugged or temporarily abandoned within three years. Plugging or abandonment of wells may be delayed by two years if all of the well’s hydrocarbon and sulphur zones are appropriately isolated. Similarly, platforms or other facilities that are no longer useful for operations must be removed within one year of the cessation of operations. If the Company completes the Dynamic acquisition, these new regulations affecting plugging, abandonment and removal activities may serve to increase, perhaps materially, the future plugging, abandonment and removal costs associated with Dynamic’s properties, which may translate into a need to increase the Company’s estimate of future asset retirement obligations required to meet such increased costs. Moreover, implementation of this NTL could likely result in increased demand for salvage contractors and equipment, resulting in increased estimates of plugging, abandonment and removal costs and increases in related asset retirement obligations.

If the Company completes the Dynamic Acquisition, its estimates of future asset retirement obligations may increase significantly and become more variable from period to period because Dynamic’s operations are exclusively in the Gulf of Mexico.

The Company is required to record a liability for the present value of asset retirement obligations to plug and abandon inactive, non-producing wells, to remove inactive or damaged platforms, facilities and equipment, and to restore the land or seabed at the end of oil and natural gas production operations. These costs are typically considerably more expensive for offshore operations as compared to most land-based operations, due to increased regulatory scrutiny and the logistical issues associated with working in waters of various depths. Estimating future restoration and removal costs in the Gulf of Mexico is especially difficult because most of the removal obligations may be many years in the future, regulatory requirements are subject to change or more restrictive interpretation, and asset removal technologies are constantly evolving, which may result in additional or increased costs. As a result, if the Company completes the Dynamic acquisition, it may make significant

 

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increases or decreases to estimated asset retirement obligations in future periods. For example, because Dynamic operates in the Gulf of Mexico, platforms, facilities and equipment are subject to damage or destruction as a result of hurricanes. The estimated cost to plug and abandon a well or dismantle a platform can change dramatically if the host platform from which the work was anticipated to be performed is damaged or toppled, rather than structurally intact. Accordingly, if the Company completes the Dynamic acquisition, its estimates of future asset retirement obligations could differ dramatically from what it may ultimately incur as a result of damage from a hurricane.

If the Company completes the Dynamic acquisition, insurance may not protect the Company against business and operating risks associated with Dynamic’s properties.

If the Company completes the Dynamic acquisition, it intends to maintain insurance for some, but not all, of the potential risks and liabilities associated with Dynamic’s business. For some risks, the Company may not obtain insurance if it believes the cost of available insurance is excessive relative to the risks presented. Due to market conditions, premiums and deductibles for certain insurance policies can increase substantially and, in some instances, certain insurance policies are economically unavailable or available only for reduced amounts of coverage. Although the Company will maintain insurance at levels it believes are appropriate and consistent with industry practice, the Company will not be fully insured against all risks, including high-cost business interruption insurance and drilling and completion risks that are generally not recoverable from third parties or insurance. In addition, pollution and environmental risks generally are not fully insurable. Losses and liabilities from uninsured and underinsured events and delay in the payment of insurance proceeds could have a material adverse effect on the Company’s business, financial condition and results of operations.

Insurance costs have generally risen in recent years due to a number of catastrophic events, including Hurricanes Ivan, Katrina, Rita, Gustav and Ike, the Deepwater Horizon incident, the September 11, 2001 terrorist attacks and the 2011 Japanese tsunami. The offshore oil and natural gas industry suffered extensive damage from the previously mentioned hurricanes and, as a result, insurance costs related to offshore oil and gas operations have increased significantly compared to the cost of insuring onshore oil and gas production. Insurers are requiring higher retention levels and limit the amount of insurance proceeds that are available after a major windstorm in the event that damages are incurred. If storm activity in the future is as severe as it was in 2005 or 2008, insurance underwriters may no longer insure Gulf of Mexico assets against weather-related damage. In addition, the Company does not have in place, and does not intend to put in place, business interruption insurance due to its high cost. If the Company completes the Dynamic acquisition and an accident or other event results in damage to offshore operations, including severe weather, terrorist acts, war, civil disturbances, pollution or environmental damage, occurs and is not fully covered by insurance or a recoverable indemnity from a vendor, it could adversely affect the Company’s business, financial condition and results of operations. Moreover, the Company may not be able to maintain adequate insurance in the future at rates it considers reasonable or be able to obtain insurance against certain risks.

 

Item 1B. Unresolved Staff Comments

None.

 

Item 2. Properties

Information regarding the Company’s properties is included in Item 1. Also, refer to Note 25 of the notes to the Company’s consolidated financial statements included in Item 8 of this report.

 

Item 3. Legal Proceedings

On February 14, 2011, Aspen Pipeline, II, L.P. (“Aspen”), filed a complaint in the District Court of Harris County, Texas, against Arena Resources, Inc. and SandRidge Energy, Inc. claiming damages based upon alleged

 

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representations by Arena in connection with Aspen’s construction of a natural gas pipeline in west Texas. On October 14, 2011, the complaint was amended to add Odessa Fuels, LLC, Odessa Fuels Marketing, LLC and Odessa Field Services and Compression, LLC as plaintiffs. The plaintiffs’ amended claims seek damages relating to the construction of the pipeline and performance under a related gas purchase agreement, which damages are alleged to approach $100.0 million. The Company intends to defend this lawsuit vigorously and believes the plaintiffs’ claims are without merit. This case is in the early stages and, accordingly, an estimate of reasonably possible losses associated with this claim, if any, cannot be made until the facts, circumstances and legal theories relating to the plaintiffs’ claims and the Company’s defenses are fully disclosed and analyzed. The Company has not established any reserves relating to this claim.

On April 5, 2011, Wesley West Minerals, Ltd. and Longfellow Ranch Partners, LP, filed suit against SandRidge Energy, Inc. and SandRidge Exploration and Production, LLC (collectively, the “SandRidge Entities”) in the 83rd District Court of Pecos County, Texas. The plaintiffs, who have leased mineral rights to the SandRidge Entities in Pecos County, allege that the SandRidge Entities have not properly paid royalties on all volumes of natural gas (including CO2) produced from the acreage leased from the plaintiffs. The plaintiffs also allege that the SandRidge Entities have inappropriately failed to pay royalties on CO2 produced from plaintiffs’ acreage that results from the treatment of natural gas at the Century Plant. The plaintiffs seek unspecified actual damages, punitive damages and a declaration that the SandRidge Entities must pay royalties on CO2 produced from plaintiffs’ acreage that results from treatment of natural gas at the Century Plant. The Commissioner of the General Land Office of the State of Texas (“GLO”) is named as an additional defendant in the lawsuit as some of the affected oil and natural gas leases described in plaintiffs’ allegations cover mineral classified lands in which the GLO is entitled to one-half of the royalties attributable to such leases. The GLO has filed a cross-claim against the SandRidge Entities asserting the same claims as the plaintiffs with respect to the leases covering mineral classified lands. The Company intends to defend this lawsuit vigorously. This case is in the early stages and, accordingly, an estimate of reasonably possible losses associated with these claims, if any, cannot be made until the facts, circumstances and legal theories relating to the plaintiffs’ claims and the Company’s defenses are fully disclosed and analyzed. The Company has not established any reserves relating to these claims.

On August 4, 2011, Patriot Exploration, LLC, Jonathan Feldman, Redwing Drilling Partners, Mapleleaf Drilling Partners, Avalanche Drilling Partners, Penguin Drilling Partners and Gramax Insurance Company Ltd. filed a lawsuit against SandRidge Energy, Inc., SandRidge Exploration and Production, LLC (“SandRidge E&P”) and certain directors and senior executive officers of SandRidge Energy, Inc. (collectively, the “defendants”), in the U.S. District Court for the District of Connecticut. The plaintiffs allege that the defendants made false and misleading statements to U.S. Drilling Capital Management LLC and the plaintiffs prior to the entry into a participation agreement among Patriot Exploration LLC, U.S. Drilling Capital Management LLC and SandRidge E&P, which provided for the investment by the plaintiffs in certain of SandRidge E&P’s oil and natural gas properties. To date, the plaintiffs have invested approximately $15.0 million under the participation agreement. The plaintiffs seek compensatory and punitive damages and rescission of the participation agreement. The Company intends to defend this lawsuit vigorously and believes the plaintiffs’ claims are without merit. This case is in the early stages and, accordingly, an estimate of reasonably possible losses associated with this claim, if any, cannot be made until the facts, circumstances and legal theories relating to the plaintiffs’ claims and the Company’s defenses are fully disclosed and analyzed. The Company has not established any reserves relating to this claim.

SandRidge is a defendant in lawsuits from time to time in the normal course of business. In management’s opinion, based on currently available information, the Company is not currently involved in any other legal proceedings that, individually or in the aggregate, could have a material adverse effect on its financial condition, operations or cash flows.

 

Item 4. Mine Safety Disclosures

Not applicable.

 

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PART II

 

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

PRICE RANGE OF COMMON STOCK

The Company’s common stock is listed on the New York Stock Exchange (“NYSE”) under the symbol “SD.” The range of high and low sales prices for its common stock for the periods indicated, as reported by the NYSE, is as follows:

 

     High      Low  

2011

     

Fourth Quarter

   $ 8.57       $ 5.01   

Third Quarter

   $ 12.11       $ 5.56   

Second Quarter

   $ 12.97       $ 9.98   

First Quarter

   $ 12.80       $ 7.15   

2010

     

Fourth Quarter

   $ 7.49       $ 4.85   

Third Quarter

   $ 6.79       $ 3.87   

Second Quarter

   $ 8.03       $ 5.20   

First Quarter

   $ 11.08       $ 7.13   

On February 17, 2012, there were 286 record holders of the Company’s common stock.

The Company has neither declared nor paid any cash dividends on its common stock, and it does not anticipate declaring any dividends on its common stock in the foreseeable future. The Company expects to retain its cash for the operation and expansion of its business, including exploration, development and production activities. In addition, the terms of the Company’s indebtedness restrict its ability to pay dividends to holders of its common stock. Accordingly, if the Company’s dividend policy were to change in the future, its ability to pay dividends would be subject to these restrictions and the Company’s then-existing conditions, including its results of operations, financial condition, contractual obligations, capital requirements, business prospects and other factors deemed relevant by its board of directors.

ISSUER PURCHASES OF EQUITY SECURITIES

As part of the Company’s restricted stock program, the Company makes required tax payments on behalf of employees when their stock awards vest and then withholds a number of vested shares of common stock having a value on the date of vesting equal to the tax obligation. The shares withheld are initially recorded as treasury stock and, beginning in December 2010, are immediately retired as repurchased. See Note 17 to the consolidated financial statements included in Item 8 of this report for further discussion of treasury stock. During the quarter ended December 31, 2011, the following shares of common stock were withheld in satisfaction of tax withholding obligations arising from the vesting of restricted stock:

 

     Total Number of
Shares  Purchased
     Average Price
Paid per  Share
     Total Number of
Shares Purchased
as Part of Publicly
Announced Plans
or Programs
     Maximum Number
of Shares that May
Yet Be Purchased
Under the Plans or
Programs
 

Period

           

October 1, 2011—October 31, 2011

     24,724       $ 6.11         N/A         N/A   

November 1, 2011—November 30, 2011

     6,643       $ 7.34         N/A         N/A   

December 1, 2011—December 31, 2011

     1,079       $ 7.50         N/A         N/A   

 

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Item 6. Selected Financial Data

The following table sets forth, as of the dates and for the periods indicated, the Company’s selected financial information. The Company’s financial information is derived from its audited consolidated financial statements for such periods. The financial data includes the results of the Arena Acquisition, effective July 16, 2010, and the Forest Acquisition, effective December 21, 2009. The information should be read in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in Item 7 of this report and the Company’s consolidated financial statements and notes thereto contained in “Financial Statements and Supplementary Data” in Item 8 of this report. The following information is not necessarily indicative of the Company’s future results.

 

    Year Ended December 31,  
    2011     2010     2009     2008     2007  
    (In thousands, except per share data)  

Statement of Operations Data

         

Revenues

  $ 1,415,213      $ 931,736      $ 591,044      $ 1,181,814      $ 677,452   

Expenses

         

Production

    322,877        237,863        169,880        159,545        106,192   

Production taxes

    46,069        29,170        4,010        30,594        19,557   

Drilling and services

    65,654        22,368        28,380        22,872        44,211   

Midstream and marketing

    66,007        90,149        80,608        189,428        94,253   

Depreciation and depletion—oil and natural gas

    326,614        275,335        176,027        290,917        173,568   

Depreciation and amortization—other

    53,630        50,776        50,865        70,448        53,541   

Impairment

    2,825        —          1,707,150        1,867,497        —     

General and administrative

    148,643        179,565        100,256        109,372        61,780   

(Gain) loss on derivative contracts

    (44,075     50,872        (147,527     (211,439     (60,732

(Gain) loss on sale of assets

    (2,044     2,424        26,419        (9,273     (1,777
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total operating expenses

    986,200        938,522        2,196,068        2,519,961        490,593   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Income (loss) from operations

    429,013        (6,786     (1,605,024     (1,338,147     186,859   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Other income (expense)

         

Interest income

    240        296        375        3,569        4,694   

Interest expense

    (237,572     (247,738     (185,691     (147,027     (117,185

Loss from extinguishment of debt

    (38,232     —          —          —          —     

Income from equity investments

    —          —          1,020        1,398        4,372   

Other income, net

    3,122        2,558        7,272        1,454        729   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total other expense

    (272,442     (244,884     (177,024     (140,606     (107,390
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Income (loss) before income taxes

    156,571        (251,670     (1,782,048     (1,478,753     79,469   

Income tax (benefit) expense

    (5,817     (446,680     (8,716     (38,328     29,524   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Net income (loss)

    162,388        195,010        (1,773,332     (1,440,425     49,945   

Less: net income (loss) attributable to noncontrolling interest(1)

    54,323        4,445        2,258        855        (276
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Net income (loss) attributable to SandRidge Energy, Inc

    108,065        190,565        (1,775,590     (1,441,280     50,221   

Preferred stock dividends and accretion

    55,583        37,442        8,813        16,232        39,888   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Income available (loss applicable) to SandRidge Energy, Inc., common stockholders

  $ 52,482      $ 153,123      $ (1,784,403   $ (1,457,512   $ 10,333   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Earnings (loss) per share information

         

Basic.

  $ 0.13      $ 0.52      $ (10.20   $ (9.36   $ 0.09   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Diluted

  $ 0.13      $ 0.52      $ (10.20   $ (9.36   $ 0.09   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Weighted average number of SandRidge Energy, Inc., common shares outstanding

         

Basic

    398,851        291,869        175,005        155,619        108,828   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Diluted

    406,645        315,349        175,005        155,619        110,041   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

 

(1)

2011 net income attributable to noncontrolling interest includes amounts attributable to third-party unitholders of the Mississippian Trust I and Permian Trust.

 

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     As of December 31,  
     2011      2010      2009     2008      2007  
     (In thousands)  

Balance Sheet Data

             

Cash and cash equivalents

   $ 207,681       $ 5,863       $ 7,861      $ 636       $ 63,135   

Property, plant and equipment, net

   $ 5,389,424       $ 4,733,865       $ 2,433,643      $ 3,175,559       $ 3,337,410   

Total assets

   $ 6,219,609       $ 5,231,448       $ 2,780,317      $ 3,655,058       $ 3,630,566   

Long-term debt

   $ 2,814,176       $ 2,909,086       $ 2,578,938      $ 2,375,316       $ 1,067,649   

Redeemable convertible preferred stock(1)

   $ —         $ —         $ —        $ —         $ 450,715   

Total equity

   $ 2,548,950       $ 1,547,483       $ (195,905   $ 793,551       $ 1,771,563   

Total liabilities and equity

   $ 6,219,609       $ 5,231,448       $ 2,780,317      $ 3,655,058       $ 3,630,566   

 

(1)

On May 7, 2008, the Company converted all of its then outstanding redeemable convertible preferred stock into shares of its common stock.

There have been no cash dividends declared or paid on the Company’s common stock.

 

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

The following discussion and analysis is intended to help the reader understand the Company’s business, financial condition, results of operations, liquidity and capital resources. This discussion and analysis should be read in conjunction with other sections of this report, including: “Business” in Item 1, “Selected Financial Data” in Item 6 and “Financial Statements and Supplementary Data” in Item 8. The information in the discussion and analysis below includes the activities of the Mississippian Trust I and the Permian Trust, including amounts attributable to noncontrolling interests. The Company’s discussion and analysis relates to the following subjects:

 

   

Results by Segment;

 

   

Consolidated Results of Operations;

 

   

Liquidity and Capital Resources;

 

   

Critical Accounting Policies and Estimates; and

 

   

New Accounting Pronouncements

Results by Segment

The Company operates in three business segments: exploration and production, drilling and oil field services and midstream gas services. The activities of the Mississippian Trust I and the Permian Trust are included in the exploration and production segment. The All Other column in the tables below includes items not related to the Company’s reportable segments, including its CO2 gathering and sales operations and corporate operations. Management evaluates the performance of the Company’s business segments based on income (loss) from operations, which is defined as segment operating revenues less operating expenses and depreciation, depletion and amortization. Results of these measurements provide important information to the Company about the activity and profitability of the Company’s lines of business. Set forth in the table below is financial information regarding each of the Company’s business segments for the years ended December 31, 2011, 2010 and 2009 (in thousands).

 

    Exploration  and
Production
    Drilling and Oil
Field Services
    Midstream  Gas
Services
    All Other     Consolidated
Total
 

Year Ended December 31, 2011

         

Revenues

  $ 1,237,565      $ 390,485      $ 183,912      $ 10,535      $ 1,822,497   

Inter-segment revenue

    (265     (287,187     (118,731     (1,101     (407,284
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total revenues

  $ 1,237,300      $ 103,298      $ 65,181      $ 9,434      $ 1,415,213   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Income (loss) from operations(1)

  $ 521,117      $ 10,341      $ (12,975   $ (89,470   $ 429,013   

Interest income (expense), net

    509        (95     (611     (237,135     (237,332

Loss on extinguishment of debt

    —          —          —          (38,232     (38,232

Other income (expense), net

    3,601        —          (485     6        3,122   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Income (loss) before income taxes

  $ 525,227      $ 10,246      $ (14,071   $ (364,831   $ 156,571   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Capital expenditures(2)

  $ 1,714,222      $ 25,674      $ 38,514      $ 54,615      $ 1,833,025   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Depreciation, depletion and amortization

  $ 328,753      $ 32,582      $ 4,650      $ 14,259      $ 380,244   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

 

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Table of Contents
    Exploration  and
Production
    Drilling and Oil
Field Services
    Midstream  Gas
Services
    All Other     Consolidated
Total
 

Year Ended December 31, 2010

         

Revenues

  $ 779,450      $ 265,262      $ 275,071      $ 35,285      $ 1,355,068   

Inter-segment revenue

    (259     (236,687     (176,549     (9,837     (423,332
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total revenues

  $ 779,191      $ 28,575      $ 98,522      $ 25,448      $ 931,736   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Income (loss) from operations(1)

  $ 88,390      $ (9,970   $ 3,959      $ (89,165   $ (6,786

Interest income (expense), net

    496        (920     (649     (246,369     (247,442

Other income, net

    1,251        —          625        682        2,558   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Income (loss) before income taxes

  $ 90,137      $ (10,890   $ 3,935      $ (334,852   $ (251,670
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Capital expenditures(2)

  $ 1,027,933      $ 31,658      $ 48,401      $ 21,661      $ 1,129,653   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Depreciation, depletion and amortization

  $ 278,110      $ 30,031      $ 4,030      $ 13,940      $ 326,111   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Year Ended December 31, 2009

         

Revenues

  $ 457,397      $ 225,227      $ 299,580      $ 30,654      $ 1,012,858   

Inter-segment revenue

    (261     (201,641     (215,667     (4,245     (421,814
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total revenues

  $ 457,136      $ 23,586      $ 83,913      $ 26,409      $ 591,044   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Loss from operations(1)

  $ (1,487,914   $ (15,166   $ (36,989   $ (64,955   $ (1,605,024

Interest income (expense), net

    1,121        (2,074     (1,246     (183,117     (185,316

Other income, net

    4,673        —          3,365        254        8,292   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Loss before income taxes

  $ (1,482,120   $ (17,240   $ (34,870   $ (247,818   $ (1,782,048
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Capital expenditures(2)

  $ 555,809      $ 4,090      $ 52,425      $ 32,818      $ 645,142   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Depreciation, depletion and amortization

  $ 178,783      $ 28,221      $ 5,496      $ 14,392      $ 226,892   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

 

(1)

Exploration and production segment income (loss) from operations includes net (gains) losses of ($44.1) million, $50.9 million and ($147.5) million on commodity derivative contracts for the years ended December 31, 2011, 2010 and 2009, respectively. The loss from operations for the exploration and production segment for the year ended December 31, 2009 includes a non-cash full cost ceiling impairment of $1,693.3 million on the Company’s oil and natural gas properties. The loss from operations for the midstream gas services segment for the year ended December 31, 2009 includes a $26.1 million loss on the sale of gathering and compression assets in the Piñon Field.

(2)

On an accrual basis and excluding acquisitions.

Exploration and Production Segment

The Company currently generates the majority of its consolidated revenues and cash flow from the production and sale of oil and natural gas. The Company’s revenues, profitability and future growth depend substantially on prevailing prices for oil and natural gas and on the Company’s ability to find and economically develop and produce oil and natural gas reserves. Prices for oil and natural gas fluctuate widely. In order to reduce the Company’s exposure to these fluctuations, the Company enters into commodity derivative contracts for a portion of its anticipated future oil and natural gas production. Reducing the Company’s exposure to price volatility helps ensure that it has adequate funds available for its capital expenditure programs.

 

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The primary factors affecting the financial results of the Company’s exploration and production segment are the prices the Company receives for its oil and natural gas production, the quantity of oil and natural gas it produces and changes in the fair value of commodity derivative contracts. Annual comparisons of production and price data are presented in the tables below. Changes in the Company’s results for these periods reflect the strategic movement toward increased oil production in 2010 and 2011, including the acquisition of oil and natural gas properties from Forest in December 2009 and Arena in July 2010, which increased oil production volumes and revenues attributable to the Company’s exploration and production segment.

 

     Year Ended
December 31,
     Change  
     2011      2010      Amount     Percent  

Production data

          

Oil (MBbls)(1)

     11,830         7,386         4,444        60.2

Natural gas (MMcf)

     69,306         76,226         (6,920     (9.1 )% 

Total volumes (MBoe)

     23,381         20,090         3,291        16.4

Average daily total volumes (MBoe/d)

     64.1         55.0         9.1        16.5

Average prices—as reported(2)

          

Oil (per Bbl)(1)

   $ 83.21       $ 66.89       $ 16.32        24.4

Natural gas (per Mcf)

   $ 3.50       $ 3.68       $ (0.18     (4.9 )% 

Total (per Boe)

   $ 52.47       $ 38.56       $ 13.91        36.1

Average prices—including impact of derivative contract settlements

          

Oil (per Bbl)(1)

   $ 76.41       $ 68.15       $ 8.26        12.1

Natural gas (per Mcf)

   $ 3.27       $ 6.20       $ (2.93     (47.3 )% 

Total (per Boe)

   $ 48.35       $ 48.58       $ (0.23     (0.5 )% 

 

     Year Ended
December 31,
     Change  
     2010      2009      Amount     Percent  

Production data

          

Oil (MBbls)(1)

     7,386         2,894         4,492        155.2

Natural gas (MMcf)

     76,226         87,461         (11,235     (12.8 )% 

Total volumes (MBoe)

     20,090         17,471         2,619        15.0

Average daily total volumes (MBoe/d)

     55.0         47.9         7.1        14.8

Average prices —as reported(2)

          

Oil (per Bbl)(1)

   $ 66.89       $ 55.62       $ 11.27        20.3

Natural gas (per Mcf)

   $ 3.68       $ 3.36       $ 0.32        9.5

Total (per Boe)

   $ 38.56       $ 26.03       $ 12.53        48.1

Average prices—including impact of derivative contract settlements

          

Oil (per Bbl)(1)

   $ 68.15       $ 59.69       $ 8.46        14.2

Natural gas (per Mcf)

   $ 6.20       $ 7.20       $ (1.00     (13.9 )% 

Total (per Boe)

   $ 48.58       $ 45.95       $ 2.63        5.7

 

(1)

Includes natural gas liquids.

(2)

Prices represent actual average prices for the periods presented and do not include impact of derivative transactions.

For a discussion of reserves, PV-10 and reconciliation to Standardized Measure, see “Business—The Company’s Business Segments and Primary Operations—Proved Reserves” in Item 1 of this report.

Exploration and Production Segment—Year Ended December 31, 2011 Compared to Year Ended December 31, 2010

Exploration and production segment revenues increased $458.1 million, or 58.8%, to $1.2 billion in the year ended December 31, 2011 from 2010, as a result of a 60.2% increase in oil production and a 24.4% increase in

 

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the average price received for oil production. These increases were slightly offset by a 9.1% decrease in natural gas production and a 4.9% decrease in the average price received for natural gas production. The increase in oil production was due to the inclusion of a full year of production from the Permian Basin properties acquired in the Arena Acquisition in July 2010, and the continued focus on increased oil drilling throughout 2010 and 2011. During 2011, the Company completed and commenced production on 943 gross (892 net) wells, substantially all of which were located in the Mid-Continent and Permian Basin. Properties acquired from Arena produced 4,132 MBbls of oil, including production from additional wells drilled on the acquired properties, for the year ended December 31, 2011 compared to 1,548 MBbls in the 2010 period after the acquisition. The decrease in natural gas production was a result of natural production declines in existing natural gas wells.

The average price received for the Company’s oil production increased 24.4%, or $16.32 per barrel, to $83.21 per barrel during the year ended December 31, 2011 from $66.89 per barrel during 2010. The average price received for the Company’s natural gas production for the year ended December 31, 2011 decreased 4.9%, or $0.18 per Mcf, to $3.50 per Mcf from $3.68 per Mcf in 2010.

Due to the long-term nature of the Company’s investment in the development of its properties, the Company enters into oil and natural gas swaps and collars for a portion of its production in order to stabilize future cash inflows for planning purposes. The Company’s derivative contracts are not designated as accounting hedges and, as a result, realized and unrealized gains or losses on commodity derivative contracts are recorded as a component of operating expenses. Internally, management views the settlement of such derivative contracts as adjustments to the price received for oil and natural gas production to determine “effective prices.” Realized gains or losses from the settlement of derivative contracts with contractual maturities outside of the reporting period are not considered in the calculation of effective prices. The effective price received for oil for the year ended December 31, 2011 was $76.41 per Bbl compared to $68.15 per Bbl during 2010. The effective price received for natural gas for the year ended December 31, 2011 was $3.27 per Mcf compared to $6.20 per Mcf during 2010. This decrease in the effective price received for natural gas is primarily due to not having natural gas fixed price swap contracts in place for a majority of natural gas production in 2011.

During the year ended December 31, 2011, the exploration and production segment reported a $44.1 million net gain on its commodity derivative positions ($50.7 million realized loss and $94.8 million unrealized gain) compared to a $50.9 million net loss on its commodity derivative positions ($224.3 million realized gain and $275.2 million unrealized loss) in 2010. The realized loss for the year ended December 31, 2011 was primarily due to higher oil prices at the time of settlement compared to the contract price on the Company’s oil price swaps. Net realized gains totaling $48.1 million ($111.0 million realized gains and $62.9 million realized losses) resulting from settlements of commodity derivative contracts with original contractual maturities after the quarterly period in which they were settled (“out-of-period settlements”) were included in the net realized loss for the year ended December 31, 2011. The realized gain for the year ended December 31, 2010 was primarily due to lower natural gas prices at the time of settlement compared to the contract price on the Company’s natural gas price swaps. Realized gains totaling $114.4 million resulting from out-of-period settlements were included in the realized gain for the year ended December 31, 2010. Unrealized gains or losses on derivative contracts represent the change in fair value of open derivative contracts during the period. The unrealized gain on the Company’s commodity derivative contracts recorded during the year ended December 31, 2011 was primarily attributable to existing contract prices on the Company’s oil price swaps exceeding average oil market prices as of December 31, 2011. The unrealized loss on commodity contracts recorded during the year ended December 31, 2010 was attributable to an increase in average oil prices and decreases in the price differentials on the Company’s natural gas basis swaps at December 31, 2010 compared to the average oil prices and price differentials at December 31, 2009 or the contract price for contracts entered into during 2010.

For the year ended December 31, 2011, the Company had income from operations of $521.1 million in its exploration and production segment compared to $88.4 million in 2010. An increase of $452.0 million in oil and natural gas revenues was slightly offset by increases of $85.0 million in production expense, $16.9 million in production taxes and $51.3 million in depreciation and depletion on oil and natural gas properties during the year

 

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ended December 31, 2011. Additionally, the Company recorded a $44.1 million net gain on its commodity derivative contracts for the year ended December 31, 2011 compared to a $50.9 million net loss in 2010. See further discussion of these changes under “Consolidated Results of Operations” below.

Exploration and Production Segment—Year Ended December 31, 2010 Compared to Year Ended December 31, 2009

Exploration and production segment revenues increased $322.1 million, or 70.5%, to $779.2 million in the year ended December 31, 2010 from $457.1 million in 2009, primarily as a result of the 155.2% increase in oil production, slightly offset by the 12.8% decrease in natural gas production volumes. Also contributing to the increase was a 48.1% increase in the combined average price the Company received on its oil and natural gas production. In the year ended December 31, 2010, oil production increased by 4,492 MBbls to 7,386 MBbls. The increase in oil production was due to the addition of Permian Basin properties acquired from Forest and Arena, and a focus on increased oil drilling in 2010. The Company produced 3,774 MBbls of oil for the year ended December 31, 2010 from the properties acquired from Forest and Arena. The 11.2 Bcf decrease in natural gas production was a result of the decline in the number of rigs drilling for natural gas during 2010 due to depressed natural gas prices and the Company’s strategic shift to increased oil drilling.

The average price received for the Company’s oil production increased 20.3%, or $11.27 per barrel, to $66.89 per barrel during the year ended December 31, 2010 from $55.62 per barrel in 2009. The average price the Company received for its natural gas production for the year ended December 31, 2010 increased 9.5%, or $0.32 per Mcf, to $3.68 per Mcf from $3.36 per Mcf in 2009. Including the impact of derivative contract settlements, the effective price received for oil for the year ended December 31, 2010 was $68.15 per Bbl compared to $59.69 per Bbl in 2009. Including the impact of derivative contract settlements, the effective price received for natural gas for the year ended December 31, 2010 was $6.20 per Mcf compared to $7.20 per Mcf in 2009.

During the year ended December 31, 2010, the exploration and production segment reported a $50.9 million net loss on its commodity derivative positions ($224.3 million realized gain and $275.2 million unrealized loss) compared to a $147.5 million net gain on its commodity derivative positions ($348.0 million realized gain and $200.5 million unrealized loss) in 2009. The realized gain of $224.3 million for the year ended December 31, 2010 was primarily due to lower natural gas prices at the time of settlement compared to the contract price. Realized gains totaling $114.4 million resulting from out-of-period settlements were included in the realized gain for the year ended December 31, 2010. The unrealized loss on the Company’s commodity contracts recorded during the year ended December 31, 2010 was primarily attributable to an increase in average oil prices at December 31, 2010 compared to the average oil prices at December 31, 2009 or the contract price for contracts entered into during 2010 and the settlement of natural gas price swaps during the year ended December 31, 2010. The unrealized loss for the year ended December 31, 2009 was attributable to increased average oil and natural gas prices and decreases in the price differentials on the Company’s basis swaps at December 31, 2009.

For the year ended December 31, 2010, the Company had income from operations of $88.4 million in its exploration and production segment compared to a loss from operations of $1,487.9 million in 2009. The $320.1 million increase in oil and natural gas revenues and the absence of a full cost pool ceiling impairment were partially offset by the $50.9 million net loss on commodity derivative contracts, a $68.0 million increase in production expenses, a $25.2 million increase in production taxes and a $99.3 million increase in depreciation and depletion on oil and natural gas properties. See discussion of production expense, production taxes and depreciation and depletion under “Consolidated Results of Operations” below.

Drilling and Oil Field Services Segment

The financial results of the Company’s drilling and oil field services segment depend primarily on demand and prices that can be charged for its services. On a consolidated basis, drilling and oil field service revenues earned and expenses incurred in performing services for third parties, including third-party working interests in

 

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wells the Company operates, are included in drilling and services revenues and expenses. Drilling and oil field service revenues earned and expenses incurred in performing services for the Company’s own account are eliminated in consolidation.

As of December 31, 2011, the Company owned 31 drilling rigs, through Lariat. The table below presents a summary of the Company’s rigs for each of the years ended December 31, 2011, 2010 and 2009:

 

     December 31,  
Rigs    2011      2010      2009  

Working for SandRidge

     20         20         14   

Working for third parties

     10         9         2   

Idle

     —           2         14   
  

 

 

    

 

 

    

 

 

 

Total operational

     30         31         30   

Non-operational(1)

     1         —           1   
  

 

 

    

 

 

    

 

 

 

Total rigs

     31         31         31   
  

 

 

    

 

 

    

 

 

 

 

(1)

Includes a rig stacked at December 31, 2011 and a rig being serviced at December 31, 2009.

The table below presents certain information concerning the Company’s rigs and contract drilling operations:

 

    Year Ended December 31,  
    2011     2010     2009  

Average number of operational rigs owned during the period

    30.8        27.5        30.0   

Average drilling revenue per day per rig working for third parties(1)

  $ 15,215      $ 14,287      $ 11,398   

 

(1)

Represents revenues from the Company’s rigs working for third parties divided by the total number of days such drilling rigs were used by third parties during the period, excluding revenues for related rental equipment.

Until April 15, 2009, the Company indirectly owned, through Lariat and its partner Clayton Williams Energy, Inc. (“CWEI”), an additional 11 operational rigs through an investment in Larclay L.P. (“Larclay”). Although the Company’s ownership in Larclay afforded it access to Larclay’s rigs, it did not control Larclay, and, therefore, did not consolidate the results of its operations with the Company’s. On April 15, 2009, Lariat completed an assignment to CWEI of Lariat’s 50% equity interest in Larclay pursuant to the terms of an Assignment and Assumption Agreement (the “Larclay Assignment”) entered into between Lariat and CWEI. Pursuant to the Larclay Assignment, Lariat assigned all of its right, title and interest in and to Larclay to CWEI effective April 15, 2009, and CWEI assumed all of the obligations and liabilities of Lariat relating to Larclay. As the Company had fully impaired its investment in and notes receivable due from Larclay at December 31, 2008, there were no additional losses on Larclay during the year ended December 31, 2009 or as a result of the Larclay Assignment.

Drilling and Oil Field Services Segment—Year Ended December 31, 2011 Compared to Year Ended December 31, 2010

Drilling and oil field services segment revenues increased $74.7 million to $103.3 million in the year ended December 31, 2011 from the year ended December 31, 2010 and drilling and oil field services segment expenses increased $54.4 million during the same period to $93.0 million. The increase in revenues and expenses was primarily attributable to an increase in the number of rigs working for third parties and an increase in oil field services performed for third parties during 2011. During 2011, an average of ten rigs were working for third parties compared to an average of four rigs working for third parties during 2010. Additionally, the average daily rate received per rig working for third parties increased to $15,215 during 2011 compared to $14,287 during 2010. The increases in rigs working for third parties and the average daily rate received from third parties resulted in income from operations of $10.3 million in the year ended December 31, 2011 compared to a loss from operations of $10.0 million in 2010.

 

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Drilling and Oil Field Services Segment—Year Ended December 31, 2010 Compared to Year Ended December 31, 2009

Drilling and oil field services segment revenues increased to $28.6 million in the year ended December 31, 2010 from $23.6 million in the year ended December 31, 2009 and drilling and oil field services segment expenses decreased $0.2 million to $38.5 million during the same period. The increase in revenues was primarily attributable to an increase in the number of rigs working for third parties during 2010. During 2010, an average of four rigs were working for third parties compared to an average of one rig working for third parties during 2009. Additionally, the average daily rate received per rig working for third parties increased to $14,287 during 2010 compared to $11,398 during 2009. Reduced, or stand-by, rates received on two of the Company’s rigs during 2009 resulted in a lower average rate per rig per working day in 2009. During 2010, none of the Company’s rigs received stand-by rates. The increase in the number of rigs working for third parties and the average daily rate received from third parties resulted in a reduced loss from operations of $10.0 million in the year ended December 31, 2010 compared to $15.2 million in 2009.

Midstream Gas Services Segment

Midstream gas services segment revenues consist mostly of revenue from gas marketing, which is a very low-margin business. Midstream gas services are primarily undertaken to realize incremental margins on natural gas purchased at the wellhead, and provide value-added services to customers. On a consolidated basis, midstream and marketing revenues represent natural gas sold on behalf of third parties and the fees the Company charges to gather, compress and treat this natural gas. Gas marketing operating costs represent payments made to third parties for the proceeds from the sale of natural gas owned by such parties, net of any applicable margin and actual costs the Company charges to gather, compress and treat the natural gas. In general, natural gas purchased and sold by the Company’s midstream gas business is priced at a published daily or monthly index price. The primary factors affecting the results of the Company’s midstream gas services segment are the quantity of natural gas the Company gathers, treats and markets and the prices it pays and receives for natural gas.

In June 2009, the Company completed the sale of its gathering and compression assets located in the Piñon Field. Net proceeds from the sale were approximately $197.5 million, which resulted in a loss on the sale of $26.1 million. In conjunction with the sale, the Company entered into a gas gathering agreement and an operations and maintenance agreement. Under the gas gathering agreement, the Company has dedicated its Piñon Field acreage for priority gathering services through June 30, 2029 and will pay a fee for such services that was negotiated at arms’ length. Pursuant to the operations and maintenance agreement, the Company will operate and maintain the gathering system assets sold through June 30, 2029 unless the Company or the buyer of the assets chooses to terminate the agreement.

Grey Ranch Plant, L.P. (“GRLP”) is a limited partnership that operates the Company’s Grey Ranch plant located in Pecos County, Texas. The Company purchased its 50% interest in GRLP during 2003. During October 2009, the Company executed amendments to certain agreements related to the ownership and operation of GRLP. As a result of these amendments, the Company became the primary beneficiary of GRLP and began consolidating the activity of GRLP in its midstream gas services segment prospectively beginning on October 1, 2009, the effective date of the amendments.

Midstream Gas Services Segment—Year Ended December 31, 2011 Compared to Year Ended December 31, 2010

Midstream gas services segment revenues for the year ended December 31, 2011 were $65.2 million compared to $98.5 million in 2010. The decrease in revenue was due to a decrease in third-party volumes the Company marketed of approximately 5.5 Bcf, a decrease in natural gas prices and a decrease in natural gas volumes processed in the Company’s gas treating plants. The decrease in revenue and a $2.8 million impairment on certain midstream assets resulted in a loss from operations of $13.0 million for the year ended December 31, 2011 compared to income from operations of $4.0 million in 2010.

 

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Midstream Gas Services Segment—Year Ended December 31, 2010 Compared to Year Ended December 31, 2009

Midstream gas services segment revenues for the year ended December 31, 2010 were $98.5 million compared to $83.9 million in the same period in 2009. Income from operations was $4.0 million for the year ended December 31, 2010 compared to a loss from operations of $37.0 million in 2009. An increase in natural gas prices for third-party volumes the Company marketed in the year ended December 31, 2010 compared to 2009 contributed to the increase in revenues. The consolidation of GRLP activity into the midstream gas services segment for the year ended December 31, 2010 also contributed to the increase in midstream gas services segment revenues and to the increase in income from operations. Prior to October 1, 2009 when the Company began consolidating GRLP, its share of GRLP activity was reported as income from equity investments. The 2010 increase in income from operations was primarily due to the inclusion of a $26.1 million loss on the sale of the Company’s gathering and compression assets and a $10.0 million impairment on its spare parts inventory in the year ended December 31, 2009.

Consolidated Results of Operations

Year Ended December 31, 2011 Compared to the Year Ended December 31, 2010

Revenues. Total revenues increased 51.9% for the year ended December 31, 2011 compared to 2010 primarily due to the increase in oil and natural gas sales and an increase in drilling and services revenue.

 

     Year Ended December 31,               
     2011      2010      $ Change     % Change  
     (In thousands)  

Revenues

          

Oil and natural gas

   $ 1,226,794       $ 774,763       $ 452,031        58.3

Drilling and services

     103,298         28,543         74,755        261.9

Midstream and marketing

     66,690         100,118         (33,428     (33.4 )% 

Other

     18,431         28,312         (9,881     (34.9 )% 
  

 

 

    

 

 

    

 

 

   

Total revenues

   $ 1,415,213       $ 931,736       $ 483,477        51.9
  

 

 

    

 

 

    

 

 

   

Total oil and natural gas revenues increased $452.0 million for the year ended December 31, 2011 compared to 2010, as a result of an increase in the amount of oil produced and the average price received for oil production, offset slightly by a decrease in the amount of natural gas produced and the average prices received for natural gas production. The 4,444 MBbl, or 60.2%, increase in oil production was due primarily to the 2,584 MBbl increase in production from properties acquired from Arena due to the inclusion of a full year of production and continued development of the Arena properties. During 2011, the Company completed and commenced production on a total of 943 gross (892 net) wells, including wells drilled on properties acquired from Arena. The average price received for oil production, excluding the impact of derivative contracts, increased 24.4% in the 2011 period to $83.21 per Bbl compared to $66.89 per Bbl in 2010.

Drilling and services revenues increased $74.8 million for the year ended December 31, 2011 compared to 2010 due to an increase in the average number of rigs and the average daily rate received per rig working for third parties and an increase in oil field services work performed for third parties. During the year ended December 31, 2011, the Company had an average of ten rigs working for third parties compared to an average of four rigs working for third parties in 2010. These rigs earned an average of $15,215 per day during 2011 compared to an average of $14,287 per day in 2010.

Midstream and marketing revenues decreased $33.4 million, or 33.4%, in the year ended December 31, 2011 compared to the year ended December 31, 2010. The decrease was attributable to a decrease in third-party volumes the Company marketed due to decreased natural gas production, a decrease in natural gas prices and a decrease in natural gas volumes processed at the Company’s gas treating plants for the year ended December 31, 2011 compared to 2010.

 

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Other revenues decreased $9.9 million for the year ended December 31, 2011 from 2010. The decrease was due to lower CO2 volumes sold to third parties from the Company’s gas treating plants during the year ended December 31, 2011 compared to 2010 as a result of a decrease in natural gas production and natural gas volumes processed at the Company’s gas treating plants.

Expenses. Total expenses increased $47.7 million or 5.1% for the year ended December 31, 2011 from 2010 primarily due to increases in production expense, drilling and services expense and depreciation and depletion on oil and natural gas properties, which were partially offset by a decrease in general and administrative expenses. Additionally, the Company recognized a gain on derivative contracts during 2011 compared to a loss during 2010.

 

     Year Ended December 31,               
     2011     2010      $ Change     % Change  
     (In thousands)  

Expenses

         

Production

   $ 322,877      $ 237,863       $ 85,014        35.7

Production taxes

     46,069        29,170         16,899        57.9

Drilling and services

     65,654        22,368         43,286        193.5

Midstream and marketing

     66,007        90,149         (24,142     (26.8 )% 

Depreciation and depletion—oil and natural gas

     326,614        275,335         51,279        18.6

Depreciation and amortization—other

     53,630        50,776         2,854        5.6

Impairment

     2,825        —           2,825        100.0

General and administrative

     148,643        179,565         (30,922     (17.2 )% 

(Gain) loss on derivative contracts

     (44,075     50,872         (94,947     (186.6 )% 

(Gain) loss on sale of assets

     (2,044     2,424         (4,468     (184.3 )% 
  

 

 

   

 

 

    

 

 

   

Total expenses

   $ 986,200      $ 938,522       $ 47,678        5.1
  

 

 

   

 

 

    

 

 

   

Production expense includes the costs associated with the Company’s exploration and production activities, including, but not limited to, lease operating expense and treating costs. Production expenses increased $85.0 million primarily due to operating expenses associated with properties acquired from Arena and additional oil wells that began producing during late 2010 and in 2011. Higher production costs were incurred on oil production compared to production costs on natural gas volumes. Total production increased 16.4% with oil production increasing 60.2% for the year ended December 31, 2011 compared to 2010.

Production taxes increased $16.9 million, or 57.9%, due to increased oil production, including production from properties acquired from Arena and newly producing wells, in the year ended December 31, 2011 compared to 2010.

Drilling and services expenses, which include operating expenses attributable to the drilling and oil field services segment and the Company’s CO2 services companies, increased $43.3 million, or 193.5%, for the year ended December 31, 2011 compared to 2010 primarily due to an increase in the average number of rigs working for third parties and an increase in oil field services work performed for third parties.

Midstream and marketing expenses decreased $24.1 million, or 26.8%, due to decreased natural gas volumes purchased from third parties as a result of decreased natural gas production and a decrease in volumes processed at the Company’s treating plants during the year ended December 31, 2011.

Depreciation and depletion for the Company’s oil and natural gas properties increased $51.3 million for the year ended December 31, 2011 from the same period in 2010. The increase was due to an increase of 16.4% in the Company’s combined production volume as well as an increase in the depreciation and depletion per Boe to $13.97 in 2011 from $13.70 per Boe in 2010 that resulted from the sale of oil and natural gas properties in 2011.

 

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In 2011, the Company recorded an impairment of $2.8 million on certain midstream compressor assets as their future use was limited.

General and administrative expenses decreased $30.9 million, or 17.2%, to $148.6 million for the year ended December 31, 2011 from 2010. General and administrative expenses for 2010 included $17.0 million of fees incurred related to the Arena Acquisition and $18.2 million for the settlement of a dispute with certain working interest owners. The decrease in 2011 expense resulting from the absence of such costs was slightly offset by an increase in payroll expenses in the year ended December 31, 2011 due to an increase in the number of Company employees, and fees associated with the Mississippian Trust I and Permian Trust initial public offerings.

The Company recorded a net gain of $44.1 million ($50.7 million realized loss and $94.8 million unrealized gain) on its commodity derivative contracts for the year ended December 31, 2011 compared to a net loss of $50.9 million ($224.3 million realized gain and $275.2 million unrealized loss) in 2010. See further discussion of gains and losses on commodity derivative contracts under “Results by Segment—Exploration and Production Segment.”

Other Income (Expense), Taxes and Net Income Attributable to Noncontrolling Interest. Changes in other income (expense), taxes and net income attributable to noncontrolling interest are reflected in the table below.

 

     Year Ended December 31,              
     2011     2010     $ Change     % Change  
     (In thousands)  

Other income (expense)

        

Interest income

   $ 240      $ 296      $ (56     (18.9 )% 

Interest expense

     (237,572     (247,738     10,166        (4.1 )% 

Loss on extinguishment of debt

     (38,232     —          (38,232     (100.0 )% 

Other income, net

     3,122        2,558        564        22.0
  

 

 

   

 

 

   

 

 

   

Total other expense

     (272,442     (244,884     (27,558     11.3
  

 

 

   

 

 

   

 

 

   

Income (loss) before income taxes

     156,571        (251,670     408,241        (162.2 )% 

Income tax benefit

     (5,817     (446,680     440,863        (98.7 )% 
  

 

 

   

 

 

   

 

 

   

Net income

     162,388        195,010        (32,622     (16.7 )% 

Less: net income attributable to noncontrolling interest

     54,323        4,445        49,878        1,122.1
  

 

 

   

 

 

   

 

 

   

Net income attributable to SandRidge Energy, Inc.

   $ 108,065      $ 190,565      $ (82,500     (43.3 )% 
  

 

 

   

 

 

   

 

 

   

Interest expense decreased $10.2 million for the year ended December 31, 2011 compared to 2010, primarily due to a $13.4 million decrease in the net loss on the Company’s interest rate swap. Additional decreases in interest expense on the senior credit facility, due to lower average outstanding balances in 2011, and 8.625% Senior Notes, due to the purchase and redemption of these notes, for the year ended December 31, 2011, were partially offset by interest expense on the Company’s 7.5% Senior Notes issued in March 2011.

In connection with the tender offer to purchase and the redemption of the 8.625% Senior Notes, the Company recognized a loss on extinguishment of debt of $38.2 million for the year ended December 31, 2011. The loss represents the premium paid to purchase and redeem these notes and the unamortized debt issuance costs associated with the notes.

In the second quarter of 2011, the Company completed its valuation of assets acquired and liabilities assumed related to the Arena Acquisition in order to finalize the purchase price allocation. In connection

 

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therewith, the Company recorded an additional net deferred tax liability of $7.0 million associated with the Arena Acquisition. Management determined that it is more likely than not that the Company will now realize a benefit from more of its existing deferred tax assets as the additional Arena deferred tax liabilities are available to offset the reversal of the Company’s deferred tax assets. As a result of recording an additional net deferred tax liability, the Company released a corresponding portion of its previously recorded valuation allowance resulting in a deferred tax benefit. In the third quarter of 2011, the Company filed the final income tax returns for Arena and its subsidiaries resulting in a current tax provision of $0.7 million. The $5.8 million net tax benefit for the year ended December 31, 2011 is primarily comprised of the benefit associated with the partial release of the Company’s previously recorded valuation allowance against its net deferred tax asset and the filing of the final income tax returns for Arena and its subsidiaries. The Company reported an income tax benefit of $446.7 million for the year ended December 31, 2010. The income tax benefit was primarily attributable to the release of a portion of the Company’s valuation allowance against its net deferred tax asset after the Company recorded net deferred tax liabilities related to the Arena Acquisition in July 2010.

Net income attributable to noncontrolling interest increased to $54.3 million for the year ended December 31, 2011 compared to $4.4 million for the same period in 2010 due to the completion of the Mississippian Trust I’s initial public offering in April 2011 and the Permian Trust’s initial public offering in August 2011, as it reflects the portion of net income attributable to beneficial interests of the trusts held by third parties.

Year Ended December 31, 2010 Compared to the Year Ended December 31, 2009

Revenues. Total revenues increased 57.6% to $931.7 million for the year ended December 31, 2010 from $591.0 million in 2009. This increase is primarily due to the increase in oil and natural gas sales that resulted from increased oil production and increased prices received on the Company’s oil and natural gas production.

 

     Year Ended December 31,                
     2010      2009      $ Change      % Change  
     (In thousands)  

Revenues

           

Oil and natural gas

   $ 774,763       $ 454,705       $ 320,058         70.4

Drilling and services

     28,543         23,586         4,957         21.0

Midstream and marketing

     100,118         86,028         14,090         16.4

Other

     28,312         26,725         1,587         5.9
  

 

 

    

 

 

    

 

 

    

Total revenues

   $ 931,736       $ 591,044       $ 340,692         57.6
  

 

 

    

 

 

    

 

 

    

Total oil and natural gas revenues increased $320.1 million for the year ended December 31, 2010 compared to 2009, primarily as a result of increased oil production, offset slightly by decreased natural gas production, and increased prices received for the Company’s oil and natural gas production. The increase in oil production was primarily due to the addition of properties acquired from Forest in late 2009 and Arena in mid-2010 and a focus on increased oil drilling in 2010. The average price received for oil production, excluding the impact of derivative contracts, increased 20.3% in 2010 to $66.89 per Bbl from $55.62 in 2009. The average price received for natural gas production, excluding the impact of derivative contracts, increased 9.5% in 2010 to $3.68 per Mcf from $3.36 in 2009.

Drilling and services revenues increased 21.0% for the year ended December 31, 2010 compared to 2009. The increase was due to an increase in the number of rigs drilling for third parties and an increase in the average revenue per rig per day.

Midstream and marketing revenues increased $14.1 million, or 16.4%, for the year ended December 31, 2010 compared to 2009. The increase in revenues was primarily attributable to the inclusion of GRLP activity for the year ended December 31, 2010 and an increase in the price of natural gas marketed for third parties.

 

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Operating Costs and Expenses. Total operating costs and expenses decreased to $938.5 million during 2010, compared to $2,196.1 million in 2009, primarily due to the absence of a full cost ceiling impairment during 2010. The absence of a ceiling impairment was partially offset by increases in production expense, production taxes, midstream and marketing expense, depreciation and depletion on oil and natural gas properties, general and administrative expense and the loss on derivative contracts.

 

     Year Ended December 31,              
     2010      2009     $ Change     % Change  
     (In thousands)  

Operating costs and expenses

         

Production

   $ 237,863       $ 169,880      $ 67,983        40.0

Production taxes

     29,170         4,010        25,160        627.4

Drilling and services

     22,368         28,380        (6,012     (21.2 )% 

Midstream and marketing

     90,149         80,608        9,541        11.8

Depreciation and depletion—oil and natural gas

     275,335         176,027        99,308        56.4

Depreciation and amortization—other

     50,776         50,865        (89     (0.2 )% 

Impairment

     —           1,707,150        (1,707,150     (100.0 )% 

General and administrative

     179,565         100,256        79,309        79.1

Loss (gain) on derivative contracts

     50,872         (147,527     198,399        (134.5 )% 

Loss on sale of assets

     2,424         26,419        (23,995     (90.8 )% 
  

 

 

    

 

 

   

 

 

   

Total operating costs and expenses

   $ 938,522       $ 2,196,068      $ (1,257,546