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) 753-5500

(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.  þ

 

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 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 initial public offering of SandRidge Energy, Inc.’s common stock, par value of $0.001, commenced trading on November 6, 2007. Prior to that date, there was no public market for the registrant’s common stock. At February 28, 2008 there were 142,718,362 shares of our common stock outstanding.

 

DOCUMENTS INCORPORATED BY REFERENCE
(To The Extent Indicated Herein)

 

Portions of the proxy statement for the 2008 Annual Meeting of Shareholders are incorporated by reference in Part III.

 

 

SANDRIDGE ENERGY, INC.

 

2007 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 with our principal focus on exploration, development and production activities. We also own and operate drilling rigs and a related oil field services company operating under the name “Lariat Services, Inc.”; gas gathering, marketing and processing facilities; and, through our wholly-owned subsidiary PetroSource Energy Company, CO₂ treating and transportation facilities and tertiary oil recovery operations. We were originally organized in the State of Texas in 1984 under a predecessor company name and in 2006, we reorganized as a Delaware corporation and adopted the SandRidge Energy, Inc. name.

 

We are focused on expanding the continuing exploration and exploitation of our significant holdings in an area of West Texas that we refer to as the West Texas Overthrust, or “WTO,” a natural gas prone geological region where we have operated since 1986. The WTO includes the Piñon Field, the South Sabino prospect, the Big Canyon prospect and other prospects that we are currently evaluating. We intend to add to our existing reserve and production base in this area by increasing our development drilling activities in the Piñon Field and our exploration program in other prospects that we have identified. We believe that we are the largest operator and producer in the WTO and have assembled the largest acreage position in the area. We also operate significant interests in the Cotton Valley Trend in East Texas, the Gulf Coast area, the Gulf of Mexico, Oklahoma and the Piceance Basin of Colorado.

 

We have assembled an extensive natural gas and oil property base in which we have identified approximately 4,600 potential drilling locations, including approximately 2,600 in the WTO. As of December 31, 2007, our proved reserves were 1,516.2 Bcfe, of which 86% were natural gas. We had 1,654 gross (1,234 net) producing wells, substantially all of which we operate. As of December 31, 2007, we had interests in approximately 1,303,107 gross (822,287 net) natural gas and oil leased acres. We had 30 rigs drilling in the WTO, six rigs drilling in East Texas, two rigs drilling in Oklahoma, and two rigs drilling in other areas as of December 31, 2007.

 

We also operate businesses that are complementary to our primary exploration, development and production activities, which provides us with operational flexibility and an advantageous cost structure. We own a fleet of 32 drilling rigs, three of which are currently being retrofitted. In addition, we are a 50% partner in a limited partnership that owns an additional twelve rigs, eleven of which are currently operational. We own related oil field services businesses, gas gathering and treating facilities and a marketing business. We also capture and supply CO₂ to support our tertiary oil recovery projects undertaken by us or third parties. These assets are primarily located in our primary operating area in West Texas.

 

In November 2007, we completed the initial public offering of our common stock and received net proceeds of $794.7 million. We used the proceeds to repay indebtedness outstanding under our senior credit facility, repay a note related to a recent acquisition and fund a portion of our 2007 and 2008 capital expenditure programs.

 

Our capital expenditures and acquisitions for 2007 of approximately $1,397.4 million included $1,150.6 million for exploration and development (including land and seismic acquisitions and our tertiary recovery operations), $123.2 million for drilling and oil field services, $73.8 million for our midstream operations and $49.8 million for other capital expenditures. Approximately $871.2 million of our 2007 capital expenditures was spent on our Piñon Field development and our exploratory projects in the WTO (including land and seismic acquisitions). We drilled approximately 316 gross (274.7 net) wells in 2007, including approximately 190 gross (177.8 net) wells in the WTO.

 

On November 21, 2006, we acquired all of the outstanding membership interests in NEG Oil & Gas LLC (“NEG”) for total consideration of approximately $1.5 billion, excluding cash acquired. With core assets in the Val Verde and Permian Basins of West Texas, including overlapping or contiguous interests in the WTO, the NEG acquisition dramatically increased our exploration and production segment operations. The NEG acquisition, coupled with numerous acquisitions of additional working interests completed during 2007, 2006 and late 2005, have significantly increased our holdings in the WTO.

 

Our principal executive offices are located at 1601 N.W. Expressway, Suite 1600, Oklahoma City, Oklahoma 73118 and our telephone number is (405) 753-5500. 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. 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. You may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. The SEC maintains an internet site that contains reports, proxy and information statements, and other information regarding us. The SEC’s website address is www.sec.gov.

References to “SandRidge”, “us”, “we”, “Company” and “our” in this report refer to SandRidge Energy, Inc. together with its subsidiaries. “PetroSource” refers to our wholly-owned subsidiary, PetroSource Energy Company and “Lariat” refers to our wholly-owned subsidiary, Lariat Services, Inc.

 

Our Strategy

 

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

 

 

Competitive Strengths

 

We have a number of strengths that we believe will help us successfully execute our 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 and the Gulf Coast area, as well as other non-core operating areas.

 

The following table identifies certain information concerning our exploration and production business as of December 31, 2007 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 and Terrell Counties in West Texas and is associated with the Marathon-Ouachita fold and thrust belt that extends east-northeast across the United States into the Appalachian Mountain Region. The 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 (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 11,000 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 largely under-explored due primarily to the remoteness and lack of infrastructure in the region, as well as historical limitations of conventional subsurface geological and geophysical methods. However, several fields including our prolific Piñon Field have been discovered. We believe our access to and control of the necessary

infrastructure combined with application of modern seismic techniques will allow us to identify further exploration and development opportunities in the WTO.

 

In May 2007, we began a three-year, multi-phase seismic program to acquire 1,400 square miles of modern 3-D seismic data in the WTO. We believe this enhanced 3-D seismic program may identify structural details of potential reservoirs, thus lowering exploratory drilling risk and improving completion efficiency. The first two phases of the seismic program covered 389 square miles and were completed during 2007.

 

We have acquired leasehold acreage in the WTO, tripling our position since January 2006. As of December 31, 2007 we owned 600,546 gross (508,745 net) acres in the WTO, substantially all of which are along the leading edge of the WTO.

 

Piñon Field.  The Piñon Field, located in Pecos County, is our most significant producing field, and accounts for 61% of our proved reserve base as of December 31, 2007 and approximately 76% of our 2007 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 Wolfcamp sands (average depth of 2,500 to 3,500 feet), the Tesnus sands (average depth of 3,700 to 4,750 feet), the Upper Caballos chert (average depth of 5,500 feet), and the Lower Caballos chert (average depth of 7,300 to 10,000 feet).

 

As of December 31, 2007, our estimated proved natural gas and oil reserves in the Piñon Field were 922.2 Bcfe, 55% of which were proved undeveloped reserves. This field has produced more than 266.2 Bcfe through December 31, 2007 and currently produces in excess of 115 net Mmcfe per day.

 

Our interests in the Piñon Field include 471 producing wells as of December 31, 2007. We had a 93% average working interest in the producing area of Piñon Field and were running 30 drilling rigs in the Piñon Field as of December 31, 2007. We drilled 190 wells in the field during 2007. As of December 31, 2007, we have identified approximately 2,600 potential well locations in the Piñon Field, including approximately 400 proved undeveloped drilling locations.

 

West Texas Overthrust Prospects.  Through our regional exploratory efforts, to date we have identified several exploratory prospect areas in the WTO:

 

 

 

 

West Texas Overthrust Development.  The following table provides information concerning development opportunities in the WTO:

 

 

 

 

East Texas — Cotton Valley Trend

 

We own significant natural gas and oil interests in the natural gas bearing Cotton Valley Trend in East Texas, which covers parts of East Texas and northern Louisiana. We held interests in 53,388 gross (32,739 net) acres in East Texas as of December 31, 2007. At December 31, 2007, our estimated net proved reserves in East Texas were 202.5 Bcfe, with net production of approximately 32.7 Mmcfe per day. We intend to target the tight sand reservoirs of the Cotton Valley, Pettit and Travis Peak formations at depths of 6,500 to 10,500 feet. These sands are typically distributed over a large area, which has led to a near 100% 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 as little as 20 acres per well. Recently, operators have begun drilling horizontal wells and we are monitoring their success. We drilled 48 wells (42.0 net wells) in the Cotton Valley Trend in 2007. We currently have 6 rigs running in this region and expect to drill an additional 71 wells during 2008.

 

Gulf Coast

 

We own natural gas and oil interests in 50,768 gross (33,317 net) acres in the Gulf Coast area as of December 31, 2007, which encompasses the large coastal plain from the southernmost tip of Texas through the southern portion of Louisiana. As of December 31, 2007, our estimated net proved reserves in the Gulf Coast area were 97.8 Bcfe, with net production of approximately 42.5 Mmcfe per day. This is a predominantly gas prone, multi-pay, geologically complex area with significant faulting and compartmentalized reservoirs where 3-D seismic and other advanced exploration technologies are critical to our efforts. This area is comprised of sediments ranging from Cretaceous through Tertiary age and is productive from very shallow depths of several thousand feet to depths in excess of 18,000 feet. We target shallower geological formations such as the Frio and the Miocene, as well as deeper horizons such as Wilcox and Vicksburg. Operations in this area are generally characterized as being higher risk and higher potential than in our other core areas, with successful wells typically having higher initial production rates with steeper declines and shorter production lives. Drilling cost per well also tends to be significantly higher than in our other areas due to the increased depth and complexity of wellbore conditions. We drilled three wells in the Gulf Coast in 2007.

 

Other Areas

 

Gulf of Mexico.  We own natural gas and oil interests in 73,614 gross (36,770 net) acres in state and federal waters off the coast of Texas and Louisiana. At December 31, 2007, our estimated net proved reserves were 60.1 Bcfe, with net production of approximately 18.3 Mmcfe per day for the month of December 2007. The water depth ranges from 30 feet to 1,100 feet and activity extends from the coast to more than 100 miles offshore. The Gulf of Mexico is one of the premier producing basins in the United States and is an area where we have achieved value-added growth through exploitation and exploration. Our production will range in depth from several thousand feet to in excess of 17,000 feet. The reservoir rocks range in age from the Plio-Pleistocene through the Oligocene. Typical Gulf of Mexico reservoirs have high porosity and permeability and wells historically flow at prolific rates. Overall, the Gulf of Mexico is known as an area of high quality 3-D seismic acquisition. Our major areas of activity will include the blocks in East Breaks and High Island areas that are located off the Texas coast, and the East Cameron area located off the Louisiana coast. In this area we generally own non-operating interests in blocks operated by larger companies such as Chevron Corporation, BP plc and Apache Corporation. We are currently evaluating our future drilling plans and intend to manage our investment in this area to maximize returns without significantly increasing future capital expenditures.

 

Other West Texas.  Our other non-tertiary West Texas assets include our Brooklaw Field and the Goldsmith Adobe Unit in the Permian Basin. As of December 31, 2007, we own 31,847 gross (22,941 net) acres in these prospects. As of December 31, 2007, our estimated net proved reserves were 38.0 Bcfe. We have identified 77 potential drilling locations in these fields, including 63 proved undeveloped locations, and intend to drill approximately 21 development wells in 2008.

 

Piceance Basin.  The Piceance Basin in northwestern Colorado is a sedimentary basin consisting of multiple productive sandstone formations in one of the country’s most prolific natural gas regions. We entered the Piceance Basin in 1993 with the purchase of leasehold interests predominantly located on federal lands. We acquired this position in order to utilize the experience we had gained in underbalanced drilling and foam fracture simulations in West Texas. Initially, development of these natural gas reserves was limited due to high drilling costs and complex completion requirements. However, new drilling and completion technologies now enable successful development in this area.

 

We are currently evaluating wells we have drilled, but not completed, on the western portion of our acreage block. At December 31, 2007, we had identified 828 potential drilling locations on the eastern portion of our 40,334 gross (15,686 net) acres. We will continue to evaluate our position in 2008 and intend to manage our investment in this area to maximize returns without significantly increasing future capital expenditures.

 

Other.  We own interests in properties in the Arkoma and Anadarko Basins and other areas. As of December 31, 2007, we held interests in 443,546 gross (163,894 net) leasehold and option acres in these areas. During 2007, our acreage in Oklahoma grew to 371,006 gross (121,387 net) acres. As we continue to drill and expand our acreage positions, our Oklahoma prospects may become increasingly important to our Company.

Tertiary Oil Recovery

 

Wellman Unit.  The Wellman Unit is part of our tertiary oil recovery operations. The Wellman Field, located in Terry County, Texas was discovered in 1950 and produces from the Canyon Reef limestone formation of Permian age from an average depth of 9,500 feet. The Wellman Unit is on the western edge of the Horseshoe Atoll, a geologic feature in the northern part of the Midland Basin. There are approximately 110 separate fields that are contained within this feature, including seven existing CO₂ floods. 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 83.7 Mmboe to date. We recently re-initiated injection of CO₂, and our injection rate averaged 10.9 Mmcf per day in 2007 and we expect to reach an average 30.9 Mmcf per day over the next 10 years. As of December 31, 2007, net proved reserves attributable to the Wellman Unit were 9.3 Mmboe. We also own a CO₂ recycling plant at this unit with a capacity of 28 Mmcf per day. The plant includes 6,000 horsepower of CO₂ compression and 4,850 horsepower of processing 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 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 implementing a nine pattern pilot program. CO₂ injection began in December 2007 at 2.0 Mmcf per day. Injection is expected to increase to 15 Mmcf per day by mid-year 2008. As of December 31, 2007, net proved reserves attributable to the George Allen Field were 8.0 Mmboe. As of December 31, 2007, the CO₂ injection rate was 2.0 Mmcf per day.

 

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 ten active CO₂ floods and four more at various stages of readiness. The South Mallet Unit has produced 27.8 Mmboe to date. We are currently evaluating the project for CO₂ development with plans to begin injection of CO₂ in 2009. We expect to reach an injection rate of approximately 18 Mmcf per day by the beginning of 2010. As of December 31, 2007, net proved reserves attributable to the South Mallet Unit were 2.5 Mmboe.

 

Jones Ranch Area.  Several miles west of the George Allen Unit, in Gaines County, PetroSource has acquired various leases in the Jones Ranch Area. These leases produce from various depths and formations from approximately 2,400 gross acres. We are evaluating these leases for both conventional development and tertiary potential.

 

Proved Reserves

 

The following tables present our historical estimated net proved natural gas and oil reserves and the present value of our estimated proved reserves as of December 31, 2007, 2006 and 2005. The PV-10 and Standardized Measure shown in the table are not intended to represent the current market value of our estimated natural gas and oil reserves. At December 31, 2007, approximately 56% of our proved reserves were proved undeveloped reserves. Based on our current drilling schedule, we estimate that 88% of our current proved undeveloped reserves will be developed by 2011 and all of our current proved undeveloped reserves will be developed by 2012.

 

Netherland, Sewell & Associates, Inc., independent oil and gas consultants, have prepared the reports of proved reserves of natural gas and crude oil for our net interest in oil and gas properties, which constitute approximately 89% of our total proved reserves as of December 31, 2007, approximately 92% of our total proved reserves as of December 31, 2006 and 1.5% of our total proved reserves as of December 31, 2005. DeGolyer and MacNaughton prepared the reports of proved reserves for PetroSource (our tertiary oil reserves located in West Texas), which constitute approximately 8% of our total proved reserves as of December 31, 2007, approximately 7% of our total proved reserves as of December 31, 2006 and approximately 98% of our total proved reserves as of December 31, 2005. The remaining 3%, 1% and 0.5% of our proved reserves as of December 31, 2007, 2006 and 2005 were based on internally prepared estimates.

 

 

 

 

 

 

Proved oil and gas reserves are the estimated quantities of crude oil, natural gas, and natural gas liquids which 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.

 

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 which 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 taken into account in our lease operating expenses as processing and gathering fees. In all other areas, natural gas sales are delivered to sales points with CO₂ levels within pipeline specifications and thus are 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, 2007. 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 at December 31, 2007:

 

 

 

 

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. We generally have been able to obtain extensions of the primary terms of our federal leases when we have been unable to obtain drilling permits due to a pending Environmental Assessment, Environmental Impact Statement or related

legal challenge. The following table sets forth as of December 31, 2007 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 should not be considered indicative of future performance, nor should it be assumed that there is necessarily any correlation between the number of productive wells drilled, quantities of reserves found or economic value. Productive wells are those that produce commercial quantities of hydrocarbons, regardless of whether they produce a reasonable rate of return. “Gross” refers to the total wells in which we had a working interest and “net” refers to gross wells multiplied by our working interest.

 

 

At December 31, 2007, we had 40 wells in process.

 

Drilling Rigs

 

The following table sets forth information with respect to the drilling on our acreage as of December 31, 2007.

 

 

 

Marketing and Customers

 

Through Integra Energy, our subsidiary, we market our natural gas production in accordance with standard industry practices. Each month we develop a portfolio of natural gas sales by arranging for a percentage of Integra Energy’s natural gas to be sold on a first of the month index price basis with the remaining volume sold on a daily swing basis at current market rates. Most of the natural gas is sold on a month-to-month basis, and any longer term or evergreen agreements that we are subject to provide pricing provisions that allow us to receive monthly market area based prices. During the year ended December 31, 2007, we sold natural gas to 24 different purchasers.

 

The top five natural gas purchasers of our WTO production for the year ended December 31, 2007 and each company’s approximate percentage of total sales during that period are listed below:

 

 

In light of access to numerous other purchasers through existing pipeline interconnections, we do not believe the loss of any of our major gas purchasers would have a material effect on our business.

 

See Note 21 in the consolidated financial statements included in this report regarding major customers.

 

Title to Properties

 

As is customary in the natural gas and oil industry, we initially conduct only a cursory review of the title to our properties on which we do not have proved reserves. Prior to the commencement of drilling operations on those properties, 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 natural gas and oil industry. Our natural gas and 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

 

We provide drilling and related oil field services to our exploration and production business and to third parties in West Texas.

 

Drilling Operations

 

We drill for our own account in the WTO through our drilling and oil field services subsidiary, Lariat Services, Inc. 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. We have a 50% interest in a limited partnership, Larclay, that owns and operates drilling rigs. We believe that our ownership of drilling rigs and our related oil field services will continue to be a catalyst of our growth. As of December 31, 2007, 22 of our rigs and seven Larclay rigs were working on properties operated by us, and we operated 43 rigs, including eleven of the twelve rigs owned by Larclay. Our rig fleet is designed to drill in our specific areas of operation and have an average horsepower of over 800 and an average depth capacity of greater than 10,500 feet.

 

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 U.S. Due in part to the shortage of experienced drilling employees and various operational challenges, we have deemed it prudent to retrofit five Chinese rigs to a conventional operation. We anticipate the retrofit will be completed in the second quarter of 2008.

The table below identifies certain information concerning our contract drilling operations:

 

 

 

 

The table below identifies certain information concerning our drilling rigs as of December 31, 2007:

 

 

 

 

Oil Field Services

 

Our oil field services business began in 1986 and conducts operations that complement our exploration and production operation. These services include providing pulling units, coiled-tubing units, trucking, location and road construction roustabout services and rental tools to ourselves and to third parties. Less than 28% of our oil field services in 2007 were performed for third parties. We also provide underbalanced drilling systems for our own wells. Our capital expenditures for 2007 related to our oil field services were $123.2 million and we have budgeted approximately $50 million in capital expenditures in 2008 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, footage 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, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Segment Overview — Drilling and Oil Field Services.”

 

Our Customers

 

We perform approximately two-thirds of our drilling services in support of our exploration and production business and approximately one-third with the other operators in West Texas. For the year ended December 31, 2007, we generated revenues of $38.1 million for drilling services performed for third parties, with Mariner Energy, Inc. accounting for $19.0 million of those revenues.

Midstream Gas Services

 

We provide gathering, compression, processing and treating services of natural gas in the TransPecos region of West Texas and the Piceance Basin in Colorado. 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 our primary midstream assets as of December 31, 2007:

 

 

 

 

 

 

 

West Texas

 

In Pecos County, we operate and own the Pike’s Peak gas treating plant, which has the capacity to treat 70 Mmcf per day of 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 above numbers for the Pike’s Peak and Grey Ranch plants are based on a natural gas stream that averages 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. We have access for up to 60 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 367 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, 2007, we currently own and operate approximately 45,000 horsepower of gas compression and anticipate installing an additional 40,000 horsepower in 2008.

 

Other Areas

 

Our Piceance Basin system consists of a 50 Mmcf per day processing plant (Sagebrush) and approximately 53 miles of pipeline gathering systems and approximately 4,400 horsepower of natural gas compression capacity. We gather and transport our natural gas and third-party natural gas to market delivery points on Colorado Interstate Gas Company, Questar Corporation and Rocky Mountain Natural Gas Pipelines.

 

We also own approximately 70 miles of pipeline gathering systems and operate more than 10,000 horsepower of natural gas compression in East Texas and approximately 44 miles of pipeline gathering systems in the Gulf Coast area.

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 2007, we spent approximately $73.8 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 75 Mmcf per day in additional treating capacity. We anticipate adding approximately 80 Mmcf per day in additional treating capacity in 2008. We have budgeted approximately $107 million in 2008 capital expenditures for our midstream and other segments.

 

Marketing

 

Through Integra Energy, our subsidiary, we buy and sell the natural gas and oil production from SandRidge-operated wells and third-party operated wells within our West Texas operations. Through Integra Energy, we purchase and sell residue gas from the Sagebrush plant into Questar Corporation and Colorado Interstate Gas pipelines. 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 market our oil and condensate production in both Texas and Colorado to Shell Trading U.S. Company at current market rates.

 

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 75,000 MmBtu per day of firm transportation service subscribed on the Oasis Pipeline for a portion of our Piñon Field production for 2008.

 

Other Operations

 

Our CO₂ gathering, merchant sales and tertiary oil recovery operations are conducted through PetroSource. PetroSource owns 231 miles of CO₂ pipelines in West Texas with approximately 88,000 horsepower of owned and leased CO₂ compression available with approximately 54,000 horsepower currently operational. In addition, PetroSource has exclusive long-term supply contracts to gather CO₂ from natural gas treatment plants in West Texas and is the sole gatherer of CO₂ from the four natural gas treatment plants located in the Delaware and Val Verde Basins of West Texas. Our CO₂ supply is primarily used in our and third parties’ tertiary oil recovery operations. We have assembled an experienced CO₂ management team, including engineers and geologists with extensive experience in CO₂ flooding with industry leaders.

 

Production from most oil reservoirs includes three distinct phases: primary, secondary and tertiary or enhanced recovery. During primary recovery, the natural pressure of the reservoir or gravity drives oil into the wellbore and artificial lift techniques (such as pumps) produce the oil to the surface. However, only about 10% to 15% of a reservoir’s original oil in place is typically produced during primary recovery. Secondary recovery techniques, most commonly water flooding, often increase ultimate recovery to more than 20% to 45% of the original oil in place. This technique involves injecting water to displace oil and drive it to the wellbore. Even after a water flood, the majority of the original oil in place is still un-recovered. Tertiary or enhanced recovery techniques, such as CO₂ flooding, can recover additional oil. In CO₂ flooding, the CO₂ is injected into the reservoir. At high pressures (approximately 2,000 psi), the CO₂ is in a liquid phase and can become miscible with the oil, which means the CO₂ and oil mix together and form one fluid. This mixing changes the fluid properties of the oil and enables this trapped oil to begin to move in the reservoir again. The result is a potentially significant increase in production. CO₂ injection can recover, on average, an additional 10% to 16% of the original oil in place in a field over a period of 20 to 30 years. Mature fields that have been abandoned may still be viable candidates for CO₂ floods. CO₂ flooding typically extends the life of oil fields by 20 years.

 

In 2004 and 2005, we acquired West Texas waterfloods, the Wellman and South Mallet Units and the George Allen Unit, for the purpose of evaluating for potential implementation of tertiary oil recovery operations utilizing our equity CO₂ supply. For a discussion of our tertiary reserves and production at the units, please read “— Exploration and Production Operations — Tertiary Oil Recovery.” We have also identified numerous other properties that are attractive candidates for implementing CO₂ projects. We believe we have a competitive advantage in identifying, acquiring and developing these properties because of our expertise and large available CO₂ supply.

 

PetroSource currently has approximately 95 Mmcf per day of CO₂ in available supply. We currently deliver the majority of this supply to Occidental Permian Ltd. and Pure Resources L.P. In December 2007, we captured and sold 92 Mmcf per day. Our long term contracts in place with Occidental provide for the exchange of up to 60% of the delivered volumes. We believe our current tertiary oil recovery properties will require an average of 65 to 75 Mmcf of CO₂ per day over the next five years. We intend to increase our supply

of CO₂ in order to provide sufficient capacity for our tertiary oil recovery operations. We expect the supply of CO₂ to increase as additional natural gas reserves with a high CO₂ content are developed in the Piñon and surrounding fields. In addition, we intend to increase the capacity of our CO₂ treating, gathering and transportation assets which will continue to provide for our CO₂ needs, as well as the expansion of our merchant sales business. Currently, two additional compressors are being refurbished at the Grey Ranch and Mitchell Plant. These units will add over 11,000 horsepower and over 30 Mmcf per day of capacity.

 

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. Recently, a number of states and regions of the U.S. have passed laws, adopted regulations or undertaken regulatory initiatives to reduce the emission of “greenhouse gases,” such as CO₂ and methane. In addition, the U.S. Congress is actively considering legislation to reduce emissions of greenhouse gases, and in light of the U.S. Supreme Court’s recent decision in Massachusetts, et al. v. EPA, the U.S. Environmental Protection Agency may be required to regulate greenhouse gas emissions from mobile sources (e.g., cars and trucks) even if Congress does not adopt new legislation specifically addressing emissions of greenhouse gases. Other nations (not including the United States) have already agreed to regulate emissions of greenhouse gases pursuant to the United Nations Framework Convention on Climate Change, also known as the “Kyoto Protocol.” These 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 1.5 million metric tons of CO₂ per year. We may benefit from such capture to the extent it results in ERCs that can be traded or can be used by us to meet future compliance obligations that may otherwise be costly to satisfy. ERCs of just over 170,000 tonnes were sold on the voluntary market during 2007.

 

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 natural gas and oil industry is intensely competitive, and we face competition in each of our business segments.

 

We believe our geographic concentration of operations and vertical integration enable us to compete effectively with our exploration and production operations. However, we compete 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 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 oil properties.

 

We believe the type, age and condition of our drilling rigs, the quality of our crew 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, the experience of our rig crews and our willingness to drill on a turnkey basis, 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 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 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. 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.

We believe our supply of CO₂, focus on small to mid-sized acquisitions and technical expertise enable us to compete effectively in our tertiary oil recovery business. However, we face the same competitive pressures in this business that we do in our traditional exploration and production segment.

 

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 Matters and Regulation

 

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 natural gas and oil 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, processing 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 U.S. 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 crude 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 regulate emissions of various air pollutants through air emissions permitting programs and the imposition of other requirements. In addition, the EPA has developed, and continues to develop, stringent regulations governing emissions of toxic air pollutants at specified sources. These regulatory programs may require us to obtain permits before commencing construction on a new source of air emissions, and they may require us to reduce emissions or to install expensive emission control technologies at existing facilities and new facilities. As a result, we may be required to incur increased capital and operating costs at existing and new facilities. For instance, the Grey Ranch natural gas treatment plant operates under a permit granted by the Texas Commission on Environmental Quality, or TCEQ that currently allows us to vent CO₂ emissions. Effective March 2009, we will be required to install control devices that limit the quantity of organic compounds vented by the plant. We are in the process of refurbishing existing compressors at an estimated cost of $4.0 million, which will enable us to capture the CO₂ for ultimate delivery to the marketplace. Additional expenses and capital costs may be required for us to maintain or achieve compliance with current and future laws governing air emissions.

 

We are subject to air quality compliance reviews by federal and state agencies, and the failure to meet applicable requirements may result in enforcement action, including fines and penalties. In February 2008, we received a notice of alleged violations from TCEQ for certain monitoring and recordkeeping deficiencies and emissions in excess of allowable limits at our Pike’s Peak processing plant in 2007. We are preparing a response regarding corrective action taken with regard to the alleged violations.

 

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 natural 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 oil and natural gas 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 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 be contributing to warming of the Earth’s atmosphere. In response to such studies, the U.S. Congress is actively considering legislation to restrict or regulate emissions of greenhouse gases. At least 17 states, as well as other regions, have already taken 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, as a result of the U.S. Supreme Court’s decision on April 2, 2007 in Massachusetts, et al. v. EPA, the EPA may be required to regulate greenhouse gas emissions from mobile sources, e.g., cars and trucks, even if Congress does not adopt new legislation specifically addressing emissions of greenhouse gases. The court’s holding in Massachusetts, et al. v. EPA, that greenhouse gases fall under the federal Clean Air Act’s definition of “air pollutant”, may lead to future regulation of greenhouse gas emissions from stationary sources under certain Clean Air Act programs. 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 U.S., 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 April 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 that establish chemicals of interest and their respective threshold quantities that will trigger compliance with these 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 Natural Gas and Oil Industry

 

The natural gas and oil industry is extensively regulated by numerous federal, state and local authorities, including Native American tribes. Legislation affecting the natural gas and oil 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 natural gas and oil industry and its individual members, some of which carry substantial penalties for failure to comply. Although the regulatory burden on the natural gas and oil 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 tribes, in which we operate also regulate one or more of the following:

 

 

 

State laws regulate the size and shape of drilling and spacing units or proration units governing the pooling of natural gas and 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. Minerals Management Service of the U.S. Department of the Interior, or MMS, Regulations 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 U.S. 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. Since 1978, various federal laws have been enacted which 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 gas purchases and sales that permits all purchasers of 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, 2007, we had 2,219 full-time employees and 8 part-time employees, including more than 150 geologists, geophysicists, petroleum engineers, technicians, land and regulatory professionals. Of our 2,227 employees, 335 are located at our headquarters in Oklahoma City, Oklahoma, eight in Amarillo, Texas and the remaining 1,884 employees are working in our various field offices and at our drilling sites.

 

Offices

 

As of December 31, 2007 we lease 80,861 square feet of office space in Oklahoma City, Oklahoma at 1601 N.W. Expressway, where our principal offices are located. The term of the lease expires on August 31, 2009. In July 2007, we purchased property to serve

as our future corporate headquarters. The 3.51-acre site contains four buildings and is located in downtown Oklahoma City, Oklahoma.

 

We also lease or sublease 28,887 square feet of office space in Amarillo, Texas at 701 S. Taylor Street, where our principal offices were previously located. The leases expire in April 2009. We lease 6,725 square feet of office space at 16801 Greenspoint Park Drive in Houston, Texas under a lease expiring in January 2014. PetroSource currently leases approximately 7,848 square feet in Midland, Texas under a lease expiring in December 2008. We own two buildings in Fort Stockton, Texas that combined total 9,292 square feet. Adjacent to these buildings, we own approximately 31,620 square feet of office and shop space. We also own an approximate 10,000 square foot office building in Midland, Texas and own 4,358 square feet of office space and 6,240 square feet of shop space in Odessa, Texas. In addition, we lease a field office located in Longview and Odessa, Texas, Yukon, Oklahoma, Shreveport, Louisiana and Rifle, Colorado.

 

Glossary of Natural Gas and Oil Terms

 

The following is a description of the meanings of some of the natural gas and oil industry terms used in this Annual Report on Form 10-K.

 

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 crude 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 crude 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 crude 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 crude oil, condensate or natural gas liquids.

 

MmBbls.  Million barrels of crude 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 crude 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 which, based on supporting geological, geophysical or other data and also preliminary economic analysis using reasonably anticipated prices and costs, is deemed to have potential for the discovery of commercial hydrocarbons.

 

Proved developed reserves.  Has the meaning given to such term in Rule 4-10(a)(3) of Regulation S-X, which defines proved developed reserves as:

 

Proved developed oil and gas reserves are 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:

 

Proved oil and gas reserves are the estimated quantities of crude oil, natural gas, and natural gas liquids which 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 which 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) crude 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) crude oil, natural gas, and natural gas liquids, that may occur in undrilled prospects; and (D) crude 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:

 

Proved undeveloped oil and gas reserves are 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 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.

 

Stratigraphic play.  An oil or natural gas formation contained within an area created by permeability and porosity changes characteristic of the alternating rock layer that result from the sedimentation process.

 

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.

 

Underbalanced drilling.  The procedure used to drill oil and gas wells where the pressure in the wellbore is kept lower than the fluid pressure in the formation being drilled.

 

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 revenue, 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 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. This may result in our having to make substantial downward adjustments to our estimated proved reserves.

 

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 and Properties — Our Business and Primary Operations” 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 day of estimate. 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 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 natural gas and oil 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, 2007, only 771 of our 4,594 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 Form 10-K. 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 2007, we participated in drilling a total of 316 gross wells, of which eight have been 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 it generally is not feasible to review in depth every individual property involved in each acquisition. Even a detailed review of records and properties may not necessarily reveal existing or potential problems, nor will it 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, which 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 55.3% of the estimated proved reserves that we own or have under lease in the WTO as of December 31, 2007 are proved undeveloped reserves and 56.1% of our total reserves are 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 WTO, making us vulnerable to risks associated with operating in one major geographic area.

 

As of December 31, 2007, approximately 60.8% of our proved reserves and approximately 42.1% 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.

 

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.

 

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 14% in the WTO. 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. The amount of CO₂ in the gas produced affects the heating content of the gas. For example, if a well is 65% CO₂, the gas produced often has a heating content of between 300 and 350 MBtu per Mcf. Giving consideration for plant shrink, as many as four Mcf of high CO₂ 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.

 

Since the treatment expenses are incurred on an 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.

 

A significant decrease in natural gas production in our areas of midstream gas services operation, 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, transmit and process at our facilities. Most of the reserves backing up 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, transmitting and processing. 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, transmit and process being reduced substantially over time and could, upon exhaustion of the current wells, cause us to abandon our gathering systems and, possibly cease gathering, transmission and processing 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. The effect of any material decrease in the volume of natural gas handled by our midstream assets would be to 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, 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, it would result in our having 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, not only from dry holes, but from productive wells that 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 do not carry environmental insurance, for example. 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 processing facilities. For example, we are currently experiencing capacity limitations on sour gas treating in the Piñon Field. Our failure to obtain such services on acceptable terms or expand our midstream assets could materially harm 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 processing facilities may be limited or unavailable. If that were to occur, then we would be unable to realize revenue from those 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 must seek additional financing. Our senior credit facility and term loan contain covenants restricting our ability to incur additional indebtedness without the consent of the lenders. Our lenders may withhold this consent in their sole discretion.

 

In addition, we may not be able 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.

 

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, 2007, our total indebtedness was $1.1 billion, which represented approximately 38% 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 materially adversely affect our business, financial condition and results of operations.

 

Our senior credit facility and term loan have restrictions and financial covenants which could adversely affect our operations.

 

We will depend on our senior credit facility for a portion of future capital needs. The senior credit facility and term loan 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. Our failure to comply with any of the restrictions and covenants under the senior credit facility, term loan 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.

 

The senior credit facility limits the amounts we can borrow to a borrowing base amount, determined by the lender in its sole discretion on a semi-annual basis, based upon projected revenues from the natural gas and oil properties securing our loan. The lender can unilaterally adjust the borrowing base and the borrowings permitted to be outstanding under the senior credit facility, and any increase in the borrowing base requires its consent. Outstanding borrowings in excess of the borrowing base must be repaid immediately, or we must pledge other natural gas and 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.

 

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 instruments for a portion of our natural gas and oil production, including collars and fixed-price swaps. We have not designated any of our derivative instruments as hedges for accounting purposes and record all derivative instruments on our balance sheet at fair value. Changes in the fair value of our derivative instruments are recognized in current earnings. Accordingly, our earnings may fluctuate significantly as a result of changes in fair value of our derivative instruments. Derivative instruments also expose us to the risk of financial loss in some circumstances, including when:

 

 

In addition, these types of derivative arrangements limit the benefit we would receive from increases in the prices for natural gas and oil and may expose us to cash margin requirements.

 

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

 

The natural gas and oil industry is intensely competitive, and we compete with companies that have greater resources. 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 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 oil properties.

 

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 much 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 U.S. Department of the Interior’s Minerals Management Service (“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 and Properties — Environmental Matters and Regulation.”

 

Under certain environmental laws that impose strict, joint and several liability, we may be required 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 or property 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 them 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 U.S. have agreed to regulate emissions of “greenhouse gases.” Methane, a primary component of natural gas, and carbon dioxide, a byproduct of burning of natural gas and oil, are 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 Matters and Regulation.”

 

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

 

We are not currently required to comply with Section 404 of the Sarbanes Oxley Act of 2002, and are therefore not required to make an assessment of the effectiveness of our internal controls over financial reporting for that purpose. 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 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. We will be required to comply with Section 404 of the Sarbanes-Oxley Act of 2002 effective as of December 31, 2008. 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.

 

 

The Company is a defendant in lawsuits from time to time in the normal course of business. In management’s opinion, the Company is not currently involved in any legal proceedings which, individually or in the aggregate, could have a material effect on the financial condition, operations and/or cash flows of the Company.

 

 

Not applicable.

 

 

Price Range of Common Stock

 

Following our initial public offering, our common stock commenced trading on the New York Stock Exchange under the symbol “SD” on November 6, 2007. Prior to November 6, 2007, there was no active market for our common stock. For the period November 6, 2007 to December 31, 2007, the high and low sales prices per share of our common stock as reported by the New York Stock Exchange were $36.11 per share and $29.53 per share, respectively.

 

At February 29, 2007, there were 503 holders of record of our common stock and approximately 10,532 beneficial owners.

 

We do not anticipate declaring or paying any cash dividends to holders of our common stock in the foreseeable future. We currently intend to retain all available funds and any future earnings for use in the operation and expansion of our business, including exploration, development and acquisition activities. The terms of our revolving credit facility and senior term loans restrict our ability to pay dividends to holders of common stock. The certificate of designation for our convertible preferred stock also prohibits the payment of dividends to holders of our common stock without the consent of holders of a majority of our outstanding convertible preferred 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. This transaction did not involve any underwriter or a public offering, and we believe this transaction was exempt from registration requirements pursuant to Section 4(2) of the Securities Act and Regulation D promulgated thereunder.

 

Recent Sales of Unregistered Securities

 

On March 20, 2007, we sold approximately 17.8 million shares of our common stock for net proceeds of $318.7 million, after deducting offering expenses of approximately $1.4 million. The stock was sold in private sales as follows: 11.1 million shares to affiliates of Ares Management LLC (“Ares”), a private institutional investment firm, for $200 million, and 2.8 million shares to an affiliate of Tom L. Ward, the Company’s Chairman, Chief Executive Officer and largest stockholder for $50 million. In addition to the 13.9 million shares sold to Ares and the affiliate of Mr. Ward, holders of the Company’s outstanding Series A Convertible Preferred Shares and Common Units exercised preemptive rights resulting in the sale of an additional 3.9 million shares for $70 million. An affiliate of Mr. Ward exercised the right to acquire 0.6 million of the preemptive shares for $11.4 million, bringing the total shares purchased by Mr. Ward’s affiliates to 3.4 million shares at a purchase price of $61.4 million. All shares were sold at $18 per share.

Use of Proceeds from Sales of Registered Securities

 

On November 9, 2007, we completed the initial public offering of our common stock. We sold 32,379,500 shares at a price of $26 per share. We received net proceeds of approximately $794.7 million after deducting underwriting discounts and offering expenses of approximately $47.1 million. We used the net proceeds to repay the outstanding indebtedness under our senior credit facility ($515.9 million), to repay a note related to a recent acquisition ($49.1 million), and to fund the remainder of our 2007 capital expenditure program and a portion of our 2008 capital expenditure program ($229.7 million).

 

Issuer Purchases of Equity Securities

 

As part of our restricted stock plan, we make required tax payments on behalf of employees as their 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 were recorded as treasury shares. During the period November 5, 2007 to December 31, 2007, we purchased the following shares:

 

 

 

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 effective November 21, 2006. The information should be read in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and our consolidated financial statements and notes thereto contained in this document. The following information is not necessarily indicative of our future results.