UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

 

 

 

 

Form 10-K

 

 

 

 

 

Commission File Number: 1-33784

 

 

 

 

SANDRIDGE ENERGY, INC.

(Exact name of registrant as specified in its charter)

 

 

 

 

 

(405) 429-5500

(Registrant’s telephone number, including area code)

 

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

 

 

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):

 

 

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.

 

DOCUMENTS INCORPORATED BY REFERENCE

 

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

 

TABLE OF CONTENTS

 

 

 

General

 

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.

 

Recent Developments

 

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.

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.

 

Business Strategy

 

Our primary objective is to achieve long-term growth and maximize stockholder value over multiple business cycles by pursuing the following strategies:

 

 

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:

 

 

 

 

West Texas Overthrust (WTO)

 

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.

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:

 

 

 

 

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.

East Texas — Cotton Valley Trend

 

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.

 

Gulf Coast

 

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.

 

Mid-Continent

 

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.

 

Other Areas

 

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.

 

Tertiary Oil Recovery

 

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

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.

 

 

 

 

 

 

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.

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:

 

 

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.

 

 

 

 

 

 

 

 

Productive Wells

 

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.

 

Developed and Undeveloped Acreage

 

The following table sets forth information regarding our developed and undeveloped acreage at December 31, 2008:

 

 

 

 

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.

 

 

 

 

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

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.

 

 

Drilling Rigs

 

The following table sets forth information with respect to the rigs operating on our acreage as of December 31, 2008.

 

 

 

 

Marketing and Customers

 

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.

 

Title to Properties

 

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.

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.

 

Drilling and Oil Field Services

 

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.

 

Drilling Operations

 

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:

 

 

 

 

The table below identifies certain information concerning our drilling rigs as of December 31, 2008:

 

 

 

 

Oil Field Services

 

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.

 

Types of Drilling Contracts

 

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.

 

Our Customers

 

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.

 

Midstream Gas Services

 

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:

 

 

 

 

 

 

 

West Texas

 

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.

 

Other Areas

 

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.

 

Capital Expenditures

 

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.

 

Marketing

 

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

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.

 

Other Operations

 

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.”

 

Competition

 

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.

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.

 

Seasonal Nature of Business

 

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

 

General

 

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:

 

 

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.

 

Comprehensive Environmental Response, Compensation and Liability Act

 

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

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.

 

Waste Handling

 

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.

 

Air Emissions

 

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.

 

Water Discharges

 

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,

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.

 

National Environmental Policy Act

 

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.

 

Future Laws and Regulations

 

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.

 

Anti-Terrorism Measures

 

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.

Other Regulation of the Oil and Gas Industry

 

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.

 

Drilling and 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:

 

 

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.

 

Natural Gas Sales Transportation

 

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

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.

 

Employees

 

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.

 

Offices

 

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.

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.

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

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.

 

 

Natural gas and oil prices are volatile, and a decline in natural gas and oil prices can significantly affect our financial results and impede our growth.

 

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:

 

 

 

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.

 

Volatility in the capital markets could affect the value of certain assets as well as our ability to obtain capital.

 

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.

Future price declines may result in further reductions of the asset carrying values of our natural gas and crude oil properties.

 

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.

 

We have a substantial amount of indebtedness, which may adversely affect our cash flow and our ability to operate our business.

 

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:

 

 

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

 

Our estimated reserves are based on many assumptions that may turn out to be inaccurate. Any significant inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.

 

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

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.

 

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

 

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:

 

 

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.

 

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

 

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.

 

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

 

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

 

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

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.

 

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

 

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.

 

The development of the proved undeveloped reserves in the WTO and other areas of operation may take longer and may require higher levels of capital expenditures than we currently anticipate.

 

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.

 

A significant portion of our operations are located in the WTO, making us vulnerable to risks associated with operating in one major geographic area.

 

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.

 

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

 

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

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.

 

All of our consolidated drilling and services revenues are derived from companies in the oil and gas industry.

 

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:

 

 

A significant decrease in natural gas production in our areas of midstream gas services operations, due to the decline in production from existing wells, depressed commodity prices or otherwise, would adversely affect our revenues and cash flow for our midstream gas services segment.

 

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.

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.

 

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

 

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:

 

 

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

 

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

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.

 

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

 

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:

 

 

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.

 

The agreements governing our existing indebtedness have restrictions, financial covenants and borrowing base redeterminations which could adversely affect our operations.

 

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

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.

 

Our derivative activities could result in financial losses or could reduce our earnings.

 

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:

 

 

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

 

Competition in the oil and gas industry is intense, which may adversely affect our ability to succeed.

 

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.

 

We are subject to complex federal, state, local and other laws and regulations that could adversely affect the cost, manner or feasibility of conducting our operations.

 

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

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.

 

Our operations expose us to potentially substantial costs and liabilities with respect to environmental, health and safety matters.

 

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.

 

The Century Plant may not be constructed, operate or perform as intended.

 

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

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.

 

If we fail to maintain an adequate system of internal control over financial reporting, it could adversely affect our ability to accurately report our results.

 

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.

 

 

None.

 

 

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.

 

 

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.

 

 

Not applicable.

 

 

Price Range of Common Stock

 

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:

 

 

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:

 

 

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.