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SandRidge Energy 10-K 2009
e10vk
Table of Contents

 
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
 
 
 
 
 
 
 
 
     
(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, 2008
OR
o
  TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
    For the transition period from          to          
 
Commission File Number: 1-33784
 
 
 
 
 
 
 
 
     
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
(Address of principal executive offices)
  73102
(Zip Code)
 
(405) 429-5500
 
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 o     No þ
 
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.  Yes o     No 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 o
 
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.  o
 
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 o   Non-accelerated filer o   Smaller reporting company o
        (Do not check if a smaller reporting company)    
 
Indicate by check mark whether the registrant is a shell company (as defined in Exchange Act Rule 12b-2).  Yes o     No þ
 
The aggregate market value of our common stock held by non-affiliates on June 30, 2008 was approximately $8.0 billion based on the closing price as quoted on the New York Stock Exchange. As of February 20, 2009, there were 167,625,519 shares of our common stock outstanding.
 
 
Portions of the proxy statement for the 2009 Annual Meeting of Shareholders are incorporated by reference in Part III.
 


 

 
SANDRIDGE ENERGY, INC.
 
2008 ANNUAL REPORT ON FORM 10-K
 
 
                 
Item
      Page
 
 
1.
    Business     3  
 
1A.
    Risk Factors     25  
 
1B.
    Unresolved Staff Comments     35  
 
2.
    Properties     35  
 
3.
    Legal Proceedings     35  
 
4.
    Submission of Matters to a Vote of Security Holders     35  
 
PART II
 
5.
    Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities     36  
 
6.
    Selected Financial Data     37  
 
7.
    Management’s Discussion and Analysis of Financial Condition and Results of Operations     38  
 
7A.
    Quantitative and Qualitative Disclosures about Market Risk     62  
 
8.
    Financial Statements and Supplementary Data     65  
 
9.
    Changes in and Disagreements with Accountants on Accounting and Financial Disclosure     65  
 
9A.
    Controls and Procedures     65  
 
9B.
    Other Information     65  
 
PART III
 
10.
    Directors, Executive Officers and Corporate Governance     65  
 
11.
    Executive Compensation     65  
 
12.
    Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters     66  
 
13.
    Certain Relationships and Related Transactions and Director Independence     66  
 
14.
    Principal Accountant Fees and Services     66  
 
PART IV
 
15.
    Exhibits and Financial Statement Schedules     66  
 EX-4.16
 EX-10.5.8
 EX-10.7.5
 EX-23.1
 EX-23.2
 EX-23.3
 EX-31.1
 EX-31.2
 EX-32.1


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PART I
 
Item 1.   Business
 
 
SandRidge Energy, Inc. is an independent natural gas and oil company headquartered in Oklahoma City, Oklahoma concentrating on exploration, development and production activities. We are focused on the exploration and exploitation of our significant holdings in the West Texas Overthrust, which we refer to as the WTO, a natural gas prone geological region in Pecos County and Terrell County, Texas, where we have operated since 1986 and currently have 655,926 net acres under lease. The WTO includes the Piñon Field as well as the Allison Ranch, South Sabino, Thistle, Big Canyon and McKay Creek exploration areas.
 
We have assembled an extensive natural gas and crude oil property base on which we have identified approximately 7,900 potential drilling locations as of December 31, 2008, including approximately 3,100 locations in the WTO. As of December 31, 2008, our estimated proved reserves, approximately 96% of which were prepared by third party engineers, were 2,158.6 Bcfe, of which 88% were natural gas. As of December 31, 2008, we had 2,059 gross (1,515.8 net) producing wells, substantially all of which we operate, and we had natural gas and oil interests in 1,655,956 gross (1,247,664 net) leased acres. Additionally, we averaged 29 rigs drilling in the WTO, five rigs drilling in East Texas, three rigs drilling in the Mid-Continent and three rigs drilling in other areas during 2008. We had nine rigs drilling in the WTO, five rigs drilling in East Texas, one rig drilling in Oklahoma and two rigs drilling in other areas as of December 31, 2008.
 
We also operate businesses that are complementary to our primary exploration, development and production activities which provide us with operational flexibility and an advantageous cost structure. We own related gas gathering and treating facilities, a gas marketing business and an oil field services business, including our drilling rig business, Lariat Services, Inc. (“Lariat”). As of December 31, 2008, our drilling rig fleet consisted of 43 rigs — 31 rigs owned directly by us and 12 rigs owned by Larclay, L.P. (“Larclay”), a limited partnership in which we have a 50% interest. Currently, 28 of our owned rigs and 11 of the Larclay rigs are operational. We also capture and transport CO2 to the Permian Basin.
 
Our principal executive offices are located at 123 Robert S. Kerr Avenue, Oklahoma City, Oklahoma 73102 and our telephone number is (405) 429-5500. We make available free of charge on our website at www.sandridgeenergy.com our 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 we electronically file such material with, or furnish it to, the Securities and Exchange Commission (“SEC”). Any materials that we have 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 www.sec.gov.
 
References to “SandRidge,” “us,” “we,” “Company” and “our” in this report refer to SandRidge Energy, Inc. together with its subsidiaries. “SandRidge CO2” refers to our wholly owned subsidiary SandRidge CO2, LLC, and “SandRidge Tertiary” refers to our wholly owned subsidiary SandRidge Tertiary, LLC.
 
 
During the second half of 2008, unprecedented levels of volatility in the financial and commodity markets made it necessary for us to reduce and refocus our exploration and development activities, reduce our budget for capital expenditures, explore the potential sale of certain assets and seek additional capital.
 
Private Placement of Convertible Perpetual Preferred Stock.  In January 2009, we completed a private placement of 2,650,000 shares of 8.5% convertible perpetual preferred stock to qualified institutional buyers eligible under Rule 144A under the Securities Act of 1933, as amended (the “Securities Act”). The placement included 400,000 shares of convertible perpetual preferred stock issued upon the full exercise of the initial purchasers’ option to cover over-allotments. Net proceeds from the offering were approximately $243.9 million after deducting offering expenses of approximately $8.0 million. We used the net proceeds of the offering to repay outstanding borrowings under our senior credit facility and for general corporate purposes.


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Each share of the convertible perpetual preferred stock has a liquidation preference of $100 and is entitled to an annual dividend of $8.50 payable semi-annually in cash, common stock or any combination thereof, beginning on February 15, 2010. No dividends will accrue or accumulate prior to August 15, 2009. Additionally, each share is initially convertible into 12.48 shares of our common stock, at the holder’s option, at any time on or after April 15, 2009 based on an initial conversion price of $8.01 and subject to customary adjustments in certain circumstances.
 
Marketing of Midstream Assets.  In January 2009, we announced our intent to offer for sale certain of our gas gathering and related assets located in the WTO. This process is ongoing as of the date of this filing.
 
2009 Capital Expenditure Budget.  We are introducing a 2009 production guidance range of 110.0 Bcfe to 120.0 Bcfe based on a capital expenditure guidance range of $500.0 million to $700.0 million. Based on the current and anticipated near-term drilling activity and associated expenditures, it is currently expected that full year results will trend toward the lower half of these ranges.
 
Drilling Activity.  We began to decrease the number of rigs running on our properties during December 2008 in preparation for reduced 2009 activity levels. At February 20, 2009, we had 9 rigs running compared to a high of 47 rigs operating in the second quarter of 2008.
 
East Texas/North Louisiana — Haynesville Shale Play:  We control approximately 36,000 acres in the developing Haynesville shale play of East Texas and North Louisiana. We drilled two vertical test wells within the Oakhill field area in Rusk County to evaluate the potential for Haynesville shale production. The initial well had a total of 260 feet of Haynesville shale thickness and tested at a rate of 1.5 MMcfe per day. The second well encountered 288 feet of shale thickness and is awaiting completion.
 
 
Our primary objective is to achieve long-term growth and maximize stockholder value over multiple business cycles by pursuing the following strategies:
 
  •  Grow Through Exploration and Drilling and Development of Existing Acreage.  We expect to generate long-term reserve and production growth by exploring, drilling and developing our large acreage position. Our primary exploration and development focus will be in the WTO, where we owned interests in 777,475 gross (655,926 net) acres at December 31, 2008 and operated up to 35 rigs during 2008 (nine as of December 31, 2008). We have identified approximately 3,100 potential drilling locations in the WTO and believe that we will be able to expand the number of drilling locations in the WTO through exploratory drilling and use of our 3-D seismic technology.
 
  •  Apply Technological Improvements to Our Exploration and Development Program.  We use our 3-D seismic acquisition program and our enhanced interpretation technologies to achieve high drilling and exploration success rates. We strive to maximize value by minimizing time from spud to first sales with advanced drilling, completion and production methods that historically have not been widely used in the WTO.
 
  •  Seek Opportunistic Acquisitions in Our Core Geographic Areas.  Since January 2006, through acquisitions and leasing activities, we have tripled our net acreage position in the WTO. We intend to continue to seek other opportunities to optimize and enhance our exploratory acreage position in the WTO and other strategic areas.
 
  •  Reduce Costs, Enhance Returns and Maintain Operating Flexibility by Controlling Operations.  We operate 97.3% of our production in the WTO, East Texas, the Gulf Coast area and the Mid-Continent in addition to controlling our fleet of drilling rigs. We believe this allows us to better control overall costs and maintain a high degree of operating flexibility, which permits us to manage our operating costs and control capital expenditures and the timing of development and exploration activities.


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Our Businesses and Primary Operations
 
Exploration and Production
 
We explore for, develop and produce natural gas and oil reserves, with a focus on increasing our reserves and production in the WTO. We operate substantially all of our wells in the WTO. We also have significant operated leasehold positions in the Cotton Valley Trend in East Texas, the Gulf Coast area and the Mid-Continent, as well as other non-core operating areas.
 
The following table identifies certain information concerning our exploration and production business as of December 31, 2008 unless otherwise noted:
 
                                                         
    Estimated Net
                                  Number of
 
    Proved
          Daily
    Reserves/
    Proved
          Identified
 
    Reserves
    PV-10
    Production
    Production
    Gross
    Net
    Potential Drilling
 
    (Bcfe)     (in millions)(1)     (MMcfe/d)(2)     (Years)     Acreage     Acreage     Locations  
 
Area
                                                       
WTO
    1,342.6       1,223.2       173.8       21.2       777,475       655,926       3,121  
East Texas
    399.3       462.0       46.1       23.8       59,564       29,989       1,567  
Gulf Coast
    75.4       148.5       24.8       8.3       60,059       34,764       43  
Mid-Continent
    93.0       146.8       38.8       6.6       583,333       417,573       2,474  
Other:
                                                       
Gulf of Mexico
    44.5       32.8       6.9       17.6       76,559       37,434       67  
Other West Texas
    87.3       148.7       20.1       11.9       60,632       39,236       441  
Tertiary recovery- West Texas
    116.0       95.1       3.1       102.1       9,064       8,195       67  
Other
    0.5       1.4       0.1       14.3       29,270       24,547       151  
                                                         
Total
    2,158.6       2,258.5       313.7       18.9       1,655,956       1,247,664       7,931  
                                                         
 
 
(1) PV-10 generally differs from Standardized Measure of Discounted Net Cash Flows, or 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 as of December 31, 2008, see — “Proved Reserves.” Our Standardized Measure was $2.2 billion at December 31, 2008.
 
(2) Average daily net production for the month of December 2008.
 
 
We have drilled and developed natural gas in the WTO since 1986. This area is located in Pecos County and Terrell County 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 WTO was created by the collision of the ancestral North American and South American continents resulting in source rock and reservoir rock, including potential hydrocarbon traps, becoming thrusted upon one another in multiple layers (also known as imbricate stacking) along the leading edge of the WTO. The collision and thrusting resulted in the reservoir rock becoming highly fractured, increasing the likelihood of conventional natural gas and oil accumulations in the reservoir rock and creating a unique geological setting in North America. 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 this, the WTO has historically been under-explored. The high CO2 content of the natural gas, lack of infrastructure in the region, historical limitations of conventional subsurface geological and geophysical methods and commodity prices have discouraged exploration of the area. Our access to and control of the necessary infrastructure combined with application of modern seismic techniques allow us to continue to identify further exploration and development opportunities in the WTO.


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3-D Seismic Program.  In May 2007, we began a multi-year seismic program to acquire 1,500 square miles of modern 3-D seismic data in the WTO. We believe this enhanced 3-D seismic program will lower exploratory drilling risk and improve completion efficiency by identifying structural detail of potential reservoirs. With the aid of 3-D seismic data and historical well information, we believe we can high-grade our drilling locations in order to achieve low finding costs. As of December 31, 2008, we had acquired 1,292 square miles of 3-D seismic data, of which 1,050 square miles had been processed and is currently being interpreted.
 
Piñon Field.  The Piñon Field, located in Pecos County, is our most significant producing field, accounting for 62.2% of our proved reserve base as of December 31, 2008 and approximately 68% of our 2008 exploration and development expenditures (including land and seismic acquisitions). The Piñon Field lies along the leading edge of the WTO. The primary reservoirs are the Tesnus sands (depths ranging from 3,500 to 5,000 feet), the Upper Caballos chert (depths ranging from 5,000 to 8,000 feet) and the Lower Caballos chert (depths ranging from 7,000 to 10,000 feet). During 2008, we expanded the Piñon Field utilizing data from our 3-D seismic program and historical well information to identify new reservoirs in the field’s three primary thrusts (Dugout Creek, Warwick and Frog Creek). As of December 31, 2008, our estimated proved natural gas and oil reserves in the Piñon Field were 1,342.6 Bcfe, 54.8% of which were proved undeveloped reserves based on estimates prepared by Netherland, Sewell & Associates, Inc., an independent oil and gas consulting firm. Our interests in the Piñon Field as of December 31, 2008 included 660 producing wells and a 96.0% average working interest in the producing area of the Piñon Field. We were operating nine drilling rigs in the Piñon Field as of December 31, 2008 and we drilled 252 wells in this field during 2008.
 
West Texas Overthrust Prospects.  Through our regional exploratory efforts, to date we have identified five exploration areas: Allison Ranch, South Sabino, Thistle, Big Canyon and McKay Creek. 3-D seismic data has been recently acquired over these five exploration areas, which should allow us to further develop these prospective areas for future exploration.
 
West Texas Overthrust Development.  The following table provides information concerning development opportunities in the WTO:
 
                                     
Estimated
  Estimated
           
Net PUD
  Gross PUD
  Gross PUD
  Total Gross
  2008 Year
Reserves
  Reserves
  Drilling
  Drilling
  End Rigs
(Bcfe)(1)
  (Bcfe)(1)   Locations(1)   Locations(1)   Working
 
  735.5       1,024.1       744       3,121         9  
                                     
 
 
(1) As of December 31, 2008.
 
Century Plant.  In June 2008, we entered into an agreement with a subsidiary of Occidental Petroleum Corporation (“Occidental”) to construct a CO2 treating plant (the “Century Plant”) and associated compression and pipeline facilities for $800.0 million. Occidental will pay a minimum of 100% of the contract price (including any subsequent agreed-on revisions) to us through periodic cost reimbursements based upon the percentage of the project completed. The Century Plant, to be located in Pecos County, Texas, is designed to have treating capacity of 800.0 MMcf per day of natural gas and is expected to be completed in two phases with the first phase coming on line in the second quarter of 2010 and the second phase coming on line in the second quarter of 2011.
 
Upon start-up, the Century Plant will be owned and operated by Occidental. We will deliver high CO2 natural gas to the Century Plant pursuant to a 30-year treating agreement executed simultaneously with the construction agreement, and Occidental will separate and remove the CO2 from the delivered natural gas. Occidental will retain substantially all CO2 removed at the Century Plant and our other existing CO2 treating plants. We will retain all methane from the Century Plant and our other existing plants.
 
High CO2 Treating.  The most productive reservoir in the Piñon Field is the Warwick Caballos chert high CO2 reservoir. However, CO2 is a waste product and we cannot produce high CO2 gas without removing the CO2 from the gas stream. Production from this reservoir is currently limited by treating capacity at our legacy natural gas treating plants. Our current expansion of the capacity of our existing plants and the construction of the Century Plant will expand CO2 treating capacity in the area and will allow us to accelerate the development of the Warwick thrust.


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We own significant natural gas and oil interests in the natural gas bearing Cotton Valley Trend, which covers parts of East Texas and northern Louisiana. As of December 31, 2008, we held interests in 59,564 gross (29,989 net) acres in East Texas. At that time, our estimated net proved reserves in East Texas were 399.3 Bcfe, with net production of approximately 46.1 MMcfe per day for the month of December 2008. We focus our operations in the Cotton Valley Trend on the tight sand reservoirs of the Pettit and Travis Peak formations with depths ranging from 6,500 to 10,500 feet. These sands are typically distributed over a large area, which has led to a near 100% drilling success rate in this area. Due to the tight nature of the reservoirs, significant hydraulic fracture stimulation is required to obtain commercial production rates and efficiently drain the reservoir. Production in this area is generally characterized as long-lived, with wells having high initial production and decline rates that stabilize at lower levels after several years. Moreover, area operators continue to focus on infill development drilling as many areas have been down spaced to 40 acres per well, with some areas down-spaced to 20 acres per well. We drilled 54 wells (53.3 net wells) in the Cotton Valley Trend in 2008. As of December 31, 2008, we had five rigs running in this region and expect to drill an additional 29 wells during 2009.
 
 
As of December 31, 2008, we owned natural gas and oil interests in 60,059 gross (34,764 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, 2008, our estimated net proved reserves in the Gulf Coast area were 75.4 Bcfe, with net production of approximately 24.8 MMcfe per day for the month of December 2008.
 
 
We own interests in properties in Oklahoma, Arkansas and southern Kansas that make up our Mid-Continent area. As of December 31, 2008, we held interests in approximately 583,333 gross (417,573 net) leasehold and option acres in these areas. As of December 31, 2008, our estimated proved reserves in the Mid-Continent area were 93.0 Bcfe, based on estimates prepared by our internal engineers. Our average daily net production for the month of December 2008 was approximately 38.8 MMcfe per day.
 
 
Gulf of Mexico.  As of December 31, 2008, we owned natural gas and oil interests in 76,559 gross (37,434 net) acres in state and federal waters off the coast of Texas and Louisiana. As of December 31, 2008, our estimated net proved reserves in the Gulf of Mexico were 44.5 Bcfe, with net production of approximately 6.9 MMcfe per day for the month of December 2008. Our operations in the Gulf of Mexico extend from the coast to more than 100 miles offshore and occur in waters ranging from 30 feet to 1,100 feet.
 
Other West Texas.  Other non-tertiary assets we own in West Texas, outside of the WTO, include our Brooklaw Field and the Goldsmith Adobe Unit in the Permian Basin. As of December 31, 2008, we owned interests in 60,632 gross (39,236 net) acres in these prospects. As of December 31, 2008, our estimated net proved reserves were 87.3 Bcfe with net production of approximately 20.1 MMcfe per day for the month of December 2008. We have identified 441 potential drilling locations in these fields, including 134 proved undeveloped locations.
 
 
Wellman Unit.  The Wellman Unit, located in the Wellman Field in Terry County, Texas produces from the Canyon Reef limestone formation of Permian age from an average depth of 9,500 feet. The Wellman Unit covers approximately 2,120 acres, 1,200 of which are well-suited for both water and CO2 floods. The Wellman Field has been partially CO2 flooded and water flooded to produce 83.8 Mmboe to date. We re-initiated injection of CO2 in November 2005. Our injection rate of CO2 averaged 9.5 MMcf per day in 2008 and we expect to reach an average injection rate of 29.4 MMcf per day over the next 10 years. The Wellman Field has responded to this injection, and we averaged net oil production of 396 Bbls per day of new oil in December 2008. As of December 31, 2008, net proved reserves attributable to the Wellman Unit were 6.6 Mmboe. We also own a CO2 recycling plant at this unit with a capacity of 28.0 MMcf per day. The plant includes 6,000 horsepower of CO2 compression and 4,850


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horsepower of compression, which is sufficient to handle the recycling of the CO2 that will be produced in association with the production of these reserves.
 
George Allen Unit.  The George Allen Unit, located in Gaines County, Texas covers 800 gross acres in the George Allen Field and produces from the San Andres formation from an average depth of 4,950 feet. We have also leased an additional 320 acres adjacent to the George Allen Unit to the south. The field is located within the greater Wasson area, which contains seven active CO2 floods including the largest in the world, the Denver Unit. The George Allen Unit has produced 1.6 Mmboe to date, but it also contains a significant transition zone, which has been proven to be a tertiary oil target at the nearby Denver Unit. We are currently evaluating a nine-pattern pilot project. CO2 injection began in December 2007 following implementation of the first two patterns and averaged approximately 2.0 MMcf per day during 2008. We are currently evaluating the remaining seven flood patterns for CO2 injection. CO2 injection into the nine patterns is expected to reach 15.0 MMcf per day when fully developed. As of December 31, 2008, net proved reserves attributable to the George Allen Field were 7.6 Mmboe.
 
South Mallet Unit.  The South Mallet Unit, located in Hockley County, Texas, covers 3,540 gross acres in the Slaughter/Levelland Field complex and produces from the San Andres formation from an average depth of 5,000 feet. These fields are some of the largest in West Texas and currently have fourteen active CO2 floods and six more at various stages of readiness. The South Mallet Unit has produced 27.9 Mmboe to date. We are currently evaluating five flood patterns for CO2 injection. We expect to reach an ultimate CO2 injection rate of approximately 18 MMcf per day into thirteen patterns. As of December 31, 2008, net proved reserves attributable to the South Mallet Unit were 5.0 Mmboe.
 
Jones Ranch Area.  Several miles west of the George Allen Unit, in Gaines County, SandRidge Tertiary has acquired various leases in the Jones Ranch Area. These leases, covering approximately 2,400 gross acres, produce from various depths and formations. We are evaluating these leases for both conventional development and tertiary potential.
 
Proved Reserves
 
The following historical estimates of net proved natural gas and oil reserves are based on reserve reports as of December 31, 2008, December 31, 2007 and December 31, 2006, substantially all of which were prepared by independent petroleum engineers. The PV-10 and Standardized Measure shown in the table below are not intended to represent the current market value of our estimated natural gas and oil reserves. The reserve reports were based on our current drilling schedule and prices at December 31, 2008, and we estimate that 94.1% of our current proved undeveloped reserves will be developed by 2011 and all of our current proved undeveloped reserves will be developed by 2012. Refer to “Risk Factors” in Item 1A of this report and “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in Item 7 of this report in evaluating the material presented below.
 
Netherland, Sewell & Associates, Inc., independent oil and gas consultants, prepared the reports of estimated proved reserves of natural gas and oil for our net interest in certain natural gas and crude oil properties, which constituted approximately 90.2% of our total proved reserves as of December 31, 2008, approximately 89% of our total proved reserves as of December 31, 2007 and 92% of our total proved reserves as of December 31, 2006. DeGolyer and MacNaughton prepared the reports of estimated proved reserves (our tertiary oil reserves located in West Texas), for SandRidge Tertiary, LLC, formerly PetroSource Production Company, LLC, which constituted approximately 5.4% of our total proved reserves as of December 31, 2008, approximately 8% of our total proved reserves as of December 31, 2007 and approximately 7% of our total proved reserves as of December 31, 2006. The remaining 4.4%, 3% and 1% of our estimated proved reserves as of December 31, 2008, 2007 and 2006 were based on internally prepared estimates.
 


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    December 31,  
    2008     2007     2006  
 
Estimated Proved Reserves(1)
                       
Natural gas (Bcf)(2)
    1,899.6       1,297.0       850.7  
Oil (MmBbls)
    43.2       36.5       25.2  
Total (Bcfe)
    2,158.6       1,516.2       1,001.8  
PV-10 (in millions)(3)
  $ 2,258.5     $ 3,550.5     $ 1,734.3  
Standardized Measure of Discounted Net Cash Flows (in millions)(4)
  $ 2,220.6     $ 2,718.5     $ 1,440.2  
 
 
(1) Our estimated proved reserves and the future net revenues, PV-10, and Standardized Measure of Discounted Net Cash Flows were determined using year-end prices for natural gas and oil as of December 31, 2008, 2007 and 2006. The calculated weighted average prices were $4.94 per Mcf of natural gas and $39.42 per barrel of oil at December 31, 2008, $6.46 per Mcf of natural gas and $87.47 per barrel of oil at December 31, 2007 and $5.32 per Mcf of natural gas and $54.62 per barrel of oil at December 31, 2006.
 
(2) Given the nature of our natural gas reserves, a significant amount of our production, primarily in the WTO, contains natural gas high in CO2 content. These figures are net of volumes of CO2 in excess of pipeline quality specifications.
 
(3) PV-10 is a non-GAAP financial measure and represents the present value of estimated future cash inflows from proved natural gas and oil reserves, less future development and production costs, discounted at 10% per annum to reflect timing of future cash flows and using pricing assumptions in effect at the end of the period. PV-10 differs from Standardized Measure of Discounted Net Cash Flows because it does not include the effects of income taxes on future net revenues. Neither PV-10 nor Standardized Measure represents an estimate of fair market value of our natural gas and crude oil properties. PV-10 is used by the industry and by our 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 our Standardized Measure to PV-10:
 
                         
    At December 31,  
    2008     2007     2006  
    (In millions)  
 
Standardized Measure of Discounted Net Cash Flows
  $ 2,220.6     $ 2,718.5     $ 1,440.2  
Present value of future income tax discounted at 10%
    37.9       832.0       294.1  
                         
PV-10
  $ 2,258.5     $ 3,550.5     $ 1,734.3  
                         
 
(4) The Standardized Measure of Discounted Net Cash Flows represents the present value of estimated future cash inflows from proved natural gas and oil 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 as are used to calculate PV-10. Standardized Measure differs from PV-10 because Standardized Measure includes the effect of future income taxes.
 
Proved oil and gas reserves are the estimated quantities of oil, natural gas and natural gas liquids that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions such as prices and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions.
 
Reservoirs are considered proved if economic producibility is supported by either actual production or conclusive formation test. The area of a reservoir considered proved includes (i) that portion delineated by drilling and defined by gas-oil and/or oil-water contacts, if any, and (ii) the immediately adjoining portions not yet drilled, but which can be reasonably judged as economically productive on the basis of available geological and engineering data. In the absence of information on fluid contacts, the lowest known structural occurrence of hydrocarbons controls the lower proved limit of the reservoir.

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Reserves that can be produced economically through application of improved recovery techniques (such as fluid injection) are included in the proved classification when successful testing by a pilot project, or the operation of an installed program in the reservoir, provides support for the engineering analysis on which the project or program was based.
 
Estimates of proved reserves do not include the following:
 
  •  oil that may become available from known reservoirs but is classified separately as indicated additional reserves;
 
  •  oil, natural gas and natural gas liquids, the recovery of which is subject to reasonable doubt because of uncertainty as to geology, reservoir characteristics or economic factors;
 
  •  oil, natural gas and natural gas liquids that may occur in undrilled prospects; and
 
  •  oil, natural gas and natural gas liquids that may be recovered from oil shales, coal, gilsonite and other such sources.
 
Production and Price History
 
The following tables set forth information regarding our net production of oil, natural gas and natural gas liquids 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, our reported sales and reserves volumes and the related unit prices received for natural gas in these areas are reported net of CO2 volumes stripped at the gas plants. The gas plant fees for removing CO2 for our high CO2 natural gas have been included in our lease operating expenses as 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,  
    2008     2007     2006  
 
Production Data:
                       
Natural gas (MMcf)
    87,402       51,958       13,410  
Oil (MBbls)(1)
    2,334       2,042       322  
Combined equivalent volumes (MMcfe)
    101,405       64,211       15,342  
Average daily combined equivalent volumes (MMcfe/d)
    277.1       175.9       42.0  
 
                         
    Year Ended December 31,  
    2008     2007     2006  
 
Average Prices(2):
                       
Natural gas (per Mcf)
  $ 7.95     $ 6.51     $ 6.19  
Oil (per Bbl)(1)
  $ 91.54     $ 68.12     $ 56.61  
Combined equivalent (per Mcfe)
  $ 8.96     $ 7.45     $ 6.60  
 
 
(1) Includes natural gas liquids.
 
(2) Reported prices represent actual average prices for the periods presented and do not give effect to derivative contract settlements.
 


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    Year Ended December 31,  
    2008     2007     2006  
 
Expenses per Mcfe:
                       
Lease operating expenses:
                       
Transportation
  $ 0.11     $ 0.12     $ 0.22  
Processing, treating and gathering(1)
    0.33       0.28       0.37  
Other lease operating expenses
    1.13       1.25       1.70  
                         
Total lease operating expenses
  $ 1.57     $ 1.65     $ 2.29  
                         
Production taxes
  $ 0.30     $ 0.30     $ 0.30  
                         
 
 
(1) Includes costs attributable to gas treatment to remove CO2 and other impurities from our high CO2 natural gas.
 
 
The following table sets forth the number of productive wells in which we owned a working interest at December 31, 2008. Productive wells consist of producing wells and wells capable of producing, including natural gas wells awaiting pipeline connections to commence deliveries and oil wells awaiting connection to production facilities. Gross wells are the total number of producing wells in which we have an interest, and net wells are the sum of our fractional working interests owned in gross wells.
 
                 
Area
  Gross     Net  
 
WTO
    660       632.7  
East Texas
    232       218.4  
Gulf Coast
    141       86.2  
Mid-Continent
    611       242.5  
Other:
               
Gulf of Mexico
    42       21.2  
Other West Texas
    283       272.9  
Tertiary recovery — West Texas
    43       40.9  
Other
    47       1.0  
                 
Total
    2,059       1,515.8  
                 

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Developed and Undeveloped Acreage
 
The following table sets forth information regarding our developed and undeveloped acreage at December 31, 2008:
 
                                 
    Developed Acreage(1)     Undeveloped Acreage(2)  
Area
  Gross(3)     Net(4)     Gross(3)     Net(4)  
 
WTO
    19,394       18,797       758,081       637,129  
East Texas
    31,328       23,945       28,236       6,044  
Gulf Coast
    44,250       24,820       15,809       9,944  
Mid-Continent
    92,016       54,059       491,317       363,514  
Other:
                               
Gulf of Mexico
    71,128       32,003       5,431       5,431  
Other West Texas
    32,432       23,252       28,200       15,984  
Tertiary recovery — West Texas
    9,064       8,195              
Other
    163       38       29,107       24,509  
                                 
Total
    299,775       185,109       1,356,181       1,062,555  
                                 
 
 
(1) Developed acres are acres spaced or assigned to productive wells.
 
(2) Undeveloped acres are acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil or natural gas, regardless of whether such acreage contains proved reserves.
 
(3) A gross acre is an acre in which a working interest is owned. The number of gross acres is the total number of acres in which a working interest is owned.
 
(4) A net acre is deemed to exist when the sum of the fractional ownership working interests in gross acres equals one. The number of net acres is the sum of the fractional working interests owned in gross acres expressed as whole numbers and fractions thereof.
 
Many of the leases comprising the acreage set forth in the table above will expire at the end of their respective primary terms unless production from the leasehold acreage has been established prior to such date, in which event the lease will remain in effect until the cessation of production. The following table sets forth as of December 31, 2008 the expiration periods of the gross and net acres that are subject to leases in the acreage summarized in the above table.
 
                 
    Acres Expiring  
Twelve Months Ending
  Gross     Net  
 
December 31, 2009
    222,258       145,691  
December 31, 2010
    240,761       183,925  
December 31, 2011
    429,803       320,767  
December 31, 2012 and later
    404,456       352,492  
Other(1)
    68,581       61,968  
                 
Total
    1,365,859       1,064,843  
                 
 
 
(1) Leases remaining in effect until the cessation of development efforts or cessation of production on the developed portion of the particular lease.
 
Drilling Activity
 
The following table sets forth information with respect to wells we 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, quantities of reserves found or economic


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value. 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 we had a working interest and net wells refer to gross wells multiplied by our weighted average working interest. As of December 31, 2008, we had 54 wells in process.
 
                                                                                                 
    2008     2007     2006  
    Gross     Percent     Net     Percent     Gross     Percent     Net     Percent     Gross     Percent     Net     Percent  
 
Development:
                                                                                               
Productive
    398       98.5 %     372.4       98.5 %     281       99.3 %     244.4       99.5 %     82       94 %     50.8       95 %
Dry
    6       1.5 %     5.7       1.5 %     2       0.7 %     1.3       0.5 %     5       6 %     2.5       5 %
                                                                                                 
Total
    404       100 %     378.1       100 %     283       100 %     245.7       100 %     87       100 %     53.3       100 %
                                                                                                 
Exploratory:
                                                                                               
Productive
    48       96 %     46.4       95.9 %     27       82 %     24.3       84 %     19       76 %     13.0       72 %
Dry
    2       4 %     2.0       4.1 %     6       18 %     4.7       16 %     6       24 %     5.0       28 %
                                                                                                 
Total
    50       100 %     48.4       100 %     33       100 %     29.0       100 %     25       100 %     18.0       100 %
                                                                                                 
Total:
                                                                                               
Productive
    446       98.2 %     418.8       98.2 %     308       98 %     268.7       98 %     101       90 %     63.8       89 %
Dry
    8       1.8 %     7.7       1.8 %     8       2 %     6.0       2 %     11       10 %     7.5       11 %
                                                                                                 
      454       100 %     426.5       100 %     316       100 %     274.7       100 %     112       100 %     71.3       100 %
                                                                                                 
 
 
The following table sets forth information with respect to the rigs operating on our acreage as of December 31, 2008.
 
                 
Area
  Owned(1)     Third-Party  
 
WTO
    9        
East Texas
    2       3  
Gulf Coast
           
Mid-Continent
          1  
Other West Texas
    2        
                 
Total
    13       4  
                 
 
 
(1) Includes rigs owned by Lariat and by Larclay.
 
 
We sell natural gas, oil and natural gas liquids to a variety of customers including utilities, natural gas and oil companies, and trading and energy marketing companies. During 2008 and 2007, we sold our production to over twenty different purchasers, one of which, Plains Energy, accounted for approximately 10% and 11%, respectively, of our total revenue. Given the number of purchasers for our products, it is unlikely that the loss of a single customer in the areas in which we sell our products would materially affect our sales.
 
See Note 23 in the consolidated financial statements included in Item 8 of this report for information regarding our major customers.
 
 
As is customary in the oil and gas industry, we initially conduct only a cursory review of the title to our properties for which we do not have proved reserves. Prior to the commencement of drilling operations on those properties, we conduct a thorough title examination and perform curative work with respect to significant defects.


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To the extent title opinions or other investigations reflect title defects on those properties, we are typically responsible for curing any title defects at our expense. We generally will not commence drilling operations on a property until we have cured any material title defects on such property. In addition, prior to completing an acquisition of producing natural gas and oil leases, we perform title reviews on the most significant leases, and depending on the materiality of properties, we may obtain a title opinion or review previously obtained title opinions. To date, we have obtained title opinions on substantially all of our producing properties and believe that we have satisfactory title to our producing properties in accordance with standards generally accepted in the oil and gas industry. Our natural gas and crude oil properties are subject to customary royalty and other interests, liens for current taxes and other burdens, which we believe do not materially interfere with the use of or affect our carrying value of the properties.
 
 
The drilling and related oil field services that we provide to our exploration and production business and to third parties in West Texas are described below.
 
 
We drill for our own account in the WTO through our drilling and oil field services subsidiary, Lariat. In addition, we also drill wells for other natural gas and oil companies, primarily located in the West Texas region. We believe that drilling with our own rigs allows us to control costs and maintain operating flexibility. In addition, we own a 50% interest in a limited partnership, Larclay, which owns and operates drilling rigs. Our rig fleet, including rigs owned by Larclay, is designed to drill in our specific areas of operation and has an average horsepower of over 800 and an average depth capacity of greater than 10,500 feet. As of December 31, 2008, our drilling rig fleet consisted of 39 operational rigs, 28 of which we owned directly and 11 of which were owned by Larclay. As of December 31, 2008, 13 of our rigs were working on properties that we operated.
 
In 2005, we ordered 22 rigs from Chinese manufacturers for an aggregate purchase price of $126.4 million, which included the cost of assembling and equipping the rigs in the United States. Due in part to the shortage of experienced drilling employees and various operational challenges, we deemed it prudent to retrofit five of these rigs to a conventional operation. The last of the five rigs to be retrofitted became operational in the second quarter of 2008.
 
The table below identifies certain information concerning our contract drilling operations and our directly-owned rigs:
 
                         
    Year Ended December 31,  
    2008     2007     2006  
 
Number of operational rigs owned at end of period
    28       25       25  
Average number of operational rigs owned during the period
    27.6       26.0       21.9  
Average drilling revenue per day per rig working for third parties(1)(2)
  $ 14,217     $ 21,468     $ 24,646  
 
 
(1) Represents revenues from our rigs working for third parties divided by the total number of days our drilling rigs were used by third parties during the period.
 
(2) Does not include revenues for related rental equipment.
 
The table below identifies certain information concerning our drilling rigs as of December 31, 2008:
 
                                 
    Operating for              
    SandRidge     Third Parties     Idle     Operational(1)  
 
Lariat
    13       3       12       28  
Larclay
    0       1       10       11  
                                 
Total
    13       4       22       39  
                                 
 
 
(1) Excludes two Lariat rigs that were being refurbished, one Lariat rig that was non-operational and one Larclay rig that has not been assembled.


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Our oil field services business began in 1986 and conducts operations that complement our drilling services operations. These services include providing drilling rigs, pulling units, trucking, rental tools, location and road construction and roustabout services to us and our subsidiaries as well as to third parties. Approximately 11% of our oil field services in 2008 were performed for third parties, a decline from the approximately 28% in 2007 due to an increase in the average number of our rigs that were operating on our properties, an increase in our ownership interest in our natural gas and crude oil properties and a decline in average revenue earned per day for rigs working for third parties. Our capital expenditures for 2008 related to our oil field services were $52.9 million and we have budgeted a range of $10.0 million to $20.0 million in capital expenditures in 2009 for oil field services.
 
 
We obtain our contracts for drilling natural gas and oil wells either through competitive bidding or through direct negotiations with customers. Our drilling contracts generally provide for compensation on a daywork or turnkey basis. The contract terms we offer 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.
 
 
We perform approximately two-thirds of our drilling services in support of our exploration and production business and approximately one-third for other operators in West Texas. For the year ended December 31, 2008, we generated revenues of $10.7 million for drilling services performed for third parties, with Pioneer Natural Resources accounting for approximately $9.3 million of those revenues.
 
 
We provide gathering, compression, processing and treating services of natural gas in West Texas. Our midstream operations and assets not only serve our exploration and production business, but also service other natural gas and oil companies. The following tables set forth information regarding our primary midstream assets as of December 31, 2008:
 
                         
    Plant Capacity
  Average
  Third-Party
Gas Plants (West Texas)
  (MMcf/d)   Utilization(1)   Usage
 
Pike’s Peak
    81       98 %     <1 %
Grey Ranch(2)
    160       89 %     16 %
 
 
(1) Average utilization for the year ended December 31, 2008.
 
(2) We experienced a fire at our Grey Ranch plant located in Pecos County, Texas on June 27, 2008. The plant was shut down for repairs until its return to service October 31, 2008. Prior to the fire, the plant had 95 MMcf/d of treating capacity. As of December 31, 2008, the plant was operating with the expanded capacity of 160 MMcf/d as a result of expansions made to the plant during the repair of fire damage.
 
                 
    CO2 Compression
    Average
 
SandRidge CO2 Facilities (West Texas)
  Capacity (MMcf/d)     Utilization(1)  
 
Pike’s Peak
    38       78 %
Mitchell
    26       95 %
Grey Ranch(2)
    100       19 %
Terrell
    38       64 %
 
 
(1) Average utilization for the year ended December 31, 2008.
 
(2) Includes the period that the Grey Ranch plant was shut down and operating at limited capacity due to a fire that occurred on June 27, 2008.


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In Pecos County, we operate and own the Pike’s Peak gas treating plant, which has the capacity to treat 81 MMcf per day of natural gas for the removal of CO2 from natural gas produced in the Piñon Field and nearby areas. We also own the Grey Ranch CO2 treatment plant located in Pecos County and have a 50% interest in the partnership that leases the plant from us under a lease expiring in 2010. Our 50% partner, Southern Union, operates the plant. The treating capacities for both the Pike’s Peak and Grey Ranch plants are dependent upon the quality of natural gas being treated. The data included in the table above for the Pike’s Peak and Grey Ranch plants is based on a natural gas stream that averaged 65% CO2.
 
Our two West Texas plants remove CO2 from natural gas production and deliver residue gas into the Atmos Lone Star and Enterprise Energy Services pipelines. These assets are operated on fixed fees based upon throughput of natural gas. In addition, we have access for up to 65 MMcf per day of treating capacity at Anadarko Petroleum Corporation’s Mitchell Plant under a long-term fixed fee arrangement.
 
We also operate or own approximately 653 miles of natural gas gathering pipelines and numerous dehydration units. Within the Piñon Field, we operate separate gathering systems for sweet natural gas and produced natural gas containing high percentages of CO2. In addition to servicing our exploration and production business, these assets also service other natural gas and oil companies.
 
The majority of the produced natural gas gathered by our midstream assets in West Texas requires compression from the wellhead to the final sales meter. As of December 31, 2008, we owned and operated approximately 80,000 horsepower of gas compression in West Texas. We anticipate installing an additional 20,000 horsepower in 2009.
 
 
As of December 31, 2008, we owned approximately 110 miles of pipeline gathering systems and operated more than 11,000 horsepower of natural gas compression in East Texas and approximately 44 miles of pipeline gathering systems in the Gulf Coast area.
 
In May 2008, we completed the sale of substantially all of our assets located in the Piceance Basin of Colorado, including gathering and compression systems as well as undeveloped acreage, working interests in wells and other facilities related to natural gas and oil wells.
 
 
The growth of our midstream assets is driven by our 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 2008, we spent approximately $164.0 million in capital expenditures to install pipeline and compression infrastructure to accommodate our growth in production and for increased treating capacity for high CO2 gas, adding approximately 79 MMcf per day in additional treating capacity. We anticipate adding approximately 60 MMcf per day in additional treating capacity in 2009. We have budgeted approximately $65.0 million in 2009 capital expenditures for our midstream gas services and other segments.
 
 
Through Integra Energy LLC, (“Integra Energy”), our wholly owned subsidiary, we buy and sell the natural gas from SandRidge-operated wells and third-party-operated wells within our West Texas operations. We generally buy and sell 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 Inside FERC and Gas Daily pricing indices to eliminate price exposure.
 
We do not actively seek to buy and sell third-party natural gas due to onerous credit requirements and minimal margin expectations. We conduct thorough credit checks with all potential purchasers and minimize our exposure by contracting with multiple parties each month. We do not engage in any hedging activities with respect to these contracts. We manage several interruptible natural gas transportation agreements in order to take advantage of price differentials or to secure available markets when necessary. We currently have 100 MmBtu per day of firm


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transportation service subscribed on the Oasis Pipeline and 75 MmBtu per day on the Mid-Continent Express Pipeline for a portion of our Piñon Field production for 2009. The commitment to the Mid-Continent Express Pipeline commences upon completion of its construction, currently estimated to be in the summer of 2009.
 
 
Our CO2 capturing operations are conducted through SandRidge CO2. As of December 31, 2008, SandRidge CO2 owned 231 miles of CO2 pipelines in West Texas with approximately 88,000 horsepower of owned and leased CO2 compression available and approximately 54,000 horsepower currently operational. The captured CO2 is primarily used and sequestered in tertiary oil recovery operations. As of December 31, 2008, SandRidge CO2 was capturing approximately 85.0 MMcf per day of CO2. We delivered the majority of this to Occidental Permian Ltd. (“Occidental”) and Chevron Corp. In December 2008, we captured and sold an average of 67.4 MMcf of CO2 per day and utilized 15.1 MMcf per day in our equity projects.
 
Future regulation of greenhouse gas emissions may provide the Company an opportunity to create economic benefits in the form of Emissions Reduction Credits (“ERCs”), but such regulation may also impose burdens on the conduct and cost of our operations. Legislative and regulatory efforts may result in legal requirements that create a more active and more valuable market in which to trade ERCs, although the timing and scope of future legal requirements governing greenhouse gases remain uncertain. We currently capture approximately 1.6 million metric tonnes of CO2 per year which is sequestered in enhanced oil recovery projects. The captured CO2 may prove beneficial to us if the capture results in ERCs that can be traded or used by us to meet future regulatory compliance obligations that may otherwise be costly to satisfy. ERCs of just over 200,000 tonnes were sold on the voluntary market during 2008. See “— Environmental Regulations — Future Laws and Regulations.”
 
 
We believe that our leasehold acreage position, oil field service businesses, midstream assets, CO2 supply and technical and operational capabilities generally enable us to compete effectively. However, the oil and gas industry is intensely competitive, and we face competition in each of our business segments.
 
We believe our geographic concentration of operations and vertical integration enables us to compete effectively with other exploration and production operations. However, we are competing with companies that have greater financial and personnel resources than we do. These 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 natural gas and oil market prices. Our larger or integrated competitors may be able to absorb the burden of any existing and future federal, state and local laws and regulations more easily than we can, which would adversely affect our competitive position. Our ability to acquire additional properties and to discover reserves in the future depends on our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. In addition, because we have fewer financial and human resources than many companies in our industry, we may be at a disadvantage in bidding for exploratory prospects and producing natural gas and crude oil properties.
 
With respect to our drilling business, we believe the type, age and condition of our drilling rigs, the quality of our crews and the responsiveness of our management generally enable us to compete effectively. However, to the extent we drill for third parties, we encounter substantial competition from other drilling contractors. Our primary market area is highly competitive. The drilling contracts we compete for are sometimes awarded on the basis of competitive bids.
 
We believe pricing and rig availability are the primary factors our potential customers consider in determining which drilling contractor to select. While we must be competitive in our pricing, our competitive strategy generally emphasizes the quality of our equipment and the experience of our rig crews to differentiate us from our competitors. This strategy is less effective when demand for drilling services is weak or there is an oversupply of rigs, as is the case in the current economic environment. These conditions usually result in increased price competition, which makes it more difficult for us to compete on the basis of factors other than price. Many of our competitors have greater financial, technical and other resources than we do. Their greater capabilities in these areas may enable them to better withstand industry downturns and better retain skilled rig personnel.


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We believe our geographic concentration of operations enables us to compete effectively in our midstream business segment. Most of our midstream assets are integrated with our production. However, with respect to third-party natural gas and acquisitions, we compete with companies that have greater financial and personnel resources than we do. These companies may be able to pay more for acquisitions. In addition, these companies may have a greater ability to price their services below our prices for similar services.
 
We believe our supply of CO2 and technical expertise enable us to compete effectively in our CO2 gathering and sales business. However, we face the same competitive pressures in this business that we do in our traditional oil field services segments.
 
 
Generally, the demand for natural gas decreases during the summer months and increases during the winter months. Seasonal anomalies such as mild winters or cool summers sometimes lessen this fluctuation. In addition, certain natural gas users utilize natural gas storage facilities and purchase some of their anticipated winter requirements during the summer. This can also lessen seasonal demand fluctuations. Seasonal weather conditions and lease stipulations can limit our drilling and producing activities and other natural gas and oil operations in a portion of our operating areas. These seasonal anomalies can pose challenges for meeting our 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 our operations.
 
Environmental Regulations
 
 
We are subject to extensive and complex federal, state and local laws and regulations governing the protection of the environment and of the health and safety of our employees. These laws and regulations may, among other things:
 
  •  require the acquisition of various permits before drilling or production commences;
 
  •  require the installation of expensive pollution control equipment;
 
  •  require safety-related procedures and personal protective equipment to be used during operations;
 
  •  restrict the types, quantities and concentrations of various substances that can be released into the environment in connection with natural gas and oil drilling production, transportation and treating activities;
 
  •  suspend, limit, prohibit or require approval before construction, drilling and other activities; and
 
  •  require remedial measures to mitigate pollution from historical and ongoing operations, such as the closure of pits and plugging of abandoned wells.
 
These laws, rules and regulations may also restrict the rate of natural gas and oil production below the rate that would otherwise be possible. The regulatory burden on the oil and gas industry increases the cost of doing business in the industry and consequently affects profitability.
 
Governmental authorities have the power to enforce compliance with environmental laws, regulations and permits, and violations are subject to injunction, as well as administrative, civil and potentially criminal penalties. The effects of these laws and regulations, as well as other laws or regulations that may be adopted in the future, could have a material adverse impact on our business, financial condition and results of operations. Below is a discussion of the environmental laws and regulations that could have a material impact on the oil and gas industry.
 
 
The Comprehensive Environmental Response, Compensation and Liability Act, or CERCLA, also known as the Superfund law, and analogous state laws impose joint and several liability, without regard to fault or legality of conduct, on specific classes of persons for the release of a hazardous substance into the environment. These persons include the owner or operator of the site where the release occurred, and anyone who disposed or arranged for the


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disposal of a hazardous substance released at the site. Under CERCLA, such 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 related environmental and health studies. In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. In the course of our operations, we generate wastes that may fall within CERCLA’s definition of hazardous substances. Further, natural gas and oil exploration, production, treating and other activities have been conducted at some of our properties by previous owners and operators, and materials from these operations remain at and could migrate from some of our properties and may warrant or require investigation or remediation or other response action. Therefore, governmental agencies or third parties could seek to hold us responsible under CERCLA or similar state laws for all or part of the costs to clean up a site at or to which hazardous substances may have been released or deposited.
 
 
The Resource Conservation and Recovery Act, or RCRA, and comparable state statutes, regulate the generation, transportation, treatment, storage, disposal and cleanup of hazardous and non-hazardous wastes. Under the auspices of the United States Environmental Protection Agency, or EPA, the individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own more stringent requirements. Drilling fluids, produced waters and most of the other wastes associated with the exploration, development and production of oil or natural gas are currently excluded from regulation as RCRA hazardous wastes but instead are regulated under RCRA’s non-hazardous waste provisions. However, it is possible that certain natural gas and oil exploration and production wastes now classified as non-hazardous could be classified as hazardous wastes in the future. Any such change would likely increase our operating expenses, which could have a material adverse effect on our business, financial condition or results of operations as well as on the industry in general.
 
 
The federal Clean Air Act and comparable state laws control emissions of potentially harmful air emissions through permitting and monitoring regulations. We are required to obtain various permits to ensure that emissions from our operations remain within permitted levels. To comply with the terms of these permits, and, as part of our ongoing efforts to operate in an environmentally responsible manner, we have installed and maintained complex emission control technologies throughout our systems that we expect will cause us to incur increased capital and operating costs at new and existing facilities. We have committed approximately $3.5 million to compressor engine emission reduction projects to enable compliance at our Grey Ranch compression station and our Pikes Peak treating plant. Additionally, our midstream operations have implemented a voluntary compliance audit under the Texas Environmental Health and Safety Audit Privilege Act. Substantial additional expenses and capital costs may be required in 2009 and beyond for us to maintain or achieve compliance with current and future laws governing air emissions.
 
 
The federal Water Pollution Control Act, or the Clean Water Act, and analogous state laws, impose restrictions and strict controls with respect to the discharge of pollutants, including spills and leaks of oil and other substances into waters of the United States, including wetlands, as well as state waters. These laws prohibit the discharge of produced waters and sand, drilling fluids, drill cuttings and other substances related to the oil and gas industry into onshore, coastal and offshore waters without appropriate permits. Some of the pollutant limitations have become more restrictive over the years, and additional restrictions and limitations including technology requirements and receiving water limits, may be imposed in the future. The Clean Water Act also regulates storm water discharges from industrial and construction activities. Regulations promulgated by the EPA and state regulatory agencies require industries engaged in certain industrial or construction activities to acquire permits and implement storm water management plans and best management practices, to conduct periodic monitoring and reporting of discharges, and to train employees. Further, federal and state regulations require certain natural gas and oil exploration and production facilities to obtain permits for storm water discharges. There are costs associated with each of these regulatory requirements. In addition, federal and state regulatory agencies can impose administrative,


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civil and potentially criminal penalties for non-compliance with discharge permits or other requirements of the Clean Water Act and analogous state laws and regulations.
 
The Oil Pollution Act of 1990, or OPA, which amends and augments the Clean Water Act, establishes strict liability for owners and operators of facilities that are the site of a release of oil into waters of the United States. In addition, OPA and regulations that implement OPA impose a variety of regulations on responsible parties related to the prevention of oil spills and liability for clean up and natural resource damages resulting from such spills. For example, some of our facilities in the Gulf Coast region must develop, implement and maintain facility response plans, conduct annual spill training for certain employees, conduct annual spill drills and provide varying degrees of financial assurance.
 
 
Natural gas and oil exploration and production activities on federal lands or otherwise requiring federal approval are subject to the National Environmental Policy Act, or NEPA. NEPA requires federal agencies, including the Department of Interior, to evaluate major agency actions having the potential to significantly impact the environment. In the course of such evaluations, an agency may prepare an Environmental Assessment that assesses the potential direct, indirect and cumulative impacts of a proposed project and, if necessary, will prepare a more detailed Environmental Impact Statement that is made available for public review and comment. All of our current exploration and production activities, as well as proposed exploration and development plans on federal lands, require governmental permits that are subject to the requirements of NEPA. The NEPA process has the potential to delay or even prohibit our development of natural gas and oil projects in covered areas.
 
 
Recent scientific studies have suggested that emissions of certain gases, commonly referred to as greenhouse gases and including carbon dioxide and methane, may contribute to warming the Earth’s atmosphere. In response to such studies, the United States Congress is actively considering legislation to restrict or regulate emissions of greenhouse gases. More than one-third of the states, either individually or through multi-state regional initiatives, have begun implementing legal measures to reduce emissions of greenhouse gases, primarily through the planned development of greenhouse gas emissions inventories and regional greenhouse gas cap-and-trade programs. Also, in July 2008, the EPA issued an Advance Notice of Proposed Rulemaking regarding possible future regulation of greenhouse emissions under the Clean Air Act in response to the United States Supreme Court’s decision in Massachusetts, et al. v. EPA, decided in 2007, which may result in the imposition of restrictions on the emission of greenhouse gases, even if Congress does not adopt new legislation specifically addressing emissions of greenhouse gases. Other nations have already agreed to regulate emissions of greenhouse gases pursuant to the Kyoto Protocol, an international treaty pursuant to which participating countries, not including the United States, have agreed to reduce their emissions of greenhouse gases to below 1990 levels by 2012. Passage of climate-related legislation or other regulatory initiatives by Congress or various states of the United States, or the adoption of regulations by the EPA and analogous state agencies that restrict emissions of greenhouse gases in areas in which we conduct business, may have an adverse effect on demand for our services or products and may result in compliance obligations with respect to the release, capture and use of carbon dioxide that could have an adverse effect on our operations.
 
 
The federal Department of Homeland Security Appropriations Act of 2007 requires the Department of Homeland Security, or DHS, to issue regulations establishing risk-based performance standards for the security of chemical and industrial facilities, including oil and gas facilities that are deemed to present high levels of security risk. The DHS issued an interim final rule in 2007 regarding risk-based performance standards to be attained pursuant to the act and, on November 20, 2007, further issued an Appendix A to the interim rules establishing chemicals of interest and their respective threshold quantities that will trigger compliance with the interim rules. We have not yet determined the extent to which our facilities are subject to the interim rules or the associated costs to comply, but it is possible that such costs could be substantial.


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The oil and gas industry is extensively regulated by numerous federal, state and local authorities, including Native American tribes. Legislation affecting the oil and 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 binding on the oil and gas industry and its individual members, some of which carry substantial penalties for noncompliance. Although the regulatory burden on the oil and gas industry increases our cost of doing business and, consequently, affects our profitability, these burdens generally do not affect us 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.
 
 
Our 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 we operate also regulate one or more of the following activities:
 
  •  the location of wells;
 
  •  the method of drilling and casing wells;
 
  •  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 natural gas and crude oil 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 our interest in the unitized properties. In addition, state conservation laws establish maximum rates of production from natural gas and oil 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 natural gas and oil we can produce from our wells or limit the number of wells or the locations at which we 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 we operate. Regulations of the Minerals Management Service of the United States Department of the Interior (“MMS”) 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. The MMS requires federal leaseholders to post performance bonds or otherwise provide necessary financial assurances to provide for such abandonment, decommissioning and removal. 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, or ACOE, and many other state and local municipalities have regulations for plugging and abandonment, decommissioning and site restoration. Although the ACOE does not require bonds or other financial assurances, some other state agencies and municipalities do have such requirements.
 
 
Historically, federal legislation and regulatory controls have affected the price of the natural gas we produce and the manner in which we market our production. The Federal Energy Regulatory Commission, or 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


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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 our sales of our own production.
 
FERC also regulates interstate natural gas transportation rates and service conditions, which affects the marketing of natural gas that we produce, as well as the revenues we receive for sales of our natural gas. 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, unregulated, 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, we cannot guarantee that the less stringent regulatory approach currently pursued by FERC and Congress will continue indefinitely into the future nor can we determine what effect, if any, future regulatory changes might have on our 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, FERC recently has reclassified certain jurisdictional transmission facilities as non-jurisdictional gathering facilities, which has the tendency to increase our costs of getting gas to point-of-sale locations.
 
 
As of December 31, 2008, we had 2,094 full-time employees and one part-time employee, including more than 210 geologists, geophysicists, petroleum engineers, technicians, land and regulatory professionals. Of our 2,095 employees, 528 are located at our headquarters in Oklahoma City, Oklahoma, and the remaining employees are working in our various field offices and at our drilling sites.
 
 
In July 2007, we purchased property in downtown Oklahoma City, Oklahoma, which serves as our corporate headquarters. We also own office and shop space in Fort Stockton, Midland and Odessa, Texas. As of December 31, 2008, we leased 57,417 square feet of office space in Oklahoma City, Oklahoma. The term of the lease expires in August 2009. In addition, we lease or sublease office space in Oklahoma, Louisiana and Texas.
 
Glossary of Natural Gas and Oil Terms
 
The following is a description of the meanings of some of the oil and 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.
 
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 natural gas or oil, or in the case of a dry hole, the reporting of abandonment to the appropriate agency.
 
Condensate.  Liquid hydrocarbons associated with the production of a primarily natural gas reserve.
 
CO2.  Carbon dioxide.
 
Developed acreage.  The number of acres that are allocated or assignable to productive wells or wells capable of production.
 
Development well.  A well drilled into a proved natural gas or oil reservoir to the depth of a stratigraphic horizon known to be productive.
 
Dry hole.  A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes.
 
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 natural gas and oil 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 natural gas and oil 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 and produce natural gas or oil reserves not classified as proved, to find a new reservoir in a field previously found to be productive of natural gas or oil in another reservoir or to extend a known reservoir.
 
Field.  An area consisting of either a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition.
 
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.
 
Mcf.  Thousand cubic feet of natural gas.
 
Mcf/d.  Mcf per day.
 
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.
 
MBtu.  Thousand British Thermal Units.
 
MmBtu.  Million British Thermal Units.
 
MMcf.  Million cubic feet of natural gas.
 
MMcf/d.  MMcf per day.


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MMcfe.  Million cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of oil, condensate or natural gas liquids.
 
MMcfe/d.  MMcfe 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%.
 
Productive well.  A well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of the production exceed production expenses and taxes.
 
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.  Has the meaning given to such term in Rule 4-10(a)(3) of Regulation S-X, which defines proved developed reserves as:
 
Reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Additional oil and gas expected to be obtained through the application of fluid injection or other improved recovery techniques for supplementing the natural forces and mechanisms of primary recovery should be included as proved developed reserves only after testing by a pilot project or after the operation of an installed program has confirmed through production response that increased recovery will be achieved.
 
Proved reserves.  Has the meaning given to such term in Rule 4-10(a)(2) of Regulation S-X, which defines proved reserves as:
 
The estimated quantities of oil, natural gas and natural gas liquids that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions.
 
(i) Reservoirs are considered proved if economic producibility is supported by either actual production or conclusive formation test. The area of a reservoir considered proved includes (A) that portion delineated by drilling and defined by gas-oil and/or oil-water contacts, if any, and (B) the immediately adjoining portions not yet drilled, but which can be reasonably judged as economically productive on the basis of available geological and engineering data. In the absence of information on fluid contacts, the lowest known structural occurrence of hydrocarbons controls the lower proved limit of the reservoir.
 
(ii) Reserves that can be produced economically through application of improved recovery techniques (such as fluid injection) are included in the proved classification when successful testing by a pilot project, or the operation of an installed program in the reservoir, provides support for the engineering analysis on which the project or program was based.
 
(iii) Estimates of proved reserves do not include the following: (A) oil that may become available from known reservoirs but is classified separately as indicated additional reserves; (B) oil, natural gas and natural gas liquids, the recovery of which is subject to reasonable doubt because of uncertainty as to geology, reservoir


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characteristics or economic factors; (C) oil, natural gas and natural gas liquids, that may occur in undrilled prospects; and (D) oil, natural gas and natural gas liquids, that may be recovered from oil shales, coal, gilsonite and other such sources.
 
Proved undeveloped reserves.  Has the meaning given to such term in Rule 4-10(a)(4) of Regulation S-X, which defines proved undeveloped reserves as:
 
Reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage shall be limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved reserves for other undrilled units can be claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation. Under no circumstances should estimates for proved undeveloped reserves be 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 tests in the area and in the same reservoir.
 
Pulling Units.  Pulling units are used in connection with completions and workover operations.
 
PV-10. See “Present value of future net revenues.”
 
Rental Tools.  A variety of rental tools and equipment, ranging from trash trailers to blow out preventors to sand separators, for use in the oil field.
 
Reservoir.  A porous and permeable underground formation containing a natural accumulation of producible natural gas and/or crude oil that is confined by impermeable rock or water barriers and is 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 natural gas and oil 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 and asset retirement obligations on future net revenues.
 
Trucking.  The provision of trucks to move our 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 commercial quantities of natural gas and oil regardless of whether such acreage contains proved reserves.
 
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
 
 
Our revenues, profitability and cash flow depend upon the prices and demand for natural gas and oil. The markets for these commodities are very volatile. Even relatively modest drops in prices can significantly affect our financial results and impede our growth. Changes in natural gas and oil prices have a significant impact on the value of our reserves and on our cash flow. Prices for natural gas and oil may fluctuate widely in response to relatively minor changes in the supply of and demand for natural gas and oil and a variety of additional factors that are beyond our control, such as:
 
  •  the domestic and foreign supply of natural gas and oil;


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  •  the price of foreign imports;
 
  •  worldwide economic conditions;
 
  •  political and economic conditions in oil producing regions, including the Middle East and South America;
 
  •  the ability of members of the Organization of Petroleum Exporting Countries to agree to and maintain oil price and production controls;
 
  •  the level of consumer product demand;
 
  •  weather conditions, including hurricanes and tropical storms in and around the Gulf of Mexico;
 
  •  technological advances affecting energy consumption;
 
  •  availability of pipeline infrastructure, treating, transportation and refining capacity;
 
  •  domestic and foreign governmental regulations and taxes; and
 
  •  the price and availability of alternative fuels.
 
Lower natural gas and oil prices, such as those experienced in the fourth quarter of 2008, may not only decrease our revenues on a per share basis, but also may reduce the amount of natural gas and oil that we can produce economically and, therefore, could have a material adverse effect on our financial condition and results of operations. This also may result in our having to make substantial downward adjustments to our estimated proved reserves.
 
 
Global financial markets and economic conditions have been, and continue to be, disrupted and volatile due to a variety of factors, including significant write-offs in the financial services sector and current 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. As a result, the cost of raising money in the debt and equity capital markets has increased substantially while the availability of funds from those markets has diminished significantly. In particular, as a result of concerns about the stability of financial markets generally and the solvency of lending counterparties specifically, the cost of obtaining money from the credit markets generally has increased as many lenders and institutional investors have increased interest rates, enacted tighter lending standards, refused to refinance existing debt on similar terms or at all and reduced, or in some cases ceased, to provide funding to borrowers. In addition, lending counterparties under existing revolving credit facilities and other debt instruments may be unwilling or unable to meet their funding obligations. These factors may adversely affect the value of certain of our assets and our ability to draw on our senior credit facility. If the current credit conditions of United States and international capital markets persist or deteriorate, we may be required to impair the carrying value of assets associated with derivative contracts to account for non-performance by counterparties to those contracts. Moreover, government responses to the disruptions in the financial markets may not restore consumer confidence, stabilize the markets or increase liquidity and the availability of credit.
 
On October 3, 2008, Lehman Brothers Commodity Services, Inc. (“Lehman Brothers”), a lender under our senior credit facility, filed for bankruptcy. At the time that its parent, Lehman Brothers Holdings, Inc., declared bankruptcy on September 15, 2008, Lehman Brothers elected not to fund its pro rata share, or 0.29%, of borrowings requested by us under the senior credit facility. As a result, we do not anticipate that Lehman Brothers will fund its pro rata share of any future borrowing requests. We currently do not expect this reduced availability of amounts under the senior credit facility to impact our liquidity or business operations.
 
If other financial institutions that have extended credit commitments to us are adversely affected by the current conditions of the United States and international capital markets, they may become unable to fund borrowings under their credit commitments to us, which could have a material adverse effect on our financial condition and our ability to borrow additional funds, if needed, for working capital, capital expenditures and other corporate purposes.


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We utilize the full cost method of accounting for costs related to our natural gas and crude oil properties. Under this accounting method, all costs for both productive and nonproductive properties are 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 natural gas and oil reserves attributable to proved properties, discounted at 10%, plus the lower of cost or market value of unproved properties. The full cost ceiling is evaluated at the end of each quarter using the prices for natural gas and oil in effect at the end of the quarter, adjusted for the impact of derivatives accounted for as cash flow hedges. As none of our derivatives are accounted for as cash flow hedges, the impact of our derivative contracts has been excluded from the determination of our full cost ceiling. Our ceiling limitation as of December 31, 2008 resulted in a non-cash impairment charge of $1,855.0 million. Further declines in natural gas and oil 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 us to make additional writedowns of capitalized costs of our natural gas and crude oil properties and non-cash charges against future earnings. The amount of such future writedowns and non-cash charges could be substantial. If natural gas and oil commodity prices remain at these current levels or decline further through the end of the first quarter of 2009, we estimate we would have a further reduction in our asset carrying value for our natural gas and crude oil properties.
 
 
As of December 31, 2008, our total indebtedness was $2.4 billion, which represented approximately 75% of our total capitalization. Our substantial level of indebtedness increases the possibility that we may be unable to generate cash sufficient to pay, when due, the principal of, interest on or other amounts due in respect of our indebtedness. Our substantial indebtedness, combined with our lease and other financial obligations and contractual commitments, could have other important consequences to us. For example, it could:
 
  •  make us more vulnerable to adverse changes in general economic, industry and competitive conditions and adverse changes in government regulation;
 
  •  require us to dedicate a substantial portion of our cash flow from operations to payments on our indebtedness, thereby reducing the availability of our cash flows to fund working capital, capital expenditures, acquisitions and other general corporate purposes;
 
  •  limit our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate;
 
  •  place us at a competitive disadvantage compared to our competitors that are less leveraged and, therefore, may be able to take advantage of opportunities that our indebtedness prevents us from pursuing; and
 
  •  limit our ability to borrow additional amounts for working capital, capital expenditures, acquisitions, debt service requirements, execution of our business strategy or other purposes.
 
Any of the above listed factors could have a material adverse effect on our business, financial condition and results of operations.
 
 
The process of estimating natural gas and oil reserves is complex and inherently imprecise. It requires interpretations of available technical data and many assumptions, including assumptions relating to production rates and economic factors such as natural gas and oil prices, drilling and operating expenses, capital expenditures and availability of funds. Any significant inaccuracies in these interpretations or assumptions could materially affect the


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estimated quantities and present value of reserves shown in this report. See “Business — Our Businesses and Primary Operations” in Item 1 of this report for information about our natural gas and oil reserves.
 
Actual future production, natural gas and oil prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable natural gas and oil reserves most likely will vary from our estimates. Any significant variance could materially affect the estimated quantities and present value of reserves shown in this report. In addition, we may adjust estimates of proved reserves to reflect production history, results of exploration and development, prevailing natural gas and oil prices and other factors, many of which are beyond our control.
 
 
We base the estimated discounted future net cash flows from our proved reserves on prices and costs in effect on the last day of the reporting period. Actual future net cash flows from our natural gas and oil properties also will be affected by factors such as:
 
  •  actual prices we receive for natural gas and oil;
 
  •  actual cost of development and production expenditures;
 
  •  the amount and timing of actual production;
 
  •  supply of and demand for natural gas and oil; and
 
  •  changes in governmental regulations or taxation.
 
The timing of both our production and our incurrence of expenses in connection with the development and production of natural gas and crude oil properties will affect the timing of actual future net cash flows from proved reserves, and thus their actual present value. In addition, the 10% discount factor we use when calculating discounted future net cash flows may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the oil and gas industry in general.
 
 
Our future natural gas and oil reserves and production, and therefore our cash flow and income, are highly dependent on our success in efficiently developing and exploiting our current reserves and economically finding or acquiring additional recoverable reserves. We may not be able to develop, find or acquire additional reserves to replace our current and future production at acceptable costs.
 
 
As of December 31, 2008, only 1,514 of our 7,931 identified potential future well locations were attributed proved undeveloped reserves. These potential drilling locations, including those without proved undeveloped reserves, represent a significant part of our growth strategy. Our ability to drill and develop these locations is subject to a number of uncertainties, including the availability of capital, seasonal conditions, regulatory approvals, natural gas and oil prices, costs and drilling results. Because of these uncertainties, we do not know if the numerous potential drilling locations we have will ever be drilled or if we will be able to produce natural gas or oil from these or any other potential drilling locations. As such, our actual drilling activities may materially differ from our current expectations, which could adversely affect our business.
 
 
We describe some of our current prospects and drilling locations and our plans to explore those prospects and drilling locations in this report. A prospect is a property on which we have identified what our geoscientists believe, based on available seismic and geological information, to be indications of natural gas or oil. Our prospects and


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drilling locations are in various stages of evaluation, ranging from a prospect that is ready to drill to a prospect that will require substantial additional seismic data processing and interpretation.
 
The use of seismic data and other technologies and the study of producing fields in the same area will 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, we may damage the potentially productive hydrocarbon bearing formation or experience mechanical difficulties while drilling or completing the well, resulting in a reduction in production from the well or abandonment of the well. During 2008, we participated in drilling a total of 454 gross wells, of which eight were identified as dry holes. If we drill additional wells that we identify as dry holes in our current and future prospects, our drilling success rate may decline and materially harm our business. In sum, the cost of drilling, completing and operating any well is often uncertain, and new wells may not be productive.
 
 
Our reviews of properties we acquire are inherently incomplete because an in-depth review of every individual property involved in each acquisition generally is not feasible. Even a 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, we often 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 our results of operations and financial condition.
 
 
Approximately 54.8% of the estimated proved reserves that we owned or had under lease in the WTO as of December 31, 2008 were proved undeveloped reserves and 56.3% of our total reserves were proved undeveloped reserves. Development of these reserves may take longer and require higher levels of capital expenditures than we currently anticipate. Therefore, ultimate recoveries from these fields may not match current expectations. Delays in the development of our reserves or increases in costs to drill and develop such reserves will reduce the PV-10 value of our estimated proved undeveloped reserves and future net revenues estimated for such reserves.
 
 
As of December 31, 2008, approximately 62% of our proved reserves and approximately 55% of our production were located in the WTO. In addition, a substantial portion of our WTO natural gas contains a high concentration of CO2 and requires treating. As a result, we may be disproportionately exposed to the impact of delays or interruptions of production from these wells caused by transportation and treatment capacity constraints, curtailment of production or treatment plant closures for scheduled maintenance or unanticipated occurrences. Such delays or interruptions could have a material adverse effect on our financial condition and results of operations.
 
 
The reservoirs of many of our 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 we cannot obtain sufficient capacity at treatment facilities for our natural gas with a high CO2 concentration, or if the cost to obtain such capacity significantly increases, we could be forced to delay production and development or experience increased production costs. We do not know the amount of CO2 we will encounter in any well until it is drilled. As a result, sometimes we encounter CO2 levels in our wells that are higher than expected. Since the treatment expenses are incurred on a Mcf basis, we will incur a higher effective treating cost per MmBtu of natural gas sold for natural


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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 we treat 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 our plant shrink has been approximately 12% in the WTO. After giving effect to plant shrink, as many as 4 Mcf of high CO2 natural gas must be produced to sell one MmBtu of natural gas. We report our volumes of natural gas reserves and production net of CO2 volumes that are removed prior to sales.
 
 
Companies to which we provide drilling and related services are affected by the oil and gas industry risks mentioned above. Market prices of natural gas and oil, limited access to capital and reductions in capital expenditures could result in oil and gas companies canceling or curtailing their drilling programs, which could reduce the demand for our drilling and related services. Any prolonged reduction in the overall level of exploration and development activities, whether resulting from changes in natural gas and oil prices or otherwise, could impact our drilling and services segment by negatively affecting:
 
  •  revenues, cash flow and profitability;
 
  •  our ability to retain skilled rig personnel whom we would need in the event of an upturn in the demand for drilling and related services; and
 
  •  the fair value of our rig fleet.
 
 
The profitability of our midstream business is materially impacted by the volume of natural gas we gather, transport and treat at our facilities. Most of the reserves supporting our midstream assets are operated by our exploration and production segment. A material decrease in natural gas production in our areas of operation would result in a decline in the volume of natural gas delivered to our pipelines and facilities for gathering, transporting and treating. We have 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. Failure to connect new wells to our gathering systems would result in the amount of natural gas we gather, transport and treat being reduced substantially over time and could, upon exhaustion of the current wells, cause us to abandon our gathering systems and, possibly cease gathering, transporting and treating operations. Our ability to connect to new wells will be dependent on the level of drilling activity in our areas of operations and competitive market factors. Because of our reduced capital expenditures budget for 2009, we expect that we will connect fewer new wells in the near future, which in turn may result in our midstream assets handling lower natural gas volumes than previously projected. Any material decrease in the volume of natural gas handled by our midstream assets would reduce our revenues, operating income and cash flows.
 
Our use of 2-D and 3-D seismic data is subject to interpretation and may not accurately identify the presence of natural gas and oil. In addition, the use of such technology requires greater predrilling expenditures, which could adversely affect the results of our drilling operations.
 
A significant aspect of our 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 our professionals.


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In addition, the use of 2-D and 3-D seismic and other advanced technologies requires greater predrilling expenditures than traditional drilling strategies, and we could incur losses due to such expenditures. As a result, our drilling activities may not be geologically successful or economical, and our overall drilling success rate or our drilling success rate for activities in a particular area may not improve.
 
We often gather 2-D and 3-D seismic data over large areas. Our interpretation of seismic data delineates for us those portions of an area that we believe are desirable for drilling. Therefore, we may choose not to acquire option or lease rights prior to acquiring seismic data, and in many cases, we may identify hydrocarbon indicators before seeking option or lease rights in the location. If we are not able to lease those locations on acceptable terms, we will have made substantial expenditures to acquire and analyze 2-D and 3-D data without having an opportunity to attempt to benefit from those expenditures.
 
 
Our drilling and operating activities are subject to many risks, including the risk that we will not discover commercially productive reservoirs. Drilling for natural gas and oil can be unprofitable if dry holes are drilled and if productive wells do not produce sufficient revenues to return a profit. In addition, our drilling and producing operations may be curtailed, delayed or canceled as a result of other factors, including:
 
  •  unusual or unexpected geological formations and miscalculations;
 
  •  pressures;
 
  •  fires;
 
  •  blowouts;
 
  •  loss of drilling fluid circulation;
 
  •  title problems;
 
  •  facility or equipment malfunctions;
 
  •  unexpected operational events;
 
  •  shortages of skilled personnel;
 
  •  shortages or delivery delays of equipment and services;
 
  •  compliance with environmental and other regulatory requirements; and
 
  •  adverse weather conditions.
 
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, pollution, environmental contamination or loss of wells and regulatory fines or penalties.
 
Insurance against all operational risks is not available to us. Additionally, we may elect not to obtain insurance if we believe that the cost of available insurance is excessive relative to the perceived risks presented. We could incur losses for uninsurable or uninsured risks or in amounts in excess of existing insurance coverage. The occurrence of an event that is not covered in full or in part by insurance could have a material adverse impact on our business activities, financial condition and results of operations.
 
 
Market conditions or a lack of satisfactory natural gas and oil transportation arrangements may hinder our access to natural gas and oil markets or delay our production. The availability of a ready market for our natural gas and oil production depends on a number of factors, including the demand for and supply of natural gas and oil and the proximity of reserves to pipelines and terminal facilities. Our ability to market our production depends, in


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substantial part, on the availability and capacity of gathering systems, pipelines and treating facilities. For example, we are currently experiencing capacity limitations on high CO2 gas treating in the Piñon Field. Our failure to obtain such services on acceptable terms or expand our midstream assets could have a material adverse effect on our business. We 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. We would be unable to realize revenue from any shut-in wells until production arrangements were made to deliver the production to market.
 
 
The natural gas and oil industry is capital intensive. We make and expect to continue to make substantial capital expenditures in our business and operations for the exploration, development, production and acquisition of natural gas and oil reserves. To date, we have financed capital expenditures primarily with proceeds from the sale of equity, debt and cash generated by operations. We intend to finance our future capital expenditures with the sale of equity, asset sales, cash flow from operations and current and new financing arrangements. Our cash flow from operations and access to capital are subject to a number of variables, including:
 
  •  our proved reserves;
 
  •  the level of natural gas and oil we are able to produce from existing wells;
 
  •  the prices at which natural gas and oil are sold; and
 
  •  our ability to acquire, locate and produce new reserves.
 
If our revenues decrease as a result of lower natural gas and oil prices, operating difficulties, declines in reserves or for any other reason, we may have limited ability to obtain the capital necessary to sustain our operations at current levels. In order to fund our capital expenditures, we may seek additional financing. Our senior credit facility and senior note indentures, however, contain covenants restricting our ability to incur additional indebtedness without the consent of the lenders. Our lenders may withhold this consent at their sole discretion.
 
Continuing disruptions in the global financial and capital markets also could adversely affect our ability to obtain debt or equity financing on terms favorable to us, or at all. The failure to obtain additional financing could result in a curtailment of our operations relating to exploration and development of our prospects, which in turn could lead to a possible loss of properties and a decline in our natural gas and oil reserves.
 
 
Our senior credit facility and senior notes restrict our ability to obtain additional financing, make investments, lease equipment, sell assets and engage in business combinations. We also are required to comply with certain financial covenants and ratios. Our ability to comply with these restrictions and covenants in the future is uncertain and will be affected by the levels of cash flow from our operations and events or circumstances beyond our control. If commodity prices remain at their current level for an extended period or continue to decline, this could adversely affect our ability to meet covenants. Our 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 facilities, which could cause all of our existing indebtedness to be immediately due and payable.
 
Our senior credit facility limits the amounts we 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 our request, but are limited to two requests per year. The borrowing base is determined based upon proved developed producing reserves, proved developed non-producing reserves, and proved undeveloped reserves. Outstanding borrowings in excess of the borrowing base must be repaid immediately, or we must pledge other natural gas and crude oil properties as additional collateral. We do not currently have any substantial unpledged properties, and we may not have the financial resources in the future to make any mandatory principal prepayments required under the senior credit


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facility. If the indebtedness under our senior credit facility and senior notes were to be accelerated, our assets may not be sufficient to repay such indebtedness in full.
 
 
To achieve a more predictable cash flow and to reduce our exposure to adverse fluctuations in the prices of natural gas and oil, we currently, and may in the future, enter into derivative contracts for a portion of our natural gas and oil production, including collars, basis swaps and fixed-price swaps. As of December 31, 2008, we had natural gas and crude oil derivative contracts, excluding basis swaps, of 79.8 Bcfe at an average price of $8.60 per Mcfe in place for 2009 and 68.4 Bcfe at an average price of $7.77 per Mcfe in place for 2010. The Company also had natural gas basis swaps in place through 2011 for 125.9 Bcf at an average price of $0.73 per Mcf. We have not designated any of our derivative contracts as hedges for accounting purposes and record all derivative contracts on our balance sheet at fair value. Changes in the fair value of our derivative contracts are recognized in current period earnings. Accordingly, our earnings may fluctuate significantly as a result of changes in fair value of our derivative contracts. Derivative contracts also expose us 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.
 
In addition, these types of derivative contracts limit the benefit we would receive from increases in the prices for natural gas and oil.
 
 
The oil and gas industry is intensely competitive, and we compete with companies that have greater resources than we do. Many of these companies not only explore for and produce natural gas and oil, but also carry on refining operations and market petroleum and other products on a regional, national or worldwide basis. These companies may be able to pay more for productive natural gas and crude oil properties and exploratory prospects or identify, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit. In addition, these companies may have a greater ability to continue exploration activities during periods of low natural gas and oil market prices. Our larger competitors may be able to absorb the burden of present and future federal, state, local and other laws and regulations more easily than we can, which would adversely affect our competitive position. Our ability to acquire additional properties and to discover reserves in the future will be dependent upon our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. In addition, because we have fewer financial and human resources than many companies in our industry, we may be at a disadvantage in bidding for exploratory prospects and producing natural gas and crude oil properties. See “Business — Competition” in Item 1 of this report.
 
Downturns in natural gas and oil 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.
 
 
Our natural gas and oil exploration, production, transportation and treatment operations are subject to complex and stringent laws and regulations. In order to conduct our operations in compliance with these laws and regulations, we must obtain and maintain numerous permits, approvals and certificates from various federal, state and local governmental authorities. We may incur substantial costs in order to maintain compliance with these existing laws and regulations. In addition, our costs of compliance may increase if existing laws and regulations are revised or reinterpreted, or if new laws and regulations become applicable to our operations. For instance, we may be unable to obtain all necessary permits, approvals and certificates for proposed projects. Alternatively, we may have to incur substantial expenditures to obtain, maintain or renew authorizations to conduct existing projects. If a


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project is unable to function as planned due to changing requirements or public opposition, we may suffer expensive delays, extended periods of non-operation or significant loss of value in a project. All such costs may have a negative effect on our business and results of operations.
 
Our business is subject to federal, state and local laws and regulations as interpreted and enforced by governmental agencies and other bodies vested with authority relating to the exploration for, and the development, production and transportation of, natural gas and oil. Failure to comply with such laws and regulations, as interpreted and enforced, could have a material adverse effect on us. For instance, the MMS may suspend or terminate our operations on federal leases for failure to pay royalties or comply with safety and environmental regulations.
 
 
We may incur substantial costs and liabilities as a result of environmental, health and safety requirements applicable to our natural gas and oil exploration, development, production, transportation, treatment, and other activities. These costs and liabilities could arise under a wide range of environmental, health and safety laws that cover, among other things, emissions into the air and water, habitat and endangered species protection, the containment and disposal of hazardous substances, oil field waste and other waste materials, the use of underground injection wells, and wetlands protection. These laws and regulations are complex, change frequently and have tended to become increasingly strict over time. Failure to comply with environmental, health and safety laws or regulations may result in assessment of administrative, civil, and criminal penalties, imposition of cleanup and site restoration costs and liens, and the issuance of orders enjoining or limiting our current or future operations. Compliance with these laws and regulations also increases the cost of our operations and may prevent or delay the commencement or continuance of a given operation. Specifically, we may incur increased expenditures in the future in order to maintain compliance with laws and regulations governing emissions of air pollutants from our natural gas treatment plants. See “Business — Environmental Regulations” in Item 1 of this report.
 
Certain environmental laws impose strict joint and several liability that may require us to remediate our contaminated properties regardless of whether such contamination resulted from the conduct of others or from consequences of our own actions that were or were not in compliance with all applicable laws at the time those actions were taken. In addition, claims for damages to persons, property or natural resources may result from environmental and other impacts of our operations. Moreover, new or modified environmental, health or safety laws, regulations or enforcement policies could be more stringent and impose unforeseen liabilities or significantly increase compliance costs. Therefore, the costs to comply with environmental, health or safety laws or regulations or the liabilities incurred in connection with such compliance could significantly and adversely affect our business, financial condition or results of operations. In addition, many countries as well as several states and regions of the United States have begun implementing legal measures to reduce emissions of “greenhouse gases,” including carbon dioxide and methane, a primary component of natural gas, in response to scientific studies suggesting that these gases may be contributing to the warming of the Earth’s atmosphere. On the United States federal level, President Obama has expressed support for, and it is anticipated that the current session of Congress will consider legislation to restrict or regulate emissions of greenhouse gases. Regulation of greenhouse gases could adversely impact some of our operations and demand for some of our services or products in the future. See “Business — Environmental Regulations” in Item 1 of this report.
 
 
There are significant risks associated with the construction, operation and performance of a project like the Century Plant. There are a limited number of firms and individuals with the expertise and experience necessary to complete construction projects of this size and nature. There is no assurance that the materials necessary for construction of the plant will be in ready supply when we need them or delivered to us on a timely basis. Accordingly, we may not be able to complete construction of the Century Plant within the time frame currently anticipated, and we could experience cost overruns that will not be covered by Occidental under our contract with Occidental. Finally, there is no guaranty that, once the Century Plant is constructed, we will be able to find, produce


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and deliver enough high CO2 gas to satisfy our delivery obligations to Occidental or that the Century Plant will operate at its designed capacity or otherwise perform as anticipated.
 
 
Management is responsible for establishing and maintaining adequate internal control over financial reporting. Our 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 our 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 us to provide reliable financial reports and effectively prevent material fraud. If we cannot provide reliable financial reports or prevent fraud, our reputation and operating results would be harmed. Our efforts to develop and maintain our internal controls may not be successful, and we may be unable to maintain adequate controls over our 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 or other effective improvement of our internal controls could harm our operating results. Ineffective internal controls could also cause investors to lose confidence in our reported financial information.
 
Item 1B.   Unresolved Staff Comments
 
None.
 
Item 2.   Properties
 
Information regarding our properties is included in Item 1 and in Note 6 of the notes to our consolidated financial statements included in Item 8 of this report.
 
Item 3.   Legal Proceedings
 
SandRidge is a defendant in lawsuits from time to time in the normal course of business. In management’s opinion, we are not currently involved in any legal proceedings that, individually or in the aggregate, could have a material effect on our financial condition, operations or cash flows.
 
Item 4.   Submission of Matters to a Vote of Security Holders
 
Not applicable.


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Item 5.   Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
 
 
Our common stock is listed on the New York Stock Exchange (“NYSE”) under the symbol “SD.” The range of high and low sales prices for our common stock for the period from November 6, 2007, when trading of our common stock commenced, through December 31, 2008 as reported by the NYSE, is as follows:
 
                 
    High     Low  
 
2007
               
Fourth Quarter (from November 6, 2007 through December 31, 2007)
  $ 36.11     $ 29.53  
2008
               
First Quarter
  $ 41.05     $ 28.50  
Second Quarter
  $ 69.00     $ 37.88  
Third Quarter
  $ 69.41     $ 17.46  
Fourth Quarter
  $ 19.54     $ 4.85  
 
On February 20, 2009, the closing sales price for our common stock was $6.44.
 
On February 20, 2009, there were 263 record holders of our common stock.
 
We have neither declared nor paid any cash dividends, and we do not anticipate declaring any dividends on our common stock in the foreseeable future. We expect to retain our cash for the operation and expansion of our business, including exploration, development and production activities. In addition, the terms of our indebtedness restrict our ability to pay dividends to holders of our common stock. Accordingly, if our dividend policy were to change in the future, our ability to pay dividends would be subject to these restrictions and our then-existing conditions, including our results of operations, financial condition, contractual obligations, capital requirements, business prospects and other factors deemed relevant by our board of directors.
 
Issuer Purchases of Equity Securities
 
As part of our incentive compensation program, we make required tax payments on behalf of employees as their restricted stock awards vest and then withhold a number of vested shares having a value on the date of vesting equal to the tax obligation. The shares withheld are recorded as treasury stock. During the quarter ended December 31, 2008, the following shares of common stock were withheld in satisfaction of tax withholding obligations arising from the vesting of restricted stock:
 
                                 
                Total Number of
    Maximum Number
 
                Shares Purchased
    of Shares that May
 
                as Part of Publicly
    Yet Be Purchased
 
    Total Number of
    Average Price
    Announced Plans
    Under the Plans or
 
Period
  Shares Purchased     Paid per Share     or Programs     Programs  
 
October 1, 2008-October 31, 2008
    47     $ 10.70       N/A       N/A  
November 1, 2008-November 30, 2008
    1,341     $ 10.09       N/A       N/A  
December 1, 2008-December 31, 2008
    283     $ 8.19       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, our selected financial information. Our financial information is derived from our audited consolidated financial statements for such periods. The financial data includes the results of the acquisition of NEG Oil & Gas, LLC (“NEG”), effective November 21, 2006. 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 our consolidated financial statements and notes thereto contained in Item 8 of this report. The following information is not necessarily indicative of our future results.
 
                                         
    Years Ended December 31,  
    2008     2007     2006     2005     2004  
    (In thousands, except per share data)  
 
Statement of Operations Data:
                                       
Revenues
  $ 1,181,814     $ 677,452     $ 388,242     $ 287,693     $ 175,995  
Expenses:
                                       
Production
    159,004       106,192       35,149       16,195       10,230  
Production taxes
    30,594       19,557       4,654       3,158       2,497  
Drilling and services
    26,186       44,211       98,436       52,122       26,442  
Midstream and marketing
    186,655       94,253       115,076       141,372       96,180  
Depreciation, depletion and amortization — natural gas and crude oil
    290,917       173,568       26,321       9,313       4,909  
Depreciation, depletion and amortization — other
    70,448       53,541       29,305       14,893       7,765  
Impairment
    1,867,497                          
General and administrative
    109,372       61,780       55,634       11,908       6,554  
(Gain) loss on derivative contracts
    (211,439 )     (60,732 )     (12,291 )     4,132       878  
(Gain) loss on sale of assets
    (9,273 )     (1,777 )     (1,023 )     547       (210 )
                                         
Total operating expenses
    2,519,961       490,593       351,261       253,640       155,245  
                                         
(Loss) income from operations
    (1,338,147 )     186,859       36,981       34,053       20,750  
                                         
Other income (expense):
                                       
Interest income
    3,569       4,694       991       206       56  
Interest expense
    (147,027 )     (117,185 )     (16,904 )     (5,277 )     (1,678 )
Minority interest
    (855 )     276       (296 )     (737 )     (262 )
Income (loss) from equity investments
    1,398       4,372       967       (384 )     (36 )
Other income, net
    1,454       729       118              
                                         
Total other income (expense)
    (141,461 )     (107,114 )     (15,124 )     (6,192 )     (1,920 )
                                         
(Loss) income before income taxes
    (1,479,608 )     79,745       21,857       27,861       18,830  
Income tax (benefit) expense
    (38,328 )     29,524       6,236       9,968       6,433  
                                         
(Loss) income from continuing operations
    (1,441,280 )     50,221       15,621       17,893       12,397  
Income from discontinued operations, net of tax
                      229       451  
Extraordinary gain(1)
                            12,544  
                                         
Net (loss) income
    (1,441,280 )     50,221       15,621       18,122       25,392  
Preferred stock dividends and accretion
    16,232       39,888       3,967              
                                         
(Loss applicable) income available to common stockholders
  $ (1,457,512 )   $ 10,333     $ 11,654     $ 18,122     $ 25,392  
                                         


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    Years Ended December 31,  
    2008     2007     2006     2005     2004  
    (In thousands, except per share data)  
 
Earnings Per Share Information:
                                       
Basic and Diluted
                                       
(Loss) income from continuing operations
  $ (9.26 )   $ 0.46     $ 0.21     $ 0.31     $ 0.22  
Income from discontinued operations, net of income tax
                      0.01       0.01  
Extraordinary gain on acquisition
                            0.22  
Preferred stock dividends
    (0.10 )     (0.37 )     (0.05 )            
                                         
(Loss) income per share (applicable) available to common stockholders
  $ (9.36 )   $ 0.09     $ 0.16     $ 0.32     $ 0.45  
                                         
Weighted average number of common shares outstanding(2):
                                       
Basic
    155,619       108,828       73,727       56,559       56,312  
                                         
Diluted
    155,619       110,041       74,664       56,737       56,312  
                                         
 
 
(1) We recognized an extraordinary gain from the recognition of the excess of fair value over acquisition cost of $12.5 million related to an acquisition we made in 2004.
 
(2) The number of shares has been adjusted to reflect a 281.562-to-1 stock split in December 2005.
 
                                         
    As of December 31,  
    2008     2007     2006     2005     2004  
    (In thousands)  
 
Balance Sheet Data:
                                       
Cash and cash equivalents
  $ 636     $ 63,135     $ 38,948     $ 45,731     $ 12,973  
Property, plant and equipment, net
  $ 3,175,559     $ 3,337,410     $ 2,134,718     $ 337,881     $ 114,818  
Total assets
  $ 3,655,058     $ 3,630,566     $ 2,388,384     $ 458,683     $ 197,017  
Long-term debt
  $ 2,375,316     $ 1,067,649     $ 1,066,831     $ 43,133     $ 59,340  
Redeemable convertible preferred stock(1)
  $     $ 450,715     $ 439,643     $     $  
Total stockholders’ equity
  $ 793,521     $ 1,766,891     $ 649,818     $ 289,002     $ 59,330  
Total liabilities and stockholders’ equity
  $ 3,655,058     $ 3,630,566     $ 2,388,384     $ 458,683     $ 197,017  
 
 
(1) On May 7, 2008, we converted all of our then outstanding redeemable convertible preferred stock into shares of common stock.
 
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 our business, financial condition, results of operations, liquidity and capital resources. This discussion and analysis is provided as a supplement to, and should be read in conjunction with, the 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 following discussion contains forward-looking statements that reflect our future plans, estimates, beliefs and expected performance. The forward-looking statements are dependent upon events, risks and uncertainties that may be outside our control. Our actual results could differ materially from those discussed in these forward-looking statements. Factors that could cause or contribute to such differences include, but are not limited to, market prices for natural gas and crude oil, economic and competitive conditions, regulatory changes, estimates of proved reserves, potential failure to achieve production from development projects, capital expenditures and other

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uncertainties, as well as those factors discussed below and elsewhere in this report, particularly in “Risk Factors” in Item 1A of this report and “Cautionary Statement Concerning Forward-Looking Statements” below, all of which are difficult to predict. In light of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur.
 
 
We are an independent natural gas and crude oil company concentrating on exploration, development and production activities. We are focused on continuing the exploration and exploitation of our significant holdings in the West Texas Overthrust, which we refer to as the WTO, a natural gas prone geological region where we have operated since 1986. The WTO includes the Piñon Field as well as the Allison Ranch, South Sabino, Big Canyon and McKay Creek exploration areas. We also operate interests in the Cotton Valley Trend in East Texas, the Gulf Coast area, the Mid-Continent and the Gulf of Mexico.
 
On November 21, 2006, we acquired all of the outstanding membership interests in NEG for total consideration of approximately $1.5 billion, excluding cash acquired. With core assets in the Val Verde and Permian Basins of West Texas, including overlapping or contiguous interests in the WTO, the NEG acquisition dramatically increased our exploration and production segment operations. In addition to the NEG acquisition, we have completed numerous acquisitions of additional working interests in the WTO during the period from late 2005 through 2008.
 
We currently generate the majority of our revenues, earnings and cash flow from the production and sale of natural gas and crude oil. Our revenues, profitability and future growth depend substantially on prevailing prices for natural gas and crude oil and on our ability to find and economically develop and produce natural gas and crude oil reserves. Prices for natural gas and crude oil fluctuate widely. In order to reduce our exposure to these fluctuations, we enter into derivative commodity contracts for a portion of our anticipated future natural gas and crude oil production. Reducing our exposure to price volatility helps ensure that we have adequate funds available for our capital expenditure programs.
 
We operate businesses that are complementary to our exploration, development and production activities. We own related gas gathering and treating facilities, a gas marketing business and an oil field services business. The extent to which each of these supplemental businesses contributes to our consolidated net income largely is determined by the amount of work each performs for third parties. Revenues and costs related to work performed by our businesses for our own account are eliminated in consolidation and, therefore, do not contribute to our consolidated net income. Our ownership and control of these businesses, however, provide us with operational flexibility and an advantageous cost structure.
 
 
During the second half of 2008, unprecedented levels of volatility in the financial and commodity markets made it necessary for us to reduce and refocus our exploration and development activities, reduce our budget for capital expenditures, explore the potential sale of certain assets and seek additional capital.
 
Private Placement of Convertible Perpetual Preferred Stock.  In January 2009, we commenced and completed a private placement of 2,650,000 shares of a new series of 8.5% convertible perpetual preferred stock to qualified institutional buyers eligible under Rule 144A under the Securities Act. Net proceeds from the offering were approximately $243.9 million after deducting offering expenses of approximately $8.0 million. We used the net proceeds of the offering to repay outstanding borrowings under our senior credit facility and for general corporate purposes.
 
Each share of the convertible perpetual preferred stock has a liquidation preference of $100 and is entitled to an annual dividend of $8.50 payable semi-annually in cash, common stock or any combination thereof, beginning on February 15, 2010. No dividends will accrue or accumulate prior to August 15, 2009. Additionally, each share is initially convertible into 12.48 shares of our common stock, at the holder’s option, at any time on or after April 15, 2009 based on an initial conversion price of $8.01 and subject to customary adjustments in certain circumstances.


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Marketing of Midstream Assets.  In January 2009, we announced our intent to offer for sale certain of our gas gathering and related assets located in the WTO. This process is ongoing as of the date of this filing.
 
2009 Capital Expenditure Budget.  We are introducing a 2009 production guidance range of 110.0 Bcfe to 120.0 Bcfe based on a capital expenditure guidance range of $500.0 million to $700.0 million. Based on the current and anticipated near-term drilling activity and associated expenditures, it is currently expected that full year results will trend toward the lower half of these ranges.
 
Drilling Activity.  We began to decrease the number of rigs running on our properties during December 2008 in preparation for reduced 2009 activity levels. At February 20, 2009, we had 9 rigs running compared to a high of 47 rigs operating in the second quarter of 2008.
 
East Texas/North Louisiana — Haynesville Shale Play:  We control approximately 36,000 acres in the developing Haynesville shale play of East Texas and North Louisiana. We drilled two vertical test wells within the Oakhill field area in Rusk County to evaluate the potential for Haynesville shale production. The initial well had a total of 260 feet of Haynesville shale thickness and tested at a rate of 1.5 MMcfe per day. The second well encountered 288 feet of shale thickness and is awaiting completion.
 
Segment Overview
 
We operate in four related business segments: exploration and production, drilling and oil field services, midstream gas services and other ancillary business activities. Management evaluates the performance of our business segments based on operating income, which is computed as segment operating revenues less operating expenses and depreciation, depletion, amortization and impairment. These measurements provide important information to us about the activity and profitability of our lines of business. Set forth in the table below is financial information regarding each of our business segments.
 


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    Year Ended December 31,  
    2008     2007     2006  
    (In thousands)  
 
Segment revenues:
                       
Exploration and production
  $ 912,496     $ 478,747     $ 106,413  
Drilling and oil field services
    46,991       73,202       138,657  
Midstream gas services
    204,138       107,578       122,892  
Other
    18,189       17,925       20,280  
                         
Total revenues
    1,181,814       677,452       388,242  
Segment operating (loss) income:
                       
Exploration and production
    (1,263,249 )     198,913       17,069  
Drilling and oil field services
    (5,393 )     10,473       32,946  
Midstream gas services
    2,087       6,783       3,528  
Other
    (71,592 )     (29,310 )     (16,562 )
                         
Total operating (loss) income
    (1,338,147 )     186,859       36,981  
Interest income
    3,569       4,694       991  
Interest expense
    (147,027 )     (117,185 )     (16,904 )
Other income (expense)
    1,997       5,377       789  
                         
(Loss) income before income taxes
  $ (1,479,608 )   $ 79,745     $ 21,857  
                         
Production data:
                       
Natural gas (MMcf)
    87,402       51,958       13,410  
Crude oil (MBbls)
    2,334       2,042       322  
Combined equivalent volumes (MMcfe)
    101,405       64,211       15,342  
Average daily combined equivalent volumes (MMcfe/d)
    277.1       175.9       42.0  
Average prices- as reported(1):
                       
Natural gas (per Mcf)
  $ 7.95     $ 6.51     $ 6.19  
Crude oil (per Bbl)(2)
  $ 91.54     $ 68.12     $ 56.61  
Combined equivalent (per Mcfe)
  $ 8.96     $ 7.45     $ 6.60  
Average prices- including impact of derivative contract settlements:
                       
Natural gas (per Mcf)
  $ 7.90     $ 7.18     $ 7.25  
Crude oil (per Bbl)(2)
  $ 88.09     $ 68.10     $ 56.61  
Combined equivalent (per Mcfe)
  $ 8.83     $ 7.98     $ 7.52  
Drilling and oil field services:
                       
Number of operational drilling rigs owned at end of period
    28       25       25  
Average number of operational drilling rigs owned during the period
    27.6       26.0       21.9  
 
 
(1) Prices represent actual average prices for the periods presented and do not give effect to derivative transactions.
 
(2) Includes natural gas liquids.
 
 
We explore for, develop and produce natural gas and crude oil reserves, with a focus on our proved reserves and extensive undeveloped acreage positions in the WTO. We operate substantially all of our wells in our core areas and employ our drilling rigs and other drilling services in the exploration and development of our operated wells and, to a lesser extent, of our non-operated wells.

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The primary factors affecting the financial results of our exploration and production segment are the prices we receive for our natural gas and crude oil production, the quantity of our natural gas and crude oil production and changes in the fair value of commodity derivative contracts we use to reduce the volatility of the prices we receive for our natural gas and crude oil production. Because we are vertically integrated, our exploration and production activities affect the results of our drilling and oil field services and midstream gas services segments, especially in times of weak demand for natural gas and crude oil. Our acquisition of NEG in November 2006 substantially increased our revenues and operating income in our exploration and production segment. As additional acquisitions have further increased our working interest in the WTO, a larger percentage of the work performed by our services segments has been performed for our own account.
 
As of December 31, 2008, we had 2,158.6 Bcfe of estimated net proved reserves with a PV-10 of $2,258.5 million, which is an increase from 1,516.2 Bcfe of estimated net proved reserves with a PV-10 of $3,550.5 million as of December 31, 2007. Our Standardized Measure of Discounted Future Net Cash Flows was $2,220.6 million at December 31, 2008 as compared to $2,718.5 million at December 31, 2007 and $1,440.2 million at December 31, 2006. For a discussion of PV-10 and reconciliation to Standardized Measure of Discounted Net Cash Flows, see “Business — Our Business and Primary Operations — Proved Reserves” in Item 1 of this report. The decrease in PV-10 in 2008 was primarily attributable to lower commodity prices at December 31, 2008 compared to December 31, 2007. The SEC requires public companies utilizing the full cost method of accounting for oil and gas properties to perform a ceiling limitation calculation at the end of each quarterly reporting period. Under SEC guidelines, natural gas and crude oil reserves are calculated based on posted prices on the last day of the reporting period with consideration of price changes only to the extent provided by contractual arrangements. As of December 31, 2008, these prices were $5.71 per Mcf of natural gas and $44.60 per barrel of oil. While the overall estimated reserve quantities assigned to our properties increased from December 31, 2007 to December 31, 2008, prices used to determine the future value of our reserves declined to such an extent as to necessitate a ceiling impairment of $1,855.0 million.
 
 
Exploration and production segment revenues increased to $912.5 million in the year ended December 31, 2008 from $478.7 million in 2007, an increase of 90.6%, as a result of a 57.9% increase in combined production volumes and a 20.3% increase in the average price we received for the natural gas and crude oil we produced. During 2008, we increased natural gas production by 35.4 Bcf to 87.4 Bcf and increased crude oil production by 292 MBbls to 2,334 MBbls. The total combined 37.2 Bcfe increase in production was due primarily to successful drilling in the WTO and an increase in our average working interest in the WTO (96.2% at December 31, 2008 from 93.0% at December 31, 2007). We owned interests in a total of 2,059 producing wells at December 31, 2008 compared to 1,654 producing wells at December 31, 2007.
 
The average price we received for our natural gas production for the year ended December 31, 2008 increased $1.44 per Mcf, or 22.1%, to $7.95 per Mcf from $6.51 per Mcf in 2007. The average price received for our crude oil production increased to $91.54 per Bbl from $68.12 per Bbl in 2007. The average price we received for our natural gas and crude oil production was negatively impacted by the significant decline in natural gas and crude oil prices experienced by the oil and gas industry in the fourth quarter of 2008. The average price received for our natural gas and crude oil production during the first nine months of 2008 was $9.09 per Mcf and $104.73 per Bbl, respectively, compared to the average price received for our natural gas and crude oil production during the fourth quarter of 2008 of $5.01 per Mcf and $51.92 per Bbl, respectively. Including the impact of derivative contract settlements, the effective average price received for natural gas for the year ended December 31, 2008 was $7.90 per Mcf compared to $7.18 per Mcf during 2007. Our crude oil derivative contract settlements decreased our effective price received for crude oil by $3.45 per Bbl to $88.09 per Bbl for the year ended December 31, 2008. For the year ended December 31, 2007, our oil derivative contract settlements had a minimal impact on our effective price received for crude oil, which was $68.10. Our derivative contracts are not designated as hedges and, as a result, 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 natural gas and crude oil production to determine “effective prices”. As of December 31, 2008, we had natural gas and crude oil derivative


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contracts, excluding basis swaps, of 79.8 Bcfe at an average price of $8.60 per Mcfe in place for 2009 and 68.4 Bcfe at an average price of $7.77 per Mcfe in place for 2010. The Company also had natural gas basis swaps in place through 2011 for 125.9 Bcf at an average price of $0.73 per Mcf.
 
For the year ended December 31, 2008, we had an operating loss of $1,263.2 million in our exploration and production segment, compared to operating income of $198.9 million in 2007. The $433.7 million increase in exploration and production segment revenues and $211.4 million net gain on our commodity derivative contracts, of which $224.4 million was unrealized, were offset by a full cost ceiling impairment of $1,855.0 million, a $52.8 million increase in production expenses and a $117.3 million increase in depreciation, depletion and amortization (“DD&A”) on natural gas and crude oil properties due to the increase in production. The full cost ceiling impairment was the result of the decline of the future value of our reserves due to the natural gas and crude oil prices at December 31, 2008 which offset the increase in overall estimated reserve quantities assigned to our properties. Natural gas and crude oil prices were $5.71 per Mcf and $44.60 per Bbl at December 31, 2008 compared to $6.80 per Mcf and $95.98 per Bbl at December 31, 2007. The increase in production expenses was attributable to the increase in the number of operating wells we own and the increase in our average working interests in those wells. DD&A increased due to an increase in our depreciable properties, higher future development costs and increased production.
 
During 2007 and 2008, we entered into natural gas and crude oil swaps and natural gas basis swaps. Given the long-term nature of our investment in the WTO development program, we believe it prudent to enter into natural gas and crude oil swaps and natural gas basis swaps for a portion of our production in order to stabilize future cash inflows for planning purposes. During the year ended December 31, 2008, the exploration and production segment reported a $211.4 million net gain on our commodity derivative contracts ($13.0 million realized loss and $224.4 million unrealized gain) compared to a $60.7 million net gain ($34.5 million realized gain and $26.2 million unrealized gain) in 2007. Unrealized gains or losses on derivative contracts represent the change in fair value of open derivative contracts during the period. The unrealized gain on natural gas and crude oil derivative contracts recorded during the year ended December 31, 2008 was attributable to a decrease in average natural gas and crude oil prices at December 31, 2008 compared to the average natural gas and crude oil prices at December 31, 2007 or the contract price for contracts entered into during 2008.
 
 
For the year ended December 31, 2007, exploration and production segment revenues increased to $478.7 million from $106.4 million in 2006. The increase in 2007 revenues compared to 2006 was attributable to increased production primarily due to acquisitions and successful drilling activity. Production volumes increased to 64.2 Bcfe in 2007 from 15.3 Bcfe in 2006, representing an increase of 48.9 Bcfe, or 318.5%. Average combined prices increased $0.85, or 12.9%, to $7.45 per Mcfe in 2007 compared to $6.60 per Mcfe in 2006.
 
Exploration and production segment operating income increased $181.8 million in 2007 to $198.9 million from $17.1 million in 2006. The $372.4 million increase in exploration and production segment revenues was partially offset by a $71.0 million increase in production expenses and a $147.2 million increase in DD&A. The increase in production expenses was attributable to the additional properties acquired in the NEG acquisition and operating expenses on our new wells. During the year ended December 31, 2007, the exploration and production segment reported a $60.7 million gain on our derivative positions ($34.5 million realized gain and $26.2 million unrealized gain) compared to a $12.3 million net gain ($14.2 million realized gain and $1.9 million unrealized loss) in 2006.
 
 
We drill for our own account primarily in the WTO through our drilling and oil field services subsidiary, Lariat. We also drill wells for other natural gas and crude oil companies, primarily located in the West Texas region. As of December 31, 2008, our drilling rig fleet consisted of 39 operational rigs, 28 of which we owned directly and 11 of which were owned by Larclay. Our oil field services business conducts operations that complement our drilling


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services operation. These services include providing pulling units, trucking, rental tools, location and road construction and roustabout services to us and our subsidiaries as well as to third parties.
 
In 2006, Lariat and its partner, Clayton Williams Energy, Inc. (“CWEI”), formed a limited partnership, Larclay, in which we and CWEI each have a 50% interest. Larclay acquired twelve sets of rig components and other related equipment to assemble into completed land drilling rigs. The drilling rigs were to be used for drilling on CWEI’s prospects or our prospects or for contracting to third parties on daywork drilling contracts. All but one of these rigs have been assembled. Larclay financed the acquisition cost of the rigs with a loan from a third party, secured by the purchased rigs, and a loan from CWEI. In addition, CWEI has guaranteed a portion of the third party debt. Lariat operates the rigs owned by the partnership. If Larclay has an operating shortfall, Lariat and CWEI are obligated to provide loans to the partnership. In April 2008, Lariat and CWEI each made loans of $2.5 million to Larclay under promissory notes. The notes bear interest at a floating rate based on a London Interbank Offered Rate (“LIBOR”) average plus 3.25% (5.1875% at December 31, 2008) as provided in the Larclay partnership agreement. In June 2008, Larclay executed a $15.0 million revolving promissory note with each of Lariat and CWEI. Amounts drawn under each revolving promissory note bear interest at a floating rate based on a LIBOR average plus 3.25% (5.1875% at December 31, 2008) as provided in the Larclay partnership agreement. Lariat and CWEI each advanced $5.0 million to Larclay under the revolving promissory notes during the year ended December 31, 2008. The cash shortfalls that Larclay experienced in 2008 resulted from principal payments due pursuant to its rig loan agreement. As a result of current economic conditions and continued cash shortfalls for Larclay, we have fully impaired both our investment in and notes receivable due from Larclay, resulting in impairment expense of approximately $12.5 million, as of December 31, 2008.
 
Although Lariat’s 50% interest in Larclay affords us access to Larclay’s eleven operational rigs, we do not control Larclay. We account for our investment in Larclay under the equity method of accounting, and, therefore, do not consolidate the results of its operations with ours. Only the activities of our wholly owned drilling and oil field services subsidiaries are included in the financial results of our drilling and oil field services segment. The financial results of our drilling and oil field services segment depend on many factors, particularly the demand for and the price we can charge for our services. We provide drilling services for our account and for others, generally on a daywork, and less often on a turnkey, contract basis. We generally assess the complexity and risks of operations, the on-site drilling conditions, the type of equipment to be used, the anticipated duration of the work to be performed and the prevailing market rates in determining the contract terms we offer.
 
Daywork Contracts.  Under a daywork drilling contract, we provide a drilling rig with required personnel to our customer who supervises the drilling of the well. We are paid based on a negotiated fixed rate per day while the rig is in use. Daywork drilling contracts specify the equipment to be used, the size of the hole and the depth of the well. Under a daywork drilling contract, the customer bears a large portion of the out-of-pocket drilling costs, and we generally bear no part of the usual risks associated with drilling, such as time delays and unanticipated costs. As of December 31, 2008, sixteen of our directly owned rigs were operating under daywork contracts and thirteen of these were working for our account.
 
Turnkey Contracts.  Under a typical turnkey contract, a customer pays us to drill a well to a specified depth and under specified conditions for a fixed price, regardless of the time required or the problems encountered in drilling the well. We provide most of the equipment and drilling supplies required to drill the well. We subcontract for related services such as the provision of casing crews, cementing and well logging. Generally, we do not receive progress payments and are paid only after the well is drilled. As of December 31, 2008, none of our rigs was operating under a turnkey contract.
 
 
Drilling and oil field services segment revenues decreased to $47.0 million for the year ended December 31, 2008 from $73.2 million for the year ended December 31, 2007 resulting in an operating loss of $5.4 million during 2008 compared to operating income of $10.5 million during 2007. Our drilling and oil field services segment records revenues and operating income only on wells drilled for or on behalf of third parties. The portion of drilling costs incurred by our drilling and oil field services segment relating to our ownership interest is capitalized as part of


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our full cost pool. The decline in revenues is primarily attributable to an increase in the number of rigs operating on our properties, an increase in our ownership interest in our natural gas and crude oil properties resulting in decreases in services performed for third parties, and a decline in revenue earned per day by rigs working for third parties during 2008 compared to 2007. During 2008, an average of 24.6 of the 27.6 operational rigs we owned were working for our account compared to an average of 20.0 of the 26.0 operational rigs working for our account during 2007. As a result, during the year ended December 31, 2008, 89.2% of drilling and oil field service segment revenues were generated by work performed on our own account and eliminated in consolidation compared to 72.0% during 2007. Additionally, the average daily rate received per rig working for third parties declined to an average of $14,217 per rig per working day during 2008 from an average of $21,468 per rig per working day during 2007. During the year ended December 31, 2007, two of our rigs working for third parties operated under turnkey contracts, while none of our rigs operated under turnkey contracts during the year ended December 31, 2008. Additionally, the daywork and turnkey contracts in place for 2007 generated higher per day revenue due to higher rates in place for those contracts. The operating loss of $5.4 million in 2008 is attributed to the $12.5 million impairment on the investment in and notes receivable due from Larclay.
 
 
During 2007, our drilling and oil field services segment reported $73.2 million in revenues, a decrease of $65.5 million, or 47.2%, from 2006. Operating income decreased to $10.5 million in 2007 from $32.9 million in 2006. The decline in revenues and operating income is primarily attributable to an increase in the number of rigs operating on our properties and an increase in our ownership interest in our natural gas and crude oil properties. With the NEG acquisition and other WTO property acquisitions during 2007, our average working interest increased to approximately 93% in the wells we operated in the WTO. During the year ended December 31, 2007, 72.0% of drilling and oil field service segment revenues were generated by work performed on our own account and eliminated in consolidation compared to 34.3% in 2006.
 
 
We provide gathering, compression, processing and treating services of natural gas in West Texas, primarily through our wholly owned subsidiary, SandRidge Energy Midstream, Inc. (formerly known as ROC Gas Company, Inc.). Through our gas marketing subsidiary, Integra Energy, we buy and sell natural gas produced from our operated wells as well as third-party operated wells. Gas marketing revenue is one of our largest revenue components; however, gas marketing is a very low-margin business. Substantially all of our marketing fees are billed on a per unit basis. On a consolidated basis, gas purchases and other costs of sales include the total value we receive from third parties for the natural gas we sell and the amount we pay for natural gas, which are reported as midstream and marketing expense. The primary factors affecting our midstream gas services are the quantity of natural gas we gather, treat and market and the prices we pay and receive for natural gas.
 
 
Midstream gas services segment revenues for the year ended December 31, 2008 was $204.1 million compared to $107.6 million in 2007. The increase in midstream gas services revenues is attributable to larger third-party volumes transported and marketed through our gathering systems during 2008 compared to 2007 as well as an overall increase in natural gas prices in 2008 compared to 2007. Operating income generated by our midstream gas services segment decreased $4.7 million in 2008 to $2.1 million from $6.8 million in 2007 due to an increase in depreciation expense attributable to higher carrying values of midstream gathering and treating assets.
 
 
Midstream gas services segment revenues decreased $15.3 million to $107.6 million for the year ended December 31, 2007 from $122.9 million in 2006. The decrease in midstream gas services revenues is attributable to


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the increase in our working interest in the WTO as a result of the NEG and other acquisitions. Operating income increased to $6.8 million in 2007 from $3.5 million in 2006 primarily due to lower gas prices paid.
 
 
Our other segment consists primarily of our CO2 gathering and sales operations and corporate operations. We conduct our CO2 gathering and sales operations through our wholly owned subsidiary, SandRidge CO2, LLC (formerly operated through PetroSource Energy Company, LLC). SandRidge CO2 gathers CO2 from natural gas treatment plants located in West Texas and transports and sells this CO2 for use in tertiary crude oil recovery operations conducted by us and third parties.
 
The operating loss in the other segment was $71.6 million for 2008 compared to $29.3 million for 2007 and $16.6 million for 2006. The increases in operating losses from 2006 through 2008 are primarily attributable to increases in corporate and support staff necessary to accommodate the growth in our exploration and development programs and our production levels during that time.
 
Results of Operations
 
Year Ended December 31, 2008 Compared to the Year Ended December 31, 2007
 
Revenues.  Total revenues increased 74.4% to $1,181.8 million for the year ended December 31, 2008 from $677.5 million in 2007. This increase was due to a $431.1 million increase in natural gas and crude oil sales and $99.8 million increase in midstream and marketing revenues, partially offset by lower revenues in our drilling and services operations.
 
                                 
    Year Ended December 31,              
    2008     2007     $ Change     % Change  
    (In thousands)        
 
Revenues:
                               
Natural gas and crude oil
  $ 908,689     $ 477,612     $ 431,077       90.3 %
Drilling and services
    47,199       73,197       (25,998 )     (35.5 )%
Midstream and marketing
    207,602       107,765       99,837       92.6 %
Other
    18,324       18,878       (554 )     (2.9 )%
                                 
Total revenues
  $ 1,181,814     $ 677,452     $ 504,362       74.4 %
                                 
 
Total natural gas and crude oil revenues increased $431.1 million to $908.7 million for the year ended December 31, 2008, compared to $477.6 million in 2007, primarily as a result of the increase in natural gas and crude oil production volumes and prices received on our production. Total natural gas production increased 68.2% to 87.4 Bcf in 2008 compared to 52.0 Bcf in 2007, while crude oil production increased 14.3% to 2,334 MBbls in 2008 from 2,042 MBbls in 2007. The average price received, excluding the impact of derivative contracts, for our natural gas and crude oil production increased 20.3% in 2008 to a combined equivalent price of $8.96 per Mcfe compared to $7.45 per Mcfe in 2007. The average price we received for our natural gas and crude oil production was negatively impacted by the significant decline in natural gas and crude oil prices experienced by the oil and gas industry in the fourth quarter of 2008.
 
Drilling and services revenues decreased 35.5% to $47.2 million in 2008 compared to $73.2 million in 2007. The decline in revenues is primarily attributable to an increase in the average number of our rigs operating on our properties, the increase in our ownership interest in our natural gas and crude oil properties resulting in decreases in services performed for third parties, and the decline in revenue earned per day by rigs working for third parties. The average daily rate we received per rig working for third parties declined to an average of $14,217 per rig per working day during 2008 from an average of $21,468 per rig per working day during 2007.
 
Midstream and marketing revenues increased $99.8 million, or 92.6%, to $207.6 million for the year ended December 31, 2008, compared to $107.8 million in 2007. This increase is primarily due to larger production volumes transported and marketed for third parties with ownership in our wells or ownership in other wells


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connected to our gathering systems during 2008 compared to 2007. Higher natural gas prices prevalent during the first nine months of 2008 compared to 2007 also contributed to the increase.
 
Operating Costs and Expenses.  Total operating costs and expenses increased to $2,520.0 million during 2008, compared to $490.6 million in 2007, primarily as a result of our full cost ceiling impairment along with increases in our production-related costs, midstream and marketing expenses, general and administrative expenses and depreciation, depletion and amortization. These increases were partially offset by decreases in costs attributable to our drilling and services operations as well as increased gains on commodity derivative contracts.
 
                                 
    Year Ended December 31,              
    2008     2007     $ Change     % Change  
    (In thousands)        
 
Operating costs and expenses:
                               
Production
  $ 159,004     $ 106,192     $ 52,812       49.7 %
Production taxes
    30,594       19,557       11,037       56.4 %
Drilling and services
    26,186       44,211       (18,025 )     (40.8 )%
Midstream and marketing
    186,655       94,253       92,402       98.0 %
Depreciation, depletion, and amortization — natural gas and crude oil
    290,917       173,568       117,349       67.6 %
Depreciation, depletion and amortization — other
    70,448       53,541       16,907       31.6 %
Impairment
    1,867,497             1,867,497       100.0 %
General and administrative
    109,372       61,780       47,592       77.0 %
Gain on derivative contracts
    (211,439 )     (60,732 )     (150,707 )     248.2 %
Gain on sale of assets
    (9,273 )     (1,777 )     (7,496 )     421.8 %
                                 
Total operating costs and expenses
  $ 2,519,961     $ 490,593     $ 2,029,368       413.7 %
                                 
 
Production expense includes the costs associated with our exploration and production activities, including, but not limited to, lease operating expense and treating costs. Production expenses increased $52.8 million to $159.0 million for the year ended December 31, 2008, compared to $106.2 million in 2007, primarily due to increased production from our 2008 drilling activity and the increase in the number of producing wells in which we have a working interest. Production taxes increased $11.0 million, or 56.4%, to $30.6 million for the year ended December 31, 2008, compared to $19.6 million in 2007, primarily as a result of the increase in production and the increased prices received for production during the year ended December 31, 2008. The effect on production taxes of the increased prices received for our production was offset by an increase in production tax exemptions realized during 2008 compared to 2007. As a result, production taxes on a unit-of-production basis remained constant at $0.30 per Mcfe for 2008 and 2007.
 
Drilling and services expenses, which includes operating expenses of the drilling, oil field services and CO2 services companies, decreased $18.0 million, or 40.8%, to $26.2 million in 2008 compared to $44.2 million in 2007, primarily because of the increase in the number and working interest ownership of the wells we drilled for our own account, which resulted in a decrease in services performed for third parties.
 
Midstream and marketing expenses increased $92.4 million, or 98.0%, to $186.7 million in 2008 compared to $94.3 million in 2007, due primarily to the larger production volumes transported and marketed during the year ended December 31, 2008 on behalf of third parties compared to 2007.
 
DD&A for our natural gas and crude oil properties increased to $290.9 million during 2008 from $173.6 million in 2007. Our DD&A per Mcfe increased $0.17 to $2.87 from $2.70 in 2007. The increase is primarily attributable to the increase in our depreciable properties, higher future development costs and increased production. Our production increased 57.9% to 101.4 Bcfe in 2008 from 64.2 Bcfe in 2007.
 
DD&A for our other assets consists primarily of depreciation of our drilling rigs, midstream gathering and compression facilities and other equipment. The $16.9 million increase in DD&A for our other assets was


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attributable primarily to higher carrying costs of our rigs, due to upgrades and retrofitting during 2007, and our midstream gathering and treating assets, due to upgrades made throughout 2007 and 2008. We calculate depreciation of property and equipment using the straight-line method over the estimated useful lives of the assets, which range from 3 to 39 years. Our drilling rigs and related oil field services equipment are depreciated over an average seven-year useful life.
 
At December 31, 2008, we recorded a non-cash impairment charge of $1,855.0 million on our properties as total capitalized costs of our natural gas and crude oil properties exceeded our full cost ceiling limitation. There was no full cost ceiling impairment as of December 31, 2007. The additional impairment expenses related to the impairment of our investment in and notes receivable due from Larclay.
 
General and administrative expenses increased 77.0% to $109.4 million in 2008 from $61.8 million in 2007. The increase was attributable to an increase in corporate salaries and wages, including non-cash stock compensation expense. The increase in corporate salaries is primarily due to the increase in corporate and support staff added to accommodate our growth. As of December 31, 2008, we had 528 corporate employees compared to 335 at December 31, 2007. Included in corporate salaries and wages was non-cash stock compensation expense of $18.8 million in 2008 and $7.2 million in 2007. Corporate salaries and wages were partially offset by capitalized general and administrative expenses of $14.5 million for 2008 and $4.6 million for 2007. In accordance with the full cost method of accounting, we capitalize, into the full cost pool, internal costs that can be directly identified with our acquisition, exploration and development activities and do not include any costs related to production, general corporate overhead or similar activities.
 
Due to the decline in average natural gas and crude oil prices during the second half of 2008, we recorded a gain of $211.4 million ($224.4 million unrealized gain and $13.0 million realized loss) on our derivatives contracts for 2008 compared to a $60.7 million gain ($26.2 million unrealized gain and $34.5 million realized gain) in 2007. The unrealized gain recorded during 2008 was attributable to a decrease in average natural gas prices at December 31, 2008 compared to the average natural gas prices at December 31, 2007 or the various contract dates for contracts entered into during 2008.
 
Other Income (Expense).  Total net other expense increased to $141.5 million for the year ended December 31, 2008 from $107.1 million in 2007. The increase is reflected in the table below.
 
                                 
    Year Ended December 31,              
    2008     2007     $ Change     % Change  
    (In thousands)        
 
Other income (expense):
                               
Interest income
  $ 3,569     $ 4,694     $ (1,125 )     (24.0 )%
Interest expense
    (147,027 )     (117,185 )     (29,842 )     25.5 %
Minority interest
    (855 )     276       (1,131 )     (409.8 )%
Income from equity investments
    1,398       4,372       (2,974 )     (68.0 )%
Other income, net
    1,454       729       725       99.5 %
                                 
Total other income (expense), net
    (141,461 )     (107,114 )     (34,347 )     32.1 %
                                 
(Loss) income before income taxes
    (1,479,608 )     79,745       (1,559,353 )     (1,955.4 )%
Income tax (benefit) expense
    (38,328 )     29,524       (67,852 )     (229.8 )%
                                 
Net (loss) income
  $ (1,441,280 )   $ 50,221     $ (1,491,501 )     (2,969.9 )%
                                 
 
Interest income decreased to $3.6 million in 2008 from $4.7 million in 2007. This decrease was generally due to lower excess cash levels during 2008 compared to 2007.
 
Interest expense increased to $147.0 million, net of $0.4 million of capitalized interest, in 2008, from $117.2 million, net of $2.0 million of capitalized interest, in 2007. The increase in interest expense for 2008 was the result of higher average debt balances outstanding during 2008 compared to 2007. An $8.7 million unrealized loss related to our interest rate swap also contributed to the increase in interest expense for 2008. In March 2007, the


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unamortized debt issuance costs totaling $12.5 million related to our senior bridge facility were expensed resulting in higher interest expense.
 
During the year ended December 31, 2008, we reported income from equity investments of $1.4 million compared to $4.4 million in 2007 due to decreases in profitability experienced by our unconsolidated equity investees, Larclay and Grey Ranch, L.P.
 
We reported an income tax benefit of $38.3 million for the year ended December 31, 2008 compared to income tax expense of $29.5 million in 2007. The 2008 income tax benefit represented an effective income tax rate of 2.6% compared to 37.0% in 2007. The low effective income tax rate associated with the loss before income taxes of $1,479.6 million is predominantly due to a valuation allowance being established against our net deferred tax asset. Our deferred tax position changed from a net deferred tax liability as of December 31, 2007 to a net deferred tax asset as of December 31, 2008 due to the recording of a full cost ceiling impairment of $1,855.0 million. The valuation allowance serves to reduce the tax benefits recognized from the net deferred tax asset to an amount that is more likely than not to be realized based on the weight of all available evidence.
 
Year Ended December 31, 2007 Compared to the Year Ended December 31, 2006
 
Impact of the NEG Acquisition.  The results of operations for the year ended December 31, 2006 include the results of NEG from November 21, 2006. The results of operations for the year ended December 31, 2007 include the NEG acquisition for the full year. Although NEG was principally an exploration and production company, the acquisition affected several of our revenue and expense categories. Revenues and expenses related to our natural gas and crude oil operations increased due to increased production from the acquired NEG properties. Revenues and expenses relating to our drilling and services and midstream and marketing operations decreased due to increased intercompany eliminations as more services were provided on company-owned properties. General and administrative expenses increased due to the addition of new staff. Interest expense increased due to the additional borrowings incurred in conjunction with the NEG acquisition.
 
Revenues.  Total revenues increased 75% to $677.5 million for the year ended December 31, 2007 from $388.2 million in 2006. This increase was due to a $376.4 million increase in natural gas and crude oil sales and was partially offset by lower revenues in our other segments.
 
                                 
    Year Ended December 31,              
    2007     2006     $ Change     % Change  
    (In thousands)        
 
Revenues:
                               
Natural gas and crude oil
  $ 477,612     $ 101,252     $ 376,360       371.7 %
Drilling and services
    73,197       139,049       (65,852 )     (47.4 )%
Midstream and marketing
    107,765       122,896       (15,131 )     (12.3 )%
Other
    18,878       25,045       (6,167 )     (24.6 )%
                                 
Total revenues
  $ 677,452     $ 388,242     $ 289,210       74.5 %
                                 
 
Total natural gas and crude oil revenues increased $376.4 million to $477.6 million for the year ended December 31, 2007, compared to $101.3 million in 2006, primarily as a result of an increase in natural gas and crude oil production volumes. Total natural gas production increased 287% to 52.0 Bcf in 2007 compared to 13.4 Bcf in 2006, while crude oil production increased 534% to 2,042 MBbls in 2007 from 322 MBbls in 2006. The increase was due to the NEG acquisition and our successful drilling in the WTO. The average price received for our natural gas and crude oil production increased 13% in 2007 to $7.45 per Mcfe compared to $6.60 per Mcfe in 2006, excluding the impact of derivative contracts.
 
Drilling and services revenues decreased 47% to $73.2 million in 2007 compared to $139.0 million in 2006. The decline in revenues is primarily attributable to an increase in the number of our rigs operating on our properties and an increase in our ownership interest in our natural gas and crude oil properties.
 
Midstream and marketing revenues decreased $15.1 million, or 12%, with revenues of $107.8 million for the year ended December 31, 2007, compared to $122.9 million in 2006. The NEG acquisition significantly decreased


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our midstream gas services revenues as more gas was transported for our own account. Prior to the acquisition, transportation, treating and processing of gas for NEG was recorded as midstream gas services revenues.
 
Other revenue decreased to $18.9 million during 2007 from $25.0 million in 2006. The decrease was primarily due to the sale of various non-energy related assets to our former President and Chief Operating Officer. Revenues related to these assets are included in the 2006 period prior to their sale in August 2006. This decrease was slightly offset by an increase in revenues generated by our CO2 operations.
 
Operating Costs and Expenses.  Total operating costs and expenses increased to $490.6 million in 2007, compared to $351.3 million in 2006, primarily due to increases in our production-related costs as well as an increase in corporate staff. These increases were partially offset by decreases in costs attributable to our drilling and services and midstream and marketing operations as well as increased gains on derivative instruments.
 
                                 
    Year Ended December 31,              
    2007     2006     $ Change     % Change  
    (In thousands)        
 
Operating costs and expenses:
                               
Production
  $ 106,192     $ 35,149     $ 71,043       202.1 %
Production taxes
    19,557       4,654       14,903       320.2 %
Drilling and services
    44,211       98,436       (54,225 )     (55.1 )%
Midstream and marketing
    94,253       115,076       (20,823 )     (18.1 )%
Depreciation, depletion, and amortization — natural gas and crude oil
    173,568       26,321       147,247       559.4 %
Depreciation, depletion and amortization — other
    53,541       29,305       24,236       82.7 %
General and administrative
    61,780       55,634       6,146       11.0 %
Gain on derivative instruments
    (60,732 )     (12,291 )     (48,441 )     (394.1 )%
Gain on sale of assets
    (1,777 )     (1,023 )     (754 )     (73.7 )%
                                 
Total operating costs and expenses
  $ 490,593     $ 351,261     $ 139,332       39.7 %
                                 
 
Production expenses increased $71.0 million due to increased production from our 2007 drilling activity and the addition of the NEG properties. The remainder of the increase was due to an increase in lease operating expenses due to an increase in the number of wells we operate. Production taxes increased $14.9 million, or 320%, to $19.6 million primarily due to increased natural gas production as a result of our 2007 drilling activity and the addition of the NEG properties in 2006.
 
Drilling and services and midstream and marketing expenses decreased 55% and 18% respectively, during 2007 compared to 2006 primarily because of the increase in the number and working interest ownership of the wells we drilled for our own account.
 
DD&A for our natural gas and crude oil properties increased to $173.6 million during 2007 from $26.3 million in 2006. Our DD&A per Mcfe increased $0.98 to $2.70 from $1.72 in 2006. The increase is primarily attributable to our 2007 capital expenditures and the NEG acquisition, which increased our depreciable properties by the purchase price plus future development costs and also increased production. Our production increased 320% to 64.2 Bcfe from 15.3 Bcfe in 2006.
 
The $24.2 million increase in DD&A for our other assets was due primarily to our increased investments in rigs, other oilfield services equipment and midstream assets. During 2006 and 2007, capital expenditures for drilling rigs, other oilfield services equipment and midstream assets totaled approximately $293.0 million.
 
General and administrative expenses increased 11% to $61.8 million in 2007 from $55.6 million in 2006. The increase was principally attributable to a $17.3 million increase in corporate salaries and wages due to a significant increase in corporate and support staff. As of December 31, 2007, we had 2,227 employees compared to 1,443 at December 31, 2006. The increase in corporate salaries and wages was partially offset by $4.6 million in capitalized general and administrative expenses, a $5.5 million decrease due to a legal settlement recorded in 2006 and a


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$1.6 million decrease in stock compensation expense. During 2006 we settled a legal dispute resulting in an additional loss on the settlement of $5.5 million. As part of a severance package for certain executive officers, the Board of Directors approved the acceleration of vesting of certain stock awards resulting in increased compensation expense recognized during 2006. There were no general and administrative expenses capitalized in 2006.
 
For the year ended December 31, 2007, we recorded a gain of $60.7 million ($26.2 million unrealized gain and $34.5 million realized gain) on our derivative contracts compared to a $12.3 million gain ($1.9 million unrealized loss and $14.2 million realized gain) in 2006. The unrealized gain recorded during 2007 was attributable to a decrease in average natural gas prices at December 31, 2007 as compared to the average natural gas prices at December 31, 2006 or the various contract dates for contracts entered into during 2007.
 
Other Income (Expense).  Total net other expense increased to $107.1 million for the year ended December 31, 2007 from $15.1 million in 2006. The increase is reflected in the table below.
 
                                 
    Year Ended December 31,              
    2007     2006     $ Change     % Change  
    (In thousands)        
 
Other income (expense):
                               
Interest income
  $ 4,694     $ 991     $ 3,703       373.7 %
Interest expense
    (117,185 )     (16,904 )     (100,281 )     593.2 %
Minority interest
    276       (296 )     572       193.2 %
Income from equity investments
    4,372       967       3,405       352.1 %
Other income, net
    729       118       611       517.8 %
                                 
Total other expense, net
    (107,114 )     (15,124 )     (91,990 )     (608.2 )%
                                 
Income before income taxes
    79,745       21,857       57,888       264.8 %
Income tax expense
    29,524       6,236       23,288       373.4 %
                                 
Net income
  $ 50,221     $ 15,621     $ 34,600       221.5 %
                                 
 
Interest income increased to $4.7 million in 2007 from $1.0 million in 2006. This increase was due to interest income from investment of excess cash after the repayment of debt.
 
Interest expense increased to $117.2 million during 2007 from $16.9 million in 2006. This increase was attributable to increased average debt balances. To finance the NEG acquisition, we entered into a $750 million senior credit facility, which had an initial borrowing base of $300 million, and an $850 million senior bridge facility. In March 2007, we repaid the senior bridge facility and expensed the related unamortized debt issuance costs of $12.5 million, which resulted in higher interest expense.
 
During the year ended December 31, 2007 we reported income from equity investments of $4.4 million compared to $1.0 million in 2006. Approximately $1.9 million of the increase was attributable to income from our interest in the Grey Ranch treating plant, which experienced increased profitability due to higher levels of utilization in 2007 compared to 2006. Approximately $1.5 million of the increase was attributable to income from Larclay as all of Larclay’s rigs had been delivered and all but one rig was operational by December 31, 2007.
 
We reported income tax expense of $29.5 million for the year ended December 31, 2007 compared to $6.2 million in 2006. The 2007 income tax expense represented an effective income tax rate of 37.0% compared to 28.5% in 2006. The lower effective income tax rate in 2006 was attributable to favorable percentage depletion deductions during that period.
 
 
 
Our operating cash flow is influenced mainly by the prices that we receive for our natural gas and crude oil production; the quantity of natural gas we produce and, to a lesser extent, the quantity of crude oil we produce; the success of our development and exploration activities; the demand for our drilling rigs and oil field services and the


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rates we receive for these services; and the margins we obtain from our natural gas and CO2 gathering and treating contracts.
 
Debt and equity capital markets experienced adverse conditions during the latter part of 2008. Continued volatility in the capital markets may increase costs associated with issuing debt due to increased interest rates, and may affect our ability to access these markets. Currently, we do not believe our liquidity has been, or in the near future will be, materially affected by recent events in the global financial markets. Nevertheless, we continue to monitor events and circumstances surrounding each of the 27 lenders under our senior credit facility. To date, the only disruption in our ability to access the full amounts available under our senior credit facility was the bankruptcy of Lehman Brothers Commodity Services, Inc. (“Lehman Brothers”), a lender responsible for 0.29% of the obligations under our senior credit facility. We cannot predict with any certainty the impact to us of any further disruptions in the credit markets.
 
Our senior credit facility limits the amounts we can borrow to a borrowing base amount, currently $1.1 billion. 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. We may request up to two unscheduled re-determinations per year. The borrowing base is determined based upon proved developed producing reserves, proved developed non-producing reserves, and proved undeveloped reserves. Our borrowing base is redetermined in April and October of each year based on proved reserves. Our ability to develop properties and changes in commodity prices may affect the borrowing base of our senior credit facility.
 
On November 9, 2007, we completed the initial public offering of our common stock. We sold 32,379,500 shares of our common stock, including 4,170,000 shares sold directly to an entity controlled by our Chief Executive Officer and President. After deducting underwriting discounts of approximately $44.0 million and offering expenses of approximately $3.1 million, we received net proceeds of approximately $794.7 million. The net proceeds were utilized as follows (in millions):
 
         
Repayment of outstanding balance and accrued interest on senior credit facility
  $ 515.9  
Repayment of note payable and accrued interest incurred in connection with recent acquisition
    49.1  
Excess cash to fund capital expenditures
    229.7  
         
Total
  $ 794.7  
         
 
In May 2008, we privately placed $750.0 million of our 8.0% Senior Notes due 2018. We used $478.0 million of the $735.0 million net proceeds received from the offering to repay the total balance outstanding on our senior credit facility. The remaining proceeds were used to fund a portion of our capital expenditures for 2008.
 
As of December 31, 2008, our cash and cash equivalents were $0.6 million, and we had approximately $494.0 million available to be drawn, excluding amounts to be funded by Lehman Brothers, under our senior credit facility based on a borrowing base of $1.1 billion. Amounts outstanding under our senior credit facility at December 31, 2008 totaled $573.5 million. As of December 31, 2008, we had approximately $2.4 billion in total debt outstanding. As of February 20, 2009, the balance outstanding under our senior credit facility was $565.3 million, and $502.2 million was available to be drawn under our senior credit facility after consideration of our $24.5 million in outstanding letters of credit and excluding amounts to be funded by Lehman Brothers.
 
In January 2009, we completed a private placement of 2,650,000 shares of 8.5% convertible perpetual preferred stock to qualified institutional buyers eligible under Rule 144A under the Securities Act. The placement included 400,000 shares of convertible perpetual preferred stock issued upon the full exercise of the initial purchasers’ option to cover over-allotments. Net proceeds from the offering were approximately $243.9 million after deducting offering expenses of approximately $8.0 million. We used the net proceeds of the offering to repay outstanding borrowings under our senior credit facility and for general corporate purposes.
 
Based upon the current level of operations and anticipated growth, we believe our cash flows from operations, current cash and investments on hand, availability under our senior credit facility, proceeds from our private offering of 8.5% convertible perpetual preferred stock and anticipated proceeds from the sale of our midstream assets located in the Piñon Field, together with potential access to the credit markets, will be sufficient to meet our


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capital expenditures budget, debt service requirements and working capital needs for the next 12 months. We have the ability to reduce our capital expenditures budget if cash flows are not available.
 
 
We dedicate and expect to continue to dedicate a substantial portion of our capital expenditure program toward the exploration, development, production and acquisition of natural gas and crude oil reserves.
 
Our capital expenditures, on an accrual basis, by segment for the past three years are summarized below:
 
                         
    Year Ended December 31,  
    2008     2007     2006  
    (In thousands)  
 
Capital Expenditures:
                       
Exploration and production
  $ 1,909,078     $ 1,046,552     $ 170,872  
Drilling and oil field services
    52,869       123,232       89,810  
Midstream gas services
    160,460       63,828       16,975  
Other
    55,440       47,236       28,884  
                         
Capital expenditures, excluding acquisitions
    2,177,847       1,280,848       306,541  
Acquisitions
          116,650       1,054,075  
                         
Total
  $ 2,177,847     $ 1,397,498     $ 1,360,616  
                         
 
For 2009, we have budgeted a range of $500.0 million to $700.0 million for capital expenditures, excluding acquisitions. The majority of our capital expenditures will be discretionary and could be curtailed if our cash flows decline from expected levels or we are unable to obtain capital on attractive terms. We may increase or decrease planned capital expenditures depending on natural gas prices, asset sales and the availability of capital through the issuance of additional long-term debt or equity.
 
 
Our working capital balance fluctuates as a result of the timing and amount of borrowings or repayments under our credit arrangements and changes in the fair value of our outstanding commodity derivative instruments. Absent any significant effects from our commodity derivative instruments, we typically have a working capital deficit or a relatively small amount of positive working capital because our capital spending generally exceeds our cash flows from operations and we generally use excess cash, when available, to pay down borrowings outstanding under our credit arrangements.
 
We maintain access to funds that may be needed to meet capital requirements through our senior credit facility. As of December 31, 2008, we had approximately $494.0 million available to be drawn under our senior credit facility, excluding amounts to be funded by Lehman Brothers. At December 31, 2008, we had a working capital deficit of $46.7 million compared to a deficit of $5.7 million at December 31, 2007. Current assets increased $129.5 million at December 31, 2008, compared to current assets at December 31, 2007, primarily due to a $179.2 million increase in our current derivative contract assets resulting from the decline in natural gas and crude oil market prices compared to the contract prices. Current liabilities increased $170.5 million primarily as a result of an increase of $150.7 million in accounts payable.


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Our cash flows are as follows:
 
                         
    Year Ended December 31,  
    2008     2007     2006  
    (In thousands)  
 
Cash Flows:
                       
Cash flows provided by operating activities
  $ 579,189     $ 357,452     $ 67,349  
Cash flows used in investing activities
    (1,909,443 )     (1,385,581 )     (1,340,567 )
Cash flows provided by financing activities
    1,267,755       1,052,316       1,266,435  
                         
Net (decrease) increase in cash and cash equivalents
  $ (62,499 )   $ 24,187     $ (6,783 )
                         
 
Operating Activities.  Net cash provided by operating activities for the years ended December 31, 2008 and 2007 were $579.2 million and $357.5 million, respectively. The increase in cash provided by operating activities from 2007 to 2008 was primarily due to our $504.4 million increase in revenues as a result of our 57.9% increase in production volumes related to our drilling activities during 2008. These increases were partially offset by increases in midstream and marketing expenses and general and administrative costs such as salaries and wages.
 
Cash flows provided by operating activities increased $290.1 million to $357.5 million in 2007 from $67.3 million in 2006 primarily due to our $34.6 million increase in net income as a result of our approximately 320% increase in production volumes related to the NEG and various other acquisitions as well as our drilling success. Also, contributing to this increase was $34.5 million in realized gains on our derivative contracts. These increases were partially offset by increases in general and administrative costs such as salaries and wages.
 
Investing Activities.  Cash flows used in investing activities increased to $1,909.4 million during 2008 from $1,385.6 million in 2007 due to the expansion of our capital expenditure program in 2008. During 2008, our capital expenditures, excluding capital expenditures accrued at December 31, 2008, were $1,818.7 million in our exploration and production segment, $52.9 million for drilling and oil field services, $131.4 million for midstream gas services and $55.4 million for other capital expenditures.
 
Cash flows used in investing activities increased to $1,385.6 million during 2007 from $1,340.6 million in 2006. During 2006, we acquired NEG for $990.4 million, net of cash received and $231.2 million in common stock. Capital expenditures for property, plant and equipment during 2007 were $1,280.8 million as compared to $306.5 million in 2006 as we expanded our capital expenditure program. During 2007, our capital expenditures were $1,046.6 million in our exploration and production segment, $123.2 million for drilling and oil field services, $63.8 million for midstream gas services and $47.2 million for other capital expenditures.
 
Financing Activities.  Since December 2005, we have used equity issuances and borrowings to supplement our cash flows from operations to fund our growth. Proceeds from borrowings increased to $3,252.2 million for the year ended December 31, 2008 compared to $1,331.5 million for 2007, mainly as a result of our issuance of $750.0 million in 8.0% Senior Notes due 2018 in May 2008. We repaid borrowings of approximately $1,944.5 million during 2008, leaving net borrowings of approximately $1,307.7 million for the year. Our financing activities provided $1,267.8 million in cash for the year ended December 31, 2008 compared to $1,052.3 million for the year ended December 31, 2007.
 
During 2007, we raised $1,114.7 million in equity issuances and had net cash repayments of $0.7 million of debt. Our equity issuances included the November 2007 initial public offering of our common stock yielding net proceeds of $794.7 million and a March 2007 private placement of our common stock, which provided net proceeds of approximately $318.7 million. Proceeds from borrowings were $1,331.5 million during 2007 and we repaid approximately $1,332.2 million, leaving net cash repayments during 2007 of approximately $0.7 million. We used the net proceeds from our term loan and the common stock issuances to repay our senior bridge facility and all of the outstanding borrowings under our senior credit facility. Our financing activities provided $1,052.3 million in cash during 2007 compared to $1,266.4 million in 2006.


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Senior Credit Facility.  On November 21, 2006, we entered into a $750.0 million senior secured revolving credit facility with Bank of America, N.A., as administrative agent. The senior credit facility matures on November 21, 2011 and is available to be drawn on and repaid without restriction so long as we are in compliance with its terms, including certain financial covenants.
 
The senior credit facility bank group consists of 27 financial institutions. The largest commitment from any lender in the syndicate is 6.31% of the facility. The credit agreement for the facility contains various covenants that limit our ability, and the ability of certain of our subsidiaries to grant certain liens; make certain loans and investments; make distributions; redeem stock; redeem or prepay debt; merge or consolidate with or into a third party; or engage in certain asset dispositions, including a sale of all or substantially all of our assets. Additionally, the senior credit facility limits our ability and the ability of certain of our subsidiaries to incur additional indebtedness with certain exceptions, including under the senior notes (as discussed below).
 
On October 3, 2008, Lehman Brothers, a lender under our senior credit facility, filed for bankruptcy. At the time that its parent, Lehman Brothers Holdings, Inc., declared bankruptcy on September 15, 2008, Lehman Brothers elected not to fund its pro rata share, or 0.29%, of borrowings requested by us under the senior credit facility. Accordingly, we do not anticipate that Lehman Brothers will fund its pro rata share of any future borrowing requests. We currently do not expect this reduced availability of amounts under the senior credit facility to impact our liquidity or business operations.
 
The senior credit facility also contains financial covenants, including maintenance of agreed upon levels for the (i) ratio of total funded debt to EBITDAX (as defined in the senior credit facility), which may not exceed 4.5:1.0 calculated using the last four completed fiscal quarters, (ii) ratio of EBITDAX to interest expense plus current maturities of long-term debt, which must be at least 2.5:1.0 calculated using the last four completed fiscal quarters, and (iii) current ratio, which must be at least 1.0:1.0. In the current ratio calculation, as defined in the senior credit facility, any amounts available to be drawn under the senior credit facility are included in current assets, and unrealized assets and liabilities resulting from mark-to-market adjustments on our derivative contracts are disregarded. As of December 31, 2008, we were in compliance with all of the financial covenants under the senior credit facility.
 
The obligations under the senior credit facility are secured by first priority liens on all shares of capital stock of each of our present and future subsidiaries; all of our intercompany debt; and substantially all of our assets, including proved natural gas and crude oil reserves representing at least 80% of the discounted present value (as defined in the senior credit facility) of our proved natural gas and crude oil reserves reviewed in determining the borrowing base for the senior credit facility (as determined by the administrative agent). Additionally, the obligations under the senior credit facility are guaranteed by certain of our subsidiaries.
 
At our election, interest under the senior credit facility is determined by reference to (i) LIBOR plus an applicable margin between 1.25% and 2.00% per annum or (ii) the higher of the federal funds rate plus 0.5% or the prime rate plus, in either case, an applicable margin between 0.25% and 1.00% per annum. Interest is payable quarterly for prime rate loans and at the applicable maturity date for LIBOR loans, except that if the interest period for a LIBOR loan is six months, interest is paid at the end of each three-month period. The average annual interest rate paid on amounts outstanding under our senior credit facility for the year ended December 31, 2008 was 3.82%.
 
The borrowing base of the senior credit facility is subject to review semi-annually; however, the lenders reserve the right to have one additional redetermination of the borrowing base per calendar year. We also may request up to two unscheduled redeterminations per year. The borrowing base is determined based on proved developed producing reserves, proved developed non-producing reserves and proved undeveloped reserves. The borrowing base, as of December 31, 2008, was $1.1 billion. As of December 31, 2008, we had total outstanding indebtedness of $573.5 million under our senior credit facility.
 
Other Indebtedness.  We have financed a portion of our drilling rig fleet and related oil field services equipment through the issuance of notes secured by the equipment. At December 31, 2008, the aggregate outstanding balance of these notes was $33.0 million, with annual fixed interest rates ranging from 7.64% to 8.67%. The notes have a final maturity date of December 1, 2011 and require aggregate monthly installments of


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principal and interest in the amount of $1.2 million. The notes have a prepayment penalty (currently ranging from 1% to 2%) that is triggered if we repay the notes prior to maturity.
 
On November 15, 2007, we entered into a $20.0 million note payable, which is fully secured by one of the buildings and a parking garage located on our property in downtown Oklahoma City, Oklahoma. We purchased the property in July 2007 to serve as our corporate headquarters. The mortgage bears interest at 6.08% per annum and matures on November 15, 2022. Payments of principal and interest in the amount of approximately $0.5 million are due on a quarterly basis through the maturity date. We made payments of principal and interest on this note totaling $0.8 million and $1.2 million, respectively, during 2008.
 
We have financed the purchase of other equipment used in our business. At December 31, 2006, the aggregate outstanding balance on these financings was $4.5 million. We substantially repaid such borrowings during July 2007.
 
8.625% Senior Term Loan and Senior Floating Rate Term Loan.  On March 22, 2007, we issued $1.0 billion principal amount of unsecured senior term loans. A portion of the proceeds of the senior term loans was used to repay the senior bridge facility described below under “— Senior Bridge Facility.” The senior term loans included both a floating rate tranche and fixed rate tranche as described below.
 
The floating rate tranche consisted of a $350.0 million senior term loan at a variable rate with interest payable quarterly and principal due on April 1, 2014. The variable rate term loan bore interest, at our option, at LIBOR plus 3.625% or the higher of (i) the federal funds rate, as defined, plus 3.125% or (ii) a bank’s prime rate plus 2.625%.
 
The fixed rate tranche consisted of a $650.0 million senior term loan at a fixed rate of 8.625% per annum with principal due on April 1, 2015. Under the terms of the fixed rate term loan, interest was payable quarterly and during the first four years interest could be paid, at our option, either entirely in cash or entirely with additional fixed rate term loans.
 
As discussed below, the senior term loans were exchanged pursuant to the senior term loan credit agreement.
 
8.625% Senior Notes Due 2015 and Senior Floating Rate Notes Due 2014.  On May 1, 2008, we completed an offer to exchange the senior term loans for senior unsecured notes with registration rights, as required under the senior term loan credit agreement. We issued $650.0 million of 8.625% Senior Notes due 2015 in exchange for an equal outstanding principal amount of our fixed rate term loan and $350.0 million of Senior Floating Rate Notes due 2014 in exchange for an equal outstanding principal amount of our variable rate term loan. The newly issued senior notes had terms that were substantially identical to those of the exchanged senior term loans. During the third quarter of 2008, we filed a registration statement to enable holders of the notes to exchange them for substantially identical notes that are registered under the Securities Act. All unregistered notes had been exchanged for registered notes by October 27, 2008.
 
In January 2008, we entered into a $350.0 million notional amount interest rate swap agreement with a financial institution that effectively fixed our interest rate on the variable rate term loan at an annual rate of 6.26%. As a result of the exchange of the variable rate term loan to Senior Floating Rate Notes, the interest rate swap is now being used to fix the variable LIBOR interest rate on the Senior Floating Rate Notes at an annual rate of 6.26% through April 2011.
 
We may redeem some or all of the Senior Floating Rate Notes at specified redemption prices on or after April 1, 2009 and may redeem some or all of the 8.625% Senior Notes at specified redemption prices on or after April 1, 2011.
 
We incurred $26.1 million of debt issuance costs in connection with the senior term loans. As the senior term loans were exchanged for senior unsecured notes with substantially identical terms, the remaining unamortized debt issuance costs of the senior term loans are being amortized over the term of the 8.625% Senior Notes and the Senior Floating Rate Notes.
 
8.0% Senior Notes Due 2018.  In May 2008, we privately placed $750.0 million of our unsecured 8.0% Senior Notes due 2018. We used $478.0 million of the $735.0 million net proceeds to repay the total balance outstanding at that time on our senior credit facility. The remaining proceeds were used to fund a portion of our 2008 capital


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expenditure program. The notes bear interest at a fixed rate of 8.0% per annum, payable semi-annually, with the principal due on June 1, 2018. The notes are redeemable, in whole or in part, prior to their maturity at specified redemption prices. The notes became freely tradable on November 17, 2008, 180 days after their issuance, pursuant to Rule 144 under the Securities Act.
 
We incurred $16.0 million of debt issuance costs in connection with the 8.0% Senior Notes. These costs are being amortized over the term of these notes.
 
Debt covenants under the 8.0% Senior Notes as well as the 8.625% Senior Notes and the Senior Floating Rate Notes include financial covenants similar to those of the senior credit facility. The covenants include limitations on the incurrence of indebtedness, payment of dividends, asset sales, certain asset purchases, transactions with related parties and consolidation or merger agreements. As of December 31, 2008, we were in compliance with all of the covenants under all of the senior notes.
 
Senior Bridge Facility.  On November 21, 2006, we entered into an $850.0 million senior unsecured bridge facility in conjunction with our acquisition of NEG. We repaid this facility in full in March 2007 with proceeds from our senior term loans.
 
 
Prior to the conversion of our redeemable convertible preferred stock to common stock during 2008, each holder of our redeemable convertible preferred stock was entitled to quarterly cash dividends at the annual rate of 7.75% of the accreted value, $210 per share, of their redeemable convertible preferred stock. Each share of redeemable convertible preferred stock was convertible into approximately 10.2 shares of common stock at the option of the holder, subject to certain anti-dilution adjustments.
 
During March 2008, holders of 339,823 shares of our redeemable convertible preferred stock elected to convert those shares into 3,465,593 shares of our common stock. In May 2008, we converted the remaining outstanding 1,844,464 shares of our redeemable convertible preferred stock into 18,810,260 shares of our common stock as permitted under the terms of the redeemable convertible preferred stock. These conversions resulted in total charges to retained earnings of $7.2 million in accelerated accretion expense related to the converted redeemable convertible preferred shares. We paid all dividends on our redeemable convertible preferred stock in cash, including $33.3 million in 2007 and $17.6 million in 2008. On and after the conversion date, dividends ceased to accrue and rights of common unit holders to exercise outstanding warrants to purchase shares of redeemable convertible preferred stock terminated.
 
 
A summary of our contractual obligations as of December 31, 2008 is provided in the following table:
 
                                                         
    Payments Due by Year  
                                  After
       
    2009     2010     2011     2012     2013     2013     Total  
    (In thousands)  
 
Long-term debt
  $ 16,532     $ 12,005     $ 580,751     $ 1,051     $ 1,120     $ 1,763,857     $ 2,375,316  
Interest on senior notes(1)
    142,339       142,339       142,339       142,339       142,339       341,647       1,053,342  
Firm transportation
    22,810       36,195       31,320       31,406       25,392       84,688       231,811  
Third-party drilling rig commitments(2)
    15,832       1,234                               17,066  
Dispute settlement payments(3)
    5,000       5,000       5,000                         15,000  
Asset retirement obligations
    275       6,940       1,211       2,911       446       72,989       84,772  
Operating leases and other
    1,533       383       530       497       714       2,281       5,938  
                                                         
Total
  $ 204,321     $ 204,096     $ 761,151     $ 178,204     $ 170,011     $ 2,265,462     $ 3,783,245  
                                                         
 
 
(1) Based on interest rates as of December 31, 2008.


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(2) Drilling contracts with third-party drilling rig operators at specified day rates. All of our drilling rig contracts contain operator performance conditions that allow for pricing adjustments or early termination for operator nonperformance.
 
(3) In January 2007, we settled a royalty interest dispute and agreed to pay five installments of $5 million each, plus interest commencing April 1, 2007. The remaining installments are due on July 1 of each year indicated.
 
In connection with the NEG acquisition, we acquired restricted deposits representing bank trust and escrow accounts required by surety bond underwriters and certain former owners of NEG’s offshore properties. In accordance with MMS requirements, NEG was required to put in place surety bonds or escrow agreements to provide satisfaction of its eventual responsibility to plug and abandon wells and remove structures when certain offshore fields are no longer in use. As part of the agreement with the surety bond underwriter or the former owners of the particular fields, bank trust and escrow accounts were set up and funded based on the terms of the escrow agreements. Certain amounts are required to be paid upon receipt of proceeds from production.
 
During 2007, funds totaling $10.3 million were released from escrow accounts and returned to us. No escrow funds were returned to us during 2008.
 
One of the escrow accounts requires us to deposit additional funds in an escrow account equal to 10% of the net proceeds, as defined, from certain of our offshore properties. During 2008, we deposited approximately $0.8 million in the escrow account.
 
Critical Accounting Policies and Estimates
 
The discussion and analysis of our financial condition and results of operations are based upon our consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States. The preparation of our financial statements requires us to make assumptions and prepare estimates that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities and revenues and expenses. We base our estimates on historical experience and various other assumptions that we believe are reasonable; however, actual results may differ. See “Note 1 — Summary of Organization and Significant Accounting Policies” to the consolidated financial statements included in Item 8 of this report for a discussion of our significant accounting policies.
 
Proved Reserves.  Over 95% of our reserves are estimated on an annual basis by independent petroleum engineers. Estimates of proved reserves are based on the quantities of natural gas and crude oil that geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under existing economic and operating conditions. However, there are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting future revenues, rates of production and timing of development expenditures, including many factors beyond our control. The estimation process is very complex and relies on assumptions and subjective interpretations of available geologic, geophysical, engineering and production data, and the accuracy of reserve estimates is a function of the quality and quantity of available data, engineering and geological interpretation and judgment. In addition, as a result of volatility and changing market conditions, commodity prices and future development costs will change from period to period, causing estimates of proved reserves to change, as well as causing estimates of future net revenues to change. For the years ended December 31, 2008, 2007 and 2006, we revised our proved reserves from prior years’ reports by approximately 452.6 Bcfe, 351.6 Bcfe and 26.6 Bcfe, respectively, due to market prices at the end of the applicable period or production performance indicating more (or less) reserves in place or larger (or smaller) reservoir size than initially estimated or additional proved reserve bookings within the original field boundaries. Estimates of proved reserves are key components of our most significant financial estimates involving our rate for recording depreciation, depletion and amortization and our full cost ceiling limitation. These revisions may be material and could materially affect our future depletion, depreciation and amortization expenses.
 
Method of accounting for natural gas and crude oil properties.  The accounting for our business is subject to special accounting rules that are unique to the oil and natural gas industry. There are two allowable methods of accounting for oil and natural gas business activities: the successful efforts method and the full cost method. We follow the full cost method of accounting. All direct costs and certain indirect costs associated with the acquisition, exploration and development of natural gas and crude oil properties are capitalized. Exploration and development


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costs include dry hole costs, geological and geophysical costs, direct overhead related to exploration and development activities and other costs incurred for the purpose of finding natural gas and crude oil reserves. Amortization of natural gas and crude oil properties is provided using the unit-of-production method based on estimated proved natural gas and crude oil reserves. Sales and abandonments of natural gas and crude oil properties being amortized are accounted for as adjustments to the full cost pool, with no gain or loss recognized, unless the adjustments would significantly alter the relationship between capitalized costs and proved natural gas and crude oil reserves. A significant alteration would not ordinarily be expected to occur upon the sale of reserves involving less than 25% of the reserve quantities of a cost center.
 
Under the successful efforts method, geological and geophysical costs and costs of carrying and retaining undeveloped properties are charged to expense as incurred. Costs of drilling exploratory wells that do not result in proved reserves are charged to expense. Depreciation, depletion, amortization and impairment of oil and natural gas properties are generally calculated on a well by well or lease or field basis versus the aggregated “full cost” pool basis. Additionally, gain or loss is generally recognized on all sales of oil and natural gas properties under the successful efforts method. As a result, our financial statements will differ from companies that apply the successful efforts method since we will generally reflect a higher level of capitalized costs as well as a higher oil and natural gas depreciation, depletion and amortization rate, and we will not have exploration expenses that successful efforts companies frequently have.
 
In accordance with full cost accounting rules, capitalized costs are subject to a limitation. The capitalized cost of natural gas and crude oil properties, net of accumulated depreciation, depletion, and amortization, less related deferred income taxes, may not exceed an amount equal to the present value of future net revenues from proved natural gas and crude oil reserves, discounted at 10% per annum, plus the lower of cost or fair value of unproved properties, plus estimated salvage value, less related tax effects (the “ceiling limitation”). The full cost ceiling limitation is calculated using natural gas and crude oil prices in effect as of the balance sheet date and adjusted for “basis” or location differential, held constant over the life of the reserves. If capitalized costs exceed the ceiling limitation, the excess must be charged to expense. Once incurred, a write-down is not reversible at a later date. At December 31, 2008, total capitalized costs of our natural gas and crude oil properties exceeded our ceiling limitation resulting in a non-cash ceiling impairment of $1,855.0 million.
 
Unevaluated Properties.  The balance of unevaluated properties consists of capital costs incurred for undeveloped acreage, wells and production facilities in progress and wells pending determination, together with capitalized interest costs for these projects. These costs are initially excluded from our amortization base until the outcome of the project has been determined or, generally, until it is known whether proved reserves will or will not be assigned to the property. We assess all items classified as unevaluated property on a quarterly basis for possible impairment or reduction in value. We assess our properties on an individual basis or as a group if properties are individually insignificant. Our assessment includes consideration of the following factors, among others: intent to drill; remaining lease term; geological and geophysical evaluations; drilling results and activity; the assignment of proved reserves; and the economic viability of development if proved reserves are assigned. During any period in which these factors indicate an impairment, the cumulative drilling costs incurred to date for such property and all or a portion of the associated leasehold costs are transferred to the full cost pool and are then subject to amortization. We estimate that substantially all of our costs classified as unproved as of the balance sheet date will be evaluated and transferred within a six-year period from the date of acquisition, contingent on our capital expenditures and drilling program.
 
Asset Retirement Obligations.  Asset retirement obligations represent the estimated future abandonment costs of tangible long-lived assets such as platforms, wells, service assets, pipelines and other facilities. We estimate the fair value of an asset’s retirement obligation in the period in which the liability is incurred, if a reasonable estimate can be made. We employ a present value technique to estimate the fair value of an asset retirement obligation, which reflects certain assumptions, including an inflation rate, our credit-adjusted, risk-free interest rate, the estimated settlement date of the liability and the estimated current cost to settle the liability based on third-party quotes and current actual costs. Changes in timing or to the original estimate of cash flows will result in changes to the carrying amount of the liability.
 
Revenue Recognition and Gas Balancing.  Natural gas and crude oil revenues are recorded when title passes to the customer, net of royalties, discounts and allowances, as applicable. We account for natural gas and crude oil


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production imbalances using the sales method, whereby we recognize revenue on all natural gas and crude oil sold to our customers notwithstanding the fact that its ownership may be less than 100% of the natural gas and crude oil sold. Liabilities are recorded for imbalances greater than our proportionate share of remaining estimated natural gas and crude oil reserves.
 
We recognize revenues and expenses generated from daywork drilling contracts as the services are performed, since we do not bear the risk of completion of the well. Under turnkey contracts, we bear the risk of completion of the well; therefore, revenues and expenses are recognized when the well is substantially completed. Under this method, substantial completion is determined when the well bore reaches the negotiated depth as stated in the contract. The duration of these contracts typically ranges from 20 to 90 days. The entire amount of a loss, if any, is recorded when the loss is determinable. The costs of uncompleted drilling contracts include expenses incurred to date on turnkey contracts, which are still in process at the end of the period.
 
We may receive lump-sum fees for the mobilization of equipment and personnel. Mobilization fees received and costs incurred to mobilize a rig from one market to another are recognized over the term of the related drilling contract. The contract terms typically range from 20 to 90 days.
 
Revenues of our midstream gas services segment are derived from providing supply, transportation, balancing and sales services for producers and wholesale customers on our natural gas pipelines, as well as other interconnected pipeline systems. Midstream gas services are primarily undertaken to realize incremental margins on gas purchased at the wellhead, and provide value-added services to customers. In general, natural gas purchased and sold by our midstream gas business is priced at a published daily or monthly index price. Sales to wholesale customers typically incorporate a premium for managing their transmission and balancing requirements. Revenues are recognized upon delivery of natural gas to customers and/or when services are rendered, pricing is determinable and collectability is reasonably assured.
 
Revenue from sales of CO2 is recognized when the product is delivered to the customer. We recognize service fees related to the transportation of CO2 as revenue when the related service is provided.
 
Property, Plant and Equipment, Net.  Other capitalized costs, including drilling equipment, natural gas gathering and treating equipment, transportation equipment and other property and equipment are carried at cost. Renewals and improvements are capitalized while repairs and maintenance are expensed. Depreciation of drilling equipment is recorded using the straight-line method based on estimated useful lives. Depreciation of other property and equipment is computed using the straight-line method over the estimated useful lives of the assets ranging from 3 to 39 years. 
 
Realization of the carrying value of property and equipment is reviewed for possible impairment whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. Assets are determined to be impaired if a forecast of undiscounted estimated future net operating cash flows directly related to the asset including disposal value if any, is less than the carrying amount of the asset. If any asset is determined to be impaired, the loss is measured as the amount by which the carrying amount of the asset exceeds its fair value. An estimate of fair value is based on the best information available, including prices for similar assets. Changes in such estimates could cause us to reduce the carrying value of property and equipment.
 
When property and equipment components are disposed of, the cost and the related accumulated depreciation are removed from the accounts and any resulting gain or loss is reflected in operations.
 
Income Taxes.  Deferred income taxes are recorded for temporary differences between financial statement and income tax bases. Temporary differences are differences between the amounts of assets and liabilities reported for financial statement purposes and their tax bases. Deferred tax assets are recognized for temporary differences that will be deductible in future years’ tax returns and for operating loss and tax credit carryforwards. Deferred tax assets are reduced by a valuation allowance if it is deemed more likely than not that some or all of the deferred tax assets will not be realized. Deferred tax liabilities are recognized for temporary differences that will be taxable in future years’ tax returns.
 
As of December 31, 2008, we had recorded a full valuation allowance against our net deferred tax asset. Our deferred tax position changed from a net deferred tax liability as of December 31, 2007 to a net deferred tax asset as of December 31, 2008 due to the recording of a full cost ceiling impairment of $1,855.0 million. The valuation


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allowance serves to reduce the tax benefits recognized from the net deferred tax asset to an amount that is more likely than not to be realized based on the weight of all available evidence.
 
Derivative Financial Instruments.  To manage risks related to increases in interest rates and changes in natural gas and crude oil prices, we enter into interest rate swaps and natural gas and crude oil futures contracts.
 
We recognize all of our derivative contracts as either assets or liabilities at fair value. The accounting for changes in the fair value (i.e., gains or losses) of a derivative contract depends on whether it has been designated and qualifies as part of a hedging relationship, and further, on the type of hedging relationship. For those derivative contracts that are designated and qualify as hedging instruments, we designate the hedging instrument, based on the exposure being hedged, as either a fair value hedge or a cash flow hedge. For derivative contracts not designated as hedging instruments, the gain or loss is recognized in current earnings during the period of change. None of our derivatives was designated as a hedging instrument during 2008, 2007 and 2006.
 
 
For a discussion of recently adopted accounting standards, see Note 1 to our consolidated financial statements included in Item 8 of this report.
 
 
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 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 2009 capital expenditures, our liquidity and capital resources, the timing and success of specific projects, outcomes and effects of litigation, claims and disputes, elements of our business strategy and other statements concerning our operations, economic performance and financial condition. Forward-looking statements are generally accompanied by words such as “estimate,” “project,” “predict,” “believe,” “expect,” “anticipate,” “potential,” “could,” “may,” “foresee,” “plan,” “goal” or other words that convey the uncertainty of future events or outcomes. We have based these forward-looking statements on our current expectations and assumptions about future events. These statements are based on certain assumptions and analyses made by us in light of our experience and our perception of historical trends, current conditions and expected future developments as well as other factors we believe are appropriate under the circumstances. The forward-looking statements in this report speak only as of the date of this report; we disclaim any obligation to update or revise these statements unless required by securities law, and we caution you not to rely on them unduly. While our 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:
 
  •  the volatility of natural gas and crude oil prices;
 
  •  uncertainties in estimating natural gas and crude oil reserves;
 
  •  the need to replace the natural gas and crude oil reserves we produce;
 
  •  our ability to execute our growth strategy by drilling wells as planned;
 
  •  the need to drill productive, economically viable natural gas and crude oil wells;
 
  •  risks and liabilities associated with acquired properties;
 
  •  amount, nature and timing of capital expenditures, including future development costs, required to develop the WTO;
 
  •  concentration of operations in the WTO;
 
  •  economic viability of WTO production with high CO2 content;
 
  •  availability of natural gas production for our midstream services operations;


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  •  limitations of seismic data;
 
  •  risks associated with drilling natural gas and crude oil wells;
 
  •  availability of satisfactory natural gas and crude oil marketing and transportation;
 
  •  availability and terms of capital;
 
  •  substantial existing indebtedness;
 
  •  limitations on operations resulting from debt restrictions and financial covenants;
 
  •  potential financial losses or earnings reductions from commodity derivatives;
 
  •  competition in the oil and gas industry;
 
  •  general economic conditions, either internationally or domestically or in the jurisdictions in which we operate;
 
  •  costs to comply with current and future governmental regulation of the oil and gas industry, including environmental, health and safety laws and regulations; and
 
  •  the need to maintain adequate internal control over financial reporting.
 
Item 7A.   Quantitative and Qualitative Disclosures about Market Risk
 
The discussion in this section provides information about the financial instruments we use to manage commodity price and interest rate volatility. All contracts are financial contracts, which are settled in cash and do not require the actual delivery of a commodity quantity to satisfy settlement.
 
Commodity Price Risk.  Our most significant market risk relates to the prices we receive for our natural gas and crude oil production. For example, crude oil prices have declined from a record high of $147.55 per barrel in July 2008 to approximately $33.87 per barrel in December 2008. Meanwhile, natural gas futures prices during 2008 ranged from as high as $14.27 per Mcf in July 2008 to as low as $5.29 per Mcf in December 2008. In light of the historical volatility of these commodities, we periodically have entered into, and expect in the future to enter into, derivative arrangements aimed at reducing the variability of natural gas and crude oil prices we receive for our production. From time to time, we enter into commodity pricing derivative contracts for a portion of our anticipated production volumes depending upon management’s view of opportunities under the then current market conditions. We do not intend to enter into derivative contracts that would exceed our expected production volumes for the period covered by the derivative arrangement. Our current credit agreement limits our ability to enter into derivative transactions to 85% of expected production volumes from estimated proved reserves. Future credit agreements could require a minimum level of commodity price hedging.
 
The use of derivative contracts also involves the risk that the counterparties will be unable to meet their obligations under the contracts. Our derivative contracts are with multiple counterparties to minimize our exposure to any individual counterparty. We currently have seventeen approved derivative counterparties, sixteen of which are lenders under our senior credit facility. We currently have derivative contracts outstanding with twelve of these counterparties. We have no derivative contracts in 2009 and beyond with counterparties outside of those that are also part of our senior credit facility. Lehman Brothers is a counterparty on one of our derivative contracts. Due to the bankruptcy of Lehman Brothers and its parent, Lehman Brothers Holdings, Inc., we did not assign any value to this derivative contract (notional of 7,300 MMcf) at December 31, 2008.
 
We use, and may continue to use, a variety of commodity-based derivative contracts, including collars, fixed-price swaps and basis protection swaps. Our fixed price swap transactions are settled based upon NYMEX prices, and our basis protection swap transactions are settled based upon the index price of natural gas at the Waha hub, a West Texas gas marketing and delivery center. Settlement for natural gas derivative contracts occurs in the production month.
 
While we believe that the natural gas and crude oil price derivative arrangements we enter into are important to our program to manage price variability for our production, we have not designated any of our derivative contracts


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as hedges for accounting purposes. We record all derivative contracts on the balance sheet at fair value, which reflects changes in natural gas and crude oil prices. We establish fair value of our derivative contracts by price quotations obtained from counterparties to the derivative contracts. Changes in fair values of our derivative contracts are recognized as unrealized gains and losses in current period earnings. As a result, our current period earnings may be significantly affected by changes in fair value of our commodities derivative contracts. Changes in fair value are principally measured based on period-end prices compared to the contract price.
 
At December 31, 2008, our open natural gas and crude oil commodity derivative contracts consisted of the following:
 
 
                 
    Notional
    Weighted Avg.
 
Period and Type of Contract
  (MMcf)(1)     Fixed Price  
 
January 2009 — March 2009