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Article by DailyStocks_admin    (05-29-08 05:33 AM)

SANDRIDGE ENERGY INC. CEO Tom L.Ward bought 189785 shares on 5-19-2008 at $48.53

BUSINESS OVERVIEW

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, CO 2 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 CO 2 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:


• Grow Through Exploration and Drilling and Development of Existing Acreage. We expect to generate long-term reserve and production growth by exploring and drilling and developing our large acreage position. Our primary exploration and development focus will be in the WTO, where we have identified approximately 2,600 potential drilling locations and had 30 rigs operating as of December 31, 2007.

• Apply Technological Improvements to Our Exploration and Development Program. We intend to enhance our drilling success rate and completion efficiency with improved 3-D seismic acquisition and interpretation technologies, together with advanced drilling, completion and production methods that historically have not been widely used in the under-explored WTO.

• Seek Opportunistic Acquisitions in Our Core Geographic Area. Since January 2006, through acquisitions and leasing activities, we have tripled our net acreage position in the WTO. We intend to continue to seek other opportunities to optimize and enhance our exploratory acreage position in the WTO and other strategic areas.

• Reduce Costs, Enhance Returns and Maintain Operating Flexibility by Controlling Drilling Rigs and Midstream Assets. Our rig fleet enables us to effectively develop our own acreage while maintaining the flexibility of a third-party contract drilling business. By controlling our fleet of drilling rigs and gathering and treating assets, we believe we will be able to better control overall costs and maintain a high degree of operational flexibility.

• Capture and Utilize CO 2 for Tertiary Oil Recovery. We intend to capitalize on our access to CO 2 reserves and CO 2 flooding expertise to pursue enhanced oil recovery in mature oil fields in West Texas. By utilizing this CO 2 in our own tertiary recovery projects, we expect to recover additional oil that would have otherwise been abandoned following traditional waterfloods.

Competitive Strengths

We have a number of strengths that we believe will help us successfully execute our strategies:


• Large Asset Base with Substantial Drilling Inventory. Our producing properties are characterized by long-lived predominantly natural gas reserves with established production profiles. Our estimated proved reserves of 1,516.2 Bcfe as of December 31, 2007 had a proved reserves to production ratio of approximately 17.7 years. Our core area of operations in the WTO has expanded to 600,546 gross (508,745 net) acres as of December 31, 2007. We have identified approximately 2,600 potential drilling locations in the WTO and believe that we will be able to expand the number of drilling locations in the remainder of the WTO through exploratory drilling and our use of 3-D seismic technology.

• Geographically Concentrated Exploration and Development Operations. We intend to focus our drilling and development operations in the near term on the WTO to fully exploit this unique geological area. The WTO was created by the collision of the ancestral North and South American continents, which fractured and thrust the reservoir rock to come to rest in repeating layers. We believe the geological environment of the WTO and the height of the prospective pay zones create opportunities for significant conventional accumulations of natural gas and oil. To a lesser extent, we will also focus on the highly prolific Cotton Valley Trend in East Texas. This geographic concentration allows us to establish economies of scale in both drilling and production operations to achieve lower production costs and generate increased cash flows from our producing properties. We believe our concentrated acreage position will enable us to organically grow our reserves and production for the next several years.

• Experienced Management Team Focused on Delivering Long-term Stockholder Value. During 2006, we significantly expanded our management team when Tom L. Ward, co-founder and former president of Chesapeake Energy Corporation, purchased a significant interest in us and became our Chairman and Chief Executive Officer. Mr. Ward leads an experienced management team of 11 executive officers and 38 senior executives. Our management team averages over 24 years of experience working in or servicing the natural gas and oil industry. Our management team, board of directors and employees owned 37.2% of our capital stock as of December 31, 2007, which we believe aligns their objectives with those of our stockholders.

• High Degree of Operational Control. We operate over 99.2% of our production in the WTO, East Texas and the Gulf Coast area, which permits us to manage our operating costs and better control capital expenditures and the timing of development and exploitation activities.

• Large Modern Fleet of Drilling Rigs. 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 operational. By controlling a large, modern and efficient drilling fleet, we can develop our existing reserves and explore for new reserves on a more economical basis.

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.


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:


• South Sabino Prospect Area. The South Sabino prospect area is located approximately twelve miles east of the Piñon Field. We have drilled two wells which have encountered the Caballos chert and hydrocarbons in zones less than 7,000 feet deep. Those wells were selected using 2-D seismic and limited subsurface well control. The wells appear to be on trend with the Piñon Field and are structurally higher against one of several thrust faults that make up the WTO. Results from our first phase of 3-D seismic in this area in 2007 are encouraging and we plan to drill up to seven wells in the South Sabino Prospect in 2008.


• Big Canyon Prospect Area. Located approximately 25 miles east of the Piñon Field along the WTO, this prospect area represents potential opportunities for future development. The key well, Big Canyon Ranch 106-1, was drilled by a third-party to a depth of 24,075 feet and was abandoned in December 1993 after testing gas from the Tesnus sands and Caballos chert. Our 3-D seismic survey over the Big Canyon prospect area was acquired in late 2007. Exploratory wells are planned in 2008 to further evaluate both the Tesnus and the Caballos in a location structurally updip to the Big Canyon Ranch 106-1 well.


• Other Prospect Areas. We have identified several other potential prospect areas in the WTO that we are currently evaluating.

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 CO 2 floods. The Wellman Unit covers approximately 2,120 acres, 1,200 of which are well-suited for both water and CO 2 floods. The Wellman Field has been partially CO 2 flooded and water flooded to produce 83.7 Mmboe to date. We recently re-initiated injection of CO 2 , 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 CO 2 recycling plant at this unit with a capacity of 28 Mmcf per day. The plant includes 6,000 horsepower of CO 2 compression and 4,850 horsepower of processing compression, which is sufficient to handle the recycling of the CO 2 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 CO 2 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. CO 2 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 CO 2 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 CO 2 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 CO 2 development with plans to begin injection of CO 2 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.


CEO BACKGROUND

Tom L. Ward (Chairman, Chief Executive Officer and President) Mr. Ward has served as our Chairman and Chief Executive Officer since June 2006 and as our President since December 2006. Prior to joining SandRidge, he served as President, Chief Operating Officer and a director of Chesapeake Energy Corporation (NYSE: CHK) from the time he co-founded the company in 1989 until February 2006. From February 2006 until June 2006, Mr. Ward managed his private investments. Mr. Ward graduated from the University of Oklahoma in 1981 with a Bachelor of Business Administration in Petroleum Land Management. He is a member of the Board of Trustees of Anderson University in Anderson, Indiana.

Roy T. Oliver, Jr. (Director) Mr. Oliver was appointed as a director on July 13, 2006. Mr. Oliver has served as President of R.T. Oliver Investments, Inc., a diversified investment company with interests in energy, energy services, media and real estate, since August 2001. The company presently owns the largest portfolio of class A office properties in Oklahoma. He has served as President and Chairman of the Board of Valliance Bank, N.A. since August 2004. He founded U.S. Rig and Equipment, Inc. in 1980 and served as its President until its assets were sold in August 2003. Mr. Oliver is a graduate of The University of Oklahoma with a Bachelor of Business Administration degree. He serves on The University of Oklahoma Michael F. Price College of Business Board of Advisors.

Daniel W. Jordan (Director) Mr. Jordan was appointed as a director of SandRidge in December 2005. Mr. Jordan also has served as a director of PetroSource since May 2004 and served as a Vice President and director of Symbol Underbalanced Air Services and Larco from August 2003 to September 2005. From October 2005 through August 2006, Mr. Jordan served as our Vice President, Business. Since September 2006, Mr. Jordan has been involved in private investments. Prior to joining SandRidge, Mr. Jordan founded Jordan Drilling Fluids, Inc. and served as its Chairman, President and Chief Executive Officer from March 1984 to July 2005. Mr. Jordan sold Jordan Drilling Fluids, Inc. and its wholly owned subsidiary, Anchor Drilling Fluids USA Inc., in July 2005. At that time, Anchor Drilling Fluids USA Inc. was the largest privately held domestic drilling fluids firm.

Stuart W. Ray (Director) Mr. Ray was appointed as a director on December 14, 2007. Mr. Ray is a Partner of Sonenshine Partners LLC, a New York City based investment banking firm, and a Partner of Urban American Partners, LLC, a New Jersey based real estate investment and management firm that owns and operates portfolios of workforce housing units. Mr. Ray has also served on the board of directors of GreenHunter Energy, Inc. since December 2007. Mr. Ray is a Chartered Financial Analyst, a member of the New York Society of Security Analysts, and a registered broker with the NASD. He received his Bachelor of Arts from Harvard College and Master in Business Administration from Harvard Business School.

William A. Gilliland (Director) Mr. Gilliland was appointed as a director on January 7, 2006. Mr. Gilliland has served as managing partner of several personal and family investment partnerships, including Gillco Energy, L.P. and Gillco Investments, L.P., since April 1999. Prior to this, Mr. Gilliland was the founder, Chief Executive Officer, President and Chairman of Cross-Continent Auto Retailers, Inc. Mr. Gilliland holds a Bachelor of Business Administration from North Texas State University.

D. Dwight Scott (Director) Mr. Scott was appointed as a director on March 20, 2007. He has been a Managing Director of GSO Capital Partners, an investment advisor specializing in the leveraged finance marketplace since September 2005. Prior to joining GSO, Mr. Scott was Executive Vice President and Chief Financial Officer for El Paso Corporation from October 2002 until August 2005. He is a member of the board of directors of MCV Investors, Inc., United Engines Holding Company LLC, KIPP, Inc. and the Board of Trustees of the Council on Alcohol and Drugs Houston. Mr. Scott earned a Bachelor’s degree from the University of North Carolina at Chapel Hill and a Master’s of Business Administration from the University of Texas at Austin.

Jeffrey S. Serota (Director) Mr. Serota was appointed as a director of SandRidge Energy, Inc. on March 20, 2007. He has served as a Senior Partner with Ares Management LLC, an independent Los Angeles based investment firm, since September 1997. Prior to joining Ares, Mr. Serota worked at Bear Stearns from March 1996 to September 1997, where he specialized in providing investment banking services to financial sponsor clients of the firm. He currently serves on the board of directors of Marietta Holding Corporation, Douglas Dynamics, LLC, AmeriQual Group LLC, WCA Waste Corporation and White Energy, Inc. Mr. Serota graduated magna cum laude with a Bachelor of Science degree in Economics from the University of Pennsylvania’s Wharton School of Business and received a Masters of Business Administration degree from UCLA’s Anderson School of Management.

MANAGEMENT DISCUSSION FROM LATEST 10K

Introduction

The following discussion and analysis is intended to help the reader understand our business, financial condition, results of operations, liquidity and capital resources. This discussion and analysis is provided as a supplement to, and should be read in conjunction with, the other sections of this Annual Report on Form 10-K, including: “Items 1 and 2. Business and Properties,” “Item 6. Selected Financial Data,” and “Item 8. Financial Statements and Supplementary Data.” The following discussion contains forward-looking statements that reflect our future plans, estimates, beliefs and expected performance. The forward-looking statements are dependent upon events, risks and uncertainties that may be outside our control. Our actual results could differ materially from those discussed in these forward-looking statements. Factors that could cause or contribute to such differences include, but are not limited to, market prices for natural gas and oil, economic and competitive conditions, regulatory changes, estimates of proved reserves, potential failure to achieve production from development projects, capital expenditures and other uncertainties, as well as those factors discussed below and elsewhere in this Annual Report on Form 10-K, particularly in “Item 1A - Risk Factors” and “Cautionary Statement Concerning Forward-Looking Statements” below, all of which are difficult to predict. In light of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur.

Overview of Our Company

We are a rapidly expanding independent natural gas and oil company concentrating on exploration, development and production activities. We are focused on continuing the exploration and exploitation of our significant holdings in the West Texas Overthrust, which we refer to as the WTO, a natural gas prone geological region where we have operated since 1986 that includes the Piñon Field the South Sabino the Big Canyon Prospect and other prospects that we are currently evaluating. We also own and operate drilling rigs and conduct related oil field services, and we own and operate interests in gas gathering, marketing and processing facilities and CO 2 gathering and transportation facilities.

On November 21, 2006, we acquired all of the outstanding membership interests in NEG Oil & Gas, LLC, or 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 has 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. 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.

During November 2007, we completed the initial public offering of our common stock. We used the proceeds from this offering to repay indebtedness outstanding under our senior credit facility as well as a note payable related to a recent acquisition, to fund the remainder of our 2007 capital expenditure program and a portion of our 2008 capital expenditure program. See further discussion of these transactions in Note 18 to the consolidated financial statements contained in this Form 10-K.

Segment Overview

We operate in four related business segments: exploration and production, drilling and oil field services, midstream gas services and other. Management evaluates the performance of our business segments based on operating income, which is computed as segment operating revenue less direct operating costs. These measurements provide important information to us about the activity and profitability of our lines of business.

Exploration and Production Segment

We explore for, develop and produce natural gas and oil reserves, with a focus on our proved reserves and extensive undeveloped acreage positions in the WTO. We operate substantially all of our wells in our core areas and employ our drilling rigs and other drilling services in the exploration and development of our operated wells and, to a lesser extent, on our non-operated wells.

The primary factors affecting the financial results of our exploration and production segment are the prices we receive for our natural gas and oil production, the quantity of our natural gas and oil production and changes in the fair value of derivative instruments we use to reduce the volatility of the prices we receive for our natural gas and oil production. Because we are vertically integrated, our exploration and production activities affect the results of our oil field service and midstream segments. The NEG acquisition in November 2006 substantially increased our revenues and operating income in our exploration and production segment. However, because our working interest in the Piñon Field increased to approximately 93%, there are greater intercompany eliminations that affect the consolidated financial results of our drilling and oil field service and midstream gas services segments.

Exploration and production segment revenues increased to $478.7 million in the year ended December 31, 2007 from $106.4 million in 2006, an increase of 350%, as a result of a 320% increase in production volumes and a 13% increase in the average price we received for the natural gas and oil we produced. During 2007, we increased natural gas production by 38.5 Bcf to 52.0 Bcf and increased crude oil production by 1,720 MBbls to 2,042 MBbls. The total combined 48.9 Bcfe increase in production was due primarily to acquisitions and successful drilling in the WTO.

The average price we received for our natural gas production for the year ended December 31, 2007 increased 5%, or $0.32 per Mcf, to $6.51 per Mcf from $6.19 per Mcf in 2006. The average price received for our crude oil production increased to $68.12 from $56.61 per Bbl in 2006. Including the impact of derivative contract settlements, the effective price received for natural gas for the year ended December 31, 2007 was $7.18 per Mcf as compared to $7.25 per Mcf during the comparable period in 2006. Our oil derivative contract settlements decreased our effective price received for oil by $0.02 per Bbl to $68.10 per Bbl for the year ended December 31, 2007. Our derivative contracts had no impact on effective oil prices during the year ended December 31, 2006.

For the year ended December 31, 2007, we had $198.9 million in operating income in our exploration and production segment, compared to $17.1 million in operating income in 2006. The $372.4 million increase in exploration and production segment revenues was partially offset by a $71.0 million increase in production expenses and a $147.2 million increase in depreciation, depletion and amortization, or DD&A. The increase in production expenses was attributable to the additional properties acquired in the NEG acquisition and operating expenses on our new wells. During the year ended December 31, 2007, the exploration and production segment reported a $60.7 million net gain on our derivative positions ($34.5 million realized gains and $26.2 million unrealized gains) compared to a $12.3 million net gain ($14.2 million realized gains and $1.9 million unrealized losses) in the comparable period in 2006. During 2007, we selectively entered into natural gas swaps and basis swaps by capitalizing on what we perceived as spikes in the price of natural gas or favorable basis differences between the NYMEX price and natural gas prices at our principal West Texas pricing point of Waha Hub. Unrealized gains or losses on derivative contracts represent the change in fair value of open derivative positions during the period. The change in fair value is principally measured based on period end prices as compared to the contract price. Future volatility in natural gas and oil prices could have an adverse effect on the operating results of our exploration and production segment.

For the year ended December 31, 2006, exploration and production segment revenues increased to $106.4 million from $54.1 million in 2005. The increase in 2006 compared to 2005 was attributable to increased production due to successful drilling activity and approximately 40 days of production from the NEG acquisition effective November 21, 2006. NEG contributed approximately $36.9 million of revenues in the 2006 period. Production volumes increased to 15,342 Mmcfe in 2006 from 7,305 Mmcfe in 2005, representing an 8,037 Mmcfe, or 110% increase. Approximately 4,902 Mmcfe, or 61%, of the increase was attributable to NEG production for the period from November 21, 2006 to December 31, 2006. Average combined prices were essentially unchanged at $6.60 per Mcfe as compared to $6.63 per Mcfe in 2005.

Exploration and production segment operating income increased $2.2 million in 2006 to $17.1 million from $14.9 million in 2005. The increase was primarily attributable to the increased production revenues described above, approximately $12.3 million in derivative gains (including a $1.9 million unrealized loss) in 2006 as compared to a $4.1 million derivative loss (including a $1.3 million unrealized loss) in 2005, and the addition of NEG for the period from November 21, 2006 to December 31, 2006. The increase in exploration and production segment income was substantially offset by a $20.5 million, or 106%, increase in production costs, a $26.7 million, or 380%, increase in general and administrative expenses and a $19.3 million increase in DD&A. Approximately $7.0 million of the increase in production costs was attributable to the NEG acquisition with the remainder of the increase attributable to the increase in the number of wells operated in 2006 as compared to 2005. The increase in DD&A for our exploration and production segment was attributable to higher production and the increase in the full-cost pool due to the NEG acquisition.

As of December 31, 2007, we had 1,516.2 Bcfe of estimated net proved reserves with a PV-10 of $3,550.5 million, while at December 31, 2006 we had 1,001.8 Bcfe of estimated net proved reserves with a PV-10 of $1,734.3 million. Our Standardized Measure of Discounted Future Net Cash Flows was $2,718.5 million at December 31, 2007 as compared to $1,440.2 million at December 31, 2006 and $499.2 million at December 31, 2005. For a discussion of PV-10 and a reconciliation to Standardized Measure of Discounted Net Cash Flows, see “Items 1 and 2. Business and Properties.” The increase in 2007 was primarily attributable to revisions of our previous estimates due to performance and results of our drilling activity. The increase in 2006 was primarily related to the addition of the NEG reserves which was partially offset by a decrease in the price of natural gas to $5.32 per Mcf at December 31, 2006 from $8.40 per Mcf at December 31, 2005.

Estimates of net proved reserves are inherently imprecise. In order to prepare our estimates, we must analyze available geological, geophysical, production and engineering data and project production rates and the timing of development expenditures. The process also requires economic assumptions about matters such as natural gas and oil prices, drilling and operating expenses, capital expenditures, taxes and the availability of funds. 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. Approximately 97% of our year-end reserve estimates are prepared by independent petroleum reserve engineers.

Over the past several years, higher natural gas and oil prices have led to higher demand for drilling rigs, operating personnel and field supplies and services. Higher prices have also caused increases in the costs of those goods and services. To date, the higher sales prices have more than offset the higher field costs. Our ownership of drilling rigs has also assisted us in stabilizing our overall cost structure. Given the inherent volatility of natural gas and oil prices that are influenced by many factors beyond our control, we plan our activities and budget based on conservative sales price assumptions, which generally are lower than the average sales prices received in 2007. We focus our efforts on increasing natural gas reserves and production while controlling costs at a level that is appropriate for long-term operations. Our future earnings and cash flows are dependent on our ability to manage our overall cost structure to a level that allows for profitable production.

Like all exploration and production companies, we face the challenge of natural production declines. As initial reservoir pressures are depleted, natural gas and oil production from a given well naturally decreases. Thus, a natural gas and oil exploration and production company depletes part of its asset base with each unit of oil or natural gas it produces. We attempt to overcome this natural decline by drilling and acquiring more reserves than we produce. Our future growth will depend on our ability to continue to add reserves in excess of production. We will maintain our focus on managing the costs associated with adding reserves through drilling and acquisitions as well as the costs associated with producing such reserves. Our ability to add reserves through drilling is dependent on our capital resources and can be limited by many factors, including our ability to timely obtain drilling permits and regulatory approvals. In the WTO, this has not posed a problem. However, in other areas, the permitting and approval process has been more difficult in recent years due to increased activism from environmental and other groups. This has increased the time it takes to receive permits in some locations.

Drilling and Oil Field Services Segment

We drill for our own account primarily in the WTO through our drilling and oil field services subsidiary, Lariat Services. We also drill wells for other natural gas and oil companies, primarily located in the West Texas region. Our oil field services business conducts operations that complement our drilling services operation. These services include providing pulling units, trucking, rental tools, location and road construction and roustabout services to ourselves and to third parties. Additionally, we provide under-balanced drilling systems only for our own account.

In October 2005, we and Clayton Williams Energy, Inc. (“CWEI”) formed a limited partnership, Larclay, which acquired twelve sets of rig components and other related equipment to assemble into completed land drilling rigs. The drilling rigs were to be used for drilling on CWEI’s prospects, our prospects or for contracting to third parties on daywork drilling contracts. All of these rigs have been delivered, although one rig has not been assembled. CWEI was responsible for securing financing and the purchase of the rigs. The partnership financed 100% of the acquisition cost of the rigs utilizing a guarantee by CWEI. We operate the rigs owned by the partnership. The partnership and CWEI are responsible for all costs related to the initial construction and equipping of the drilling rigs. In the event of an operating shortfall within the partnership, we, along with CWEI are responsible to fund the shortfall through loans to the partnership. We and CWEI each have a 50% interest in Larclay. We account for Larclay as an equity investment.

The financial results of our drilling and oil field services segment depend on many factors, particularly the demand for and the price we can charge for our services. We provide drilling services for our own account and for others, generally on a daywork or turnkey contract basis. Substantially all of our drilling contract revenues are derived from daywork drilling contracts. However, we generally assess the complexity and risk of operations, the on-site drilling conditions, the type of equipment to be used, the anticipated duration of the work to be performed and the prevailing market rates in determining the contract terms we offer.

Daywork Contracts. Under a daywork drilling contract, we provide a drilling rig with required personnel to our customer who supervises the drilling of the well. We are paid based on a negotiated fixed rate per day while the rig is used. Daywork drilling contracts specify the equipment to be used, the size of the hole and the depth of the well. Under a daywork drilling contract, the customer bears a large portion of the out-of-pocket drilling costs, and we generally bear no part of the usual risks associated with drilling, such as time delays and unanticipated costs. As of December 31, 2007, 24 of our rigs were operating under daywork contracts and 22 of these were working for our account. As of December 31, 2007, the 10 operating rigs owned by Larclay were operating under daywork contracts and seven of these were working for our account. The remaining three operating Larclay rigs were working for CWEI as of December 31, 2007.

Turnkey Contracts. Under a typical turnkey contract, a customer will pay us to drill a well to a specified depth and under specified conditions for a fixed price, regardless of the time required or the problems encountered in drilling the well. We provide most of the equipment and drilling supplies required to drill the well. We subcontract for related services such as the provision of casing crews, cementing and well logging. Generally we do not receive progress payments and are paid only after the well is drilled. We routinely enter into turnkey contracts in areas where our experience and expertise permit us to drill wells more profitably than under a daywork contract. As of December 31, 2007, one of our rigs was operating under a turnkey contract.

Drilling and oil field services segment revenue decreased to $73.2 million for the year ended December 31, 2007 from $138.7 million for the year ended December 31, 2006. Operating income decreased to $10.5 million during 2007 from $32.9 million in the same period in 2006. The decline in revenues and operating income is primarily attributable to an increase in the number of rigs operating on our properties and an increase in our ownership interest in our natural gas and oil properties. Our drilling and oil field services segment records revenues and operating income only on wells drilled for or on behalf of third parties. The portion of drilling costs incurred by our drilling and oil field services segment relating to our ownership interest is capitalized as part of our full-cost pool. With the NEG acquisition and other WTO property acquisitions, our average working interest has increased to approximately 93% in the wells we operate in the WTO, and the third-party interest has declined to less than 20%. During the year ended December 31, 2007, approximately 72% of drilling and oil field service segment revenue was generated by work performed on our own account and eliminated in consolidation as compared to approximately 34% for the comparable period in 2006. The number of drilling rigs we owned increased 19% to an average of 26 rigs during 2007 from an average of 21.9 rigs in 2006. The average daily rate we received per rig of $17,177, excluding revenues for related rental equipment and before intercompany eliminations was essentially unchanged from 2006. Our rig utilization rate was 90%, representing 1,095 stacked rig days in 2007. The decline in operating income was principally attributable to the increase in the number and working interest ownership in wells drilled for our own account.

During 2006, our drilling and oil field services segment reported $138.7 million in revenues, an increase of $58.5 million, or 73%, from 2005. Operating income increased to $32.9 million in 2006 from $18.3 million in 2005. The increase in revenue and operating income was primarily attributable to an increase in the number of rigs we owned and an increase in the average revenue per rig per day we earned from the rigs. The number of rigs we owned increased 32% to 25 rigs as of December 31, 2006 and the average revenue we received per rig, excluding revenues for related rental equipment, increased 48% (before intercompany eliminations) to $17,034 per day from $11,503 per day. Our margins increased primarily due to our rig rates increasing faster than our operating costs.

We believe our ownership of drilling rigs and related oil field services will continue to be a major catalyst of our growth. As of December 31, 2007, our drilling fleet consisted of 44 rigs, including the twelve rigs owned by Larclay. As of December 31, 2007, 29 of our rigs are working on properties that we operate; six of our rigs are drilling on a contract basis for third parties; three are being retrofitted and six are idle or being repaired.

In 2005 we placed an order for 22 drilling rigs to be constructed by Chinese manufacturers for an approximate aggregate purchase price of $126.4 million, of which $75.6 million was attributable to Larclay. We believe this is a lower cost when compared to newly built U.S. manufactured rigs with similar capabilities.

Midstream Gas Services Segment

We provide gathering, compression, processing and treating services of natural gas in West Texas and the Piceance Basin in northwestern Colorado, primarily through our wholly-owned subsidiary, ROC Gas. Through our gas marketing subsidiary, Integra Energy LLC (“Integra Energy”), we buy and sell natural gas produced from our operated wells as well as third-party operated wells. Gas marketing revenue is one of our largest revenue components; however, it is a very low margin business. Substantially all of our marketing fees are billed on a per unit basis. On a consolidated basis, gas purchases and other costs of sales include the total value we receive from third parties for the gas we sell and the amount we pay for gas, which are reported as midstream and marketing expense. The primary factors affecting our midstream gas services are the quantity of gas we gather, treat and market and the prices we pay and receive for natural gas.

Midstream gas services revenue for the year ended December 31, 2007 was $107.6 million compared to $122.9 million in 2006. The decrease in midstream gas services revenues is attributable to the increase in our working interest in the WTO as a result of the NEG and other acquisitions.

Midstream gas services segment revenue decreased $24.6 million for the year ended December 31, 2006 from $147.5 million in 2005 to $122.9 million in 2006. The NEG acquisition significantly decreased our midstream gas services revenue as more gas was transported for our own account. We do not record midstream gas revenue for transportation, treating and processing of our own gas.

Prior to the NEG acquisition, transportation, treating and processing of gas for NEG was recorded as midstream gas services revenue. Operating income increased $3.3 million in 2007 to $6.8 million due to lower gas prices paid and an increase in marketing and transportation for our own account. Operating income decreased to $3.5 million in 2006 from $4.1 million in the 2005 period, primarily due to the NEG acquisition and start-up operating expenses for our Sagebrush processing plant in 2006. The Sagebrush plant was placed into full operation during May 2007. We have the contractual right to periodically increase fees we receive for transportation and processing based on certain indexes.

Other Segment

Our other segment consists primarily of our CO 2 gathering and tertiary oil recovery operations and other investments. We conduct our CO 2 gathering and tertiary oil recovery operations through our wholly-owned subsidiary, PetroSource. In the fourth quarter of 2005 we acquired a majority interest in PetroSource, and in the first and second quarters of 2006 we acquired the remaining interests in PetroSource. Prior to the majority acquisition of PetroSource we accounted for PetroSource’s results of operation as an equity investment in an unconsolidated subsidiary. PetroSource gathers CO 2 from natural gas treatment plants located in West Texas and transports this CO 2 for use in our and third parties’ tertiary oil recovery operations.

We believe our tertiary oil recovery operations will provide significant long-term production growth potential at reasonable rates of return. Generally, there is a significant delay between the initial capital expenditures for infrastructure and CO 2 injections and the resulting production increases, if any, as tertiary oil recovery operations require the construction of facilities before CO 2 flooding can commence. After the infrastructure is in place and injections begin, it usually takes an additional 18 months before the field responds (i.e. oil production increases) to the injection of CO 2 . As a result, we do not anticipate that PetroSource will be profitable for the next several years.

Results of Operations

Year Ended December 31, 2007 Compared to the Year Ended December 31, 2006

Impact of the NEG Acquisition. The results of operations for the year ended December 31, 2006 include the results of NEG from November 21, 2006. The results of operations for the year ended December 31, 2007 include the NEG acquisition for the full year. While NEG was principally an exploration and production company, the acquisition affected several of our revenue and expense categories. Revenues and expenses related to our natural gas and crude oil operations increased due to increased production from the acquired NEG properties. Revenues and expenses relating to our drilling and services and midstream and marketing operations decreased due to increased intercompany eliminations as more services were provided on company-owned properties. General and administrative expenses increase due to the addition of new staff. Interest expense increased due to the additional borrowings incurred in conjunction with the NEG acquisition.

Total natural gas and crude oil revenues increased $376.4 million to $477.6 million for the year ended December 31, 2007, compared to $101.3 million in 2006, primarily as a result of an increase in natural gas and crude oil production volumes. Total natural gas production increased 287% to 51,958 Mmcf in 2007 compared to 13,410 Mmcf in 2006, while crude oil production increased 534% to 2,042 MBbls in 2007 from 322 MBbls in 2006. The increase was due to the NEG acquisition and our successful drilling in the WTO. The average price received for our natural gas and crude oil production increased 13% in 2007 to $7.45 per Mcfe compared to $6.60 per Mcfe in 2006, excluding the impact of derivative contracts.

Drilling and services revenue decreased 47% to $73.2 million in 2007 compared to $139.0 million in 2006. The decline in revenues is primarily attributable to an increase in the number of rigs operating on our properties and an increase in our ownership interest in our natural gas and oil properties. The number of rigs we owned increased to 26.0 (average for the year ended December 31, 2007) in 2007 compared to 21.9 in 2006, an increase of 19%, and the average daily revenue per rig, after considering the effect of the elimination of intercompany usage, was essentially unchanged at $17,177 per day.

Midstream and marketing revenue decreased $15.1 million, or 12%, with revenues of $107.8 million for the year ended December 31, 2007, as compared to $122.9 million in 2006. The NEG acquisition significantly decreased our midstream gas services revenues as more gas was transported for our own account. Prior to the acquisition, transportation, treating and processing of gas for NEG was recorded as midstream gas services revenue. We have the contractual right to periodically increase fees we receive for transportation and processing based on certain indexes.

Other revenue decreased to $18.9 million during 2007 from $25.0 million in 2006. The decrease was primarily due to the sale of various non-energy related assets to our former President and Chief Operating Officer. Revenues related to these assets are included in the 2006 period prior to their sale in August 2006. This decrease was slightly offset by an increase in revenues generated by our CO 2 operations.

Operating Costs and Expenses. Total operating costs and expenses increased to $490.6 million during 2007, compared to $351.3 million in 2006, primarily due to increases in our production-related costs as well as an increase in corporate staff. These increases were partially offset by decreases in costs attributable to our drilling and services and midstream and marketing operations as well as increased gains on derivative instruments.

Production expense includes the costs associated with our exploration and production activities, including, but not limited to, lease operating expense and processing costs. Production expenses increased $71.0 million due to increased production from our 2007 drilling activity and the addition of the NEG properties. The remainder of the increase was due to an increase in lease operating expenses due to an increase in the number of wells we operate. Production taxes increased $14.9 million, or 320%, to $19.6 million primarily due to increased gas production as a result of our 2007 drilling activity and the addition of the NEG properties in 2006.

Drilling and services and midstream and marketing expenses decreased 55% and 18% respectively, during 2007 as compared to 2006 primarily because of the increase in the number and working interest ownership of the wells we drilled for our own account.

DD&A for our natural gas and crude oil properties increased to $173.6 million during 2007 from $26.3 million in 2006. Our DD&A per Mcfe increased $0.98 to $2.70 from $1.72 in 2006. The increase is primarily attributable to our 2007 capital expenditures and the NEG acquisition, which increased our depreciable properties by the purchase price plus future development costs and increased production. Our production increased 320% to 64.2 Bcfe from 15.3 Bcfe in 2006.

DD&A for our other assets consists primarily of depreciation of our drilling rigs, natural gas plants and other equipment. The $24.2 million increase in DD&A — other was due primarily to our increased investments in rigs, other oilfield services equipment and midstream assets. During 2006 and 2007, capital expenditures for drilling rigs, other oilfield services equipment and midstream assets were $293 million on a combined basis. We calculate depreciation of property and equipment using the straight-line method over the estimated useful lives of the assets, which range from three to 25 years. Our drilling rigs and related oil field services equipment are depreciated over an average seven-year useful life.

General and administrative expenses increased 11% to $61.8 million during 2007 from $55.6 million in 2006. The increase was principally attributable to a $17.3 million increase in corporate salaries and wages which was due to a significant increase in corporate and support staff. As of December 31, 2007 we had 2,227 employees as compared to 1,443 at December 31, 2006. The increase in corporate salaries and wages was partially offset by $4.6 million in capitalized general and administrative expenses, a $5.5 million decrease due to a legal settlement recorded in 2006 and a $1.6 million decrease in stock compensation expense. In accordance with the full-cost method of accounting, we capitalize internal costs that can be directly identified with our acquisition, exploration and development activities and do not include any costs related to production, general corporate overhead or similar activities. During 2006 we settled a legal dispute resulting in an additional loss on the settlement of $5.5 million. As part of a severance package for certain executive officers, the Board of Directors approved the acceleration of vesting of certain stock awards resulting in increased compensation expense recognized during 2006.

For the year ended December 31, 2007, we recorded a gain of $60.7 million ($26.2 million unrealized gain and $34.5 million realized gain) on our derivatives instruments compared to a $12.3 million gain ($1.9 million unrealized loss and $14.2 million realized gain) in 2006. During 2007, we selectively entered into natural gas swaps and basis swaps by capitalizing on what we perceived as spikes in the price of natural gas or favorable basis differences between the NYMEX price and natural gas prices at our principal West Texas pricing point of Waha Hub. Unrealized gains or losses on derivatives contracts represent the change in fair value of open derivatives positions during the period. The change in fair value is principally measured based on period end prices as compared to the contract price. The unrealized gain recorded during 2007 was attributable to a decrease in average natural gas prices at December 31, 2007 as compared to the average natural gas prices at the various contract dates.

MANAGEMENT DISCUSSION FOR LATEST QUARTER

Results of Operations

Three months ended March 31, 2008 compared to the three months ended March 31, 2007

Revenue. Total revenue increased 80.5% to $269.1 million for the three months ended March 31, 2008 from $149.1 million in the same period in 2007. This increase was due to a $115.3 million increase in natural gas and crude oil sales. Lower drilling and oil field services revenues partially offset the increases noted in midstream gas services and other segments.

Total natural gas and crude oil revenues increased $115.3 million to $205.5 million for the three months ended March 31, 2008 compared to $90.2 million for the same period in 2007, primarily as a result of an increase in natural gas and crude oil production volumes and prices received for our production. Total natural gas production increased 83.5% to 19,173 Mmcf in 2008 compared to 10,449 Mmcf in 2007, while crude oil production increased 55.5% to 611 MBbls in 2008 from 393 MBbls in 2007. The increase was due to our successful drilling in the WTO and an increased working interest in 2008 in the WTO as compared to the same period in 2007. The average price received, excluding the impact of derivative contracts, for our natural gas and crude oil production increased 27.8% in the 2008 period to $9.00 per Mcfe compared to $7.04 per Mcfe in 2007.

Drilling and services revenue decreased 55.8% to $12.3 million for the three months ended March 31, 2008 compared to $27.9 million in the same period in 2007. The decline in revenues is due to an increase in the number of company-owned rigs operating on company-owned natural gas and crude oil properties and the increase in working interest in these properties. Additionally, the average daily revenue per rig, after considering the effect of the elimination of intercompany usage, increased to approximately $17,500 per day during the first three months of 2008 as compared to an average rate of $16,600 per day during the same period in 2007.

Midstream and marketing revenue increased $20.2 million, or 77.2%, with revenues of $46.4 million in the three month period ended March 31, 2008 as compared to $26.2 million in the three month period ended March 31, 2007. This increase is due primarily to larger production volumes transported and marketed, during the three months ended March 31, 2008 as compared to the same period in 2007, for the third parties with ownership in our wells or ownership in other wells connected to our gathering systems.

Other revenue increased to $4.9 million for the three months ended March 31, 2008 from $4.8 million for the same period in 2007. Other revenue is generated primarily by our CO 2 gathering and sales operations.

Operating Costs and Expenses. Total operating costs and expenses increased to $331.9 million for the three months ended March 31, 2008 compared to $145.6 million for the same period in 2007 due to increases in production-related costs, general and administrative expenses as a result of an increase in corporate staff, depreciation, depletion and amortization and losses on derivative contracts. These increases were partially offset by a decrease in expenses attributable to our drilling and services.

Production expense includes the costs associated with our production activities, including, but not limited to, lease operating expense and processing costs. Production expenses increased $12.2 million primarily due to an increase in the number of wells in which we have a working interest. We owned working interests in 1,869 producing wells at March 31, 2008 compared to 1,333 producing wells at March 31, 2007. Production taxes increased $6.3 million, or 214.4%, to $9.2 million primarily due to the increase in production and the increased prices received for production during the three months ended March 31, 2008.

Drilling and services expenses decreased 61.8% for the three months ended March 31, 2008 as compared to the same period in 2007 primarily because of the increase in the number and working interest ownership of the wells we drilled for our own account.

Midstream and marketing expenses increased $17.0 million or 72.6% to $40.4 million due to larger production volumes transported and marketed during the three months ended March 31, 2008 on behalf of third parties than during the comparable period in 2007.

Depreciation, depletion and amortization (“DD&A”) for our natural gas and crude oil properties increased to $65.1 million for the three months ended March 31, 2008 from $32.7 million in the same period in 2007. Our DD&A per Mcfe increased $0.30 to $2.85 in the first quarter of 2008 from $2.55 in the comparable period in 2007. The increase is primarily attributable to an increase in our depreciable properties, higher future development costs and increased production. Our production increased 78.1% to 22.8 Bcfe from 12.8 Bcfe in 2007.

DD&A for our other assets consists primarily of depreciation of our drilling rigs, midstream gathering and compression facilities and other equipment. The increase in DD&A for our other assets was attributable primarily to higher carrying costs of our rigs due to upgrades and retrofitting and our midstream gathering and processing assets due to upgrades made throughout 2007. We calculate depreciation of property and equipment using the straight-line method over the estimated useful lives of the assets, which range from three to 25 years. Our drilling rigs and related oil field services equipment are depreciated over an average seven-year useful life.

General and administrative expenses increased $8.5 million to $21.0 million for the three months ended March 31, 2008 from $12.5 million for the comparable period in 2007. The increase was principally attributable to an $8.8 million increase in corporate salaries and wages due to a significant increase in corporate and support staff. As of March 31, 2008, we had 2,385 employees as compared to 1,746 at March 31, 2007. General and administrative expenses include non-cash stock compensation expense of $3.2 million for the three months ended March 31, 2008 as compared to $1.1 million for the comparable period in 2007. The increases in salaries and wages as well as stock compensation were partially offset by $3.2 million in capitalized general and administrative expenses for the three months ended March 31, 2008. There were no general and administrative expenses capitalized during the three months ended March 31, 2007.

For the three month period ended March 31, 2008, we recorded a loss of $136.8 million ($144.1 million unrealized loss and $7.3 million realized gain) on our derivative contracts compared to a $23.2 million loss ($21.7 million unrealized loss and $1.5 million realized loss) for the comparable period in 2007. During 2007 and the first three months of 2008, we selectively entered into natural gas and crude oil swaps and basis swaps in order to mitigate the effects of fluctuations in prices received for our production. Given the long-term nature of our investment in the WTO development program and the relatively high level of natural gas prices compared to budgeted prices, we believe it is prudent to enter into natural gas swaps and basis swaps for a portion of our production. Unrealized gains or losses on natural gas and crude oil derivative contracts represent the change in fair value of open derivative positions during the period. The change in fair value is principally measured based on period end prices as compared to the prior period end prices or contract price for contracts entered into during the period. The unrealized loss recorded in the three month period ended March 31, 2008 related to natural gas and crude oil commodities was attributable to an increase in average natural gas and crude oil prices at March 31, 2008 as compared to the average natural gas and crude oil prices at December 31, 2007 or the contract price for contracts entered into during the period.

Interest income decreased to $0.8 million for the three months ended March 31, 2008 from $1.1 million for the same period in 2007. This decrease was generally due to lower excess cash levels during the three months ended March 31, 2008 as compared to the same period in 2007.

Interest expense decreased to $25.2 million for the three months ended March 31, 2008 from $35.4 million for the same period in 2007. This decrease was primarily attributable to the expensing, in March 2007, of approximately $12.5 million in unamortized debt issuance costs related to our senior bridge facility at the time it was repaid. Also contributing slightly to the decrease for the three months ended March 31, 2008 was an $0.8 million unrealized gain related to our interest rate swap These decreases were partially offset by increased interest expense during the three months ended March 31, 2008 due to higher average debt balances outstanding during that period as compared to the same period in 2007.

During the three months ended March 31, 2008, we reported income from equity investments of $0.9 million as compared to $1.0 million in the comparable period in 2007.

We reported an income tax benefit of $30.5 million for the three months ended March 31, 2008, as compared to a benefit of $10.5 million for the same period in 2007. The current period income tax benefit represents an effective income tax rate of 35% which is unchanged from the same period in 2007.

Liquidity and Capital Resources

Summary

Our operating cash flow is influenced mainly by the prices that we receive for our natural gas and crude oil production; the quantity of natural gas we produce and, to a lesser extent, the quantity of crude oil we produce; the success of our development and exploration activities; the demand for our drilling rigs and oil field services and the rates we receive for these services; and the margins we obtain from our natural gas and CO 2 gathering and processing contracts.

On November 9, 2007, we completed the initial public offering of our common stock. We sold 32,379,500 shares of our common stock, including 4,170,000 shares sold directly to an entity controlled by our Chairman and Chief Executive Officer, Tom L. Ward. After deducting underwriting discounts of approximately $44.0 million and offering expenses of approximately $3.1 million, we received net proceeds of approximately $794.7 million.

As of March 31, 2008, our cash and cash equivalents were $0.7 million, and we had approximately $462.3 million available under our senior credit facility. Amounts outstanding under our senior credit facility at March 31, 2008 totaled $215.0 million. As of March 31, 2008, we had $1.3 billion in total debt outstanding.

Recent Developments

Increase in Borrowing Base. In April 2008, the Company’s senior credit facility was increased to $1.75 billion from $750 million and its borrowing base was increased to $1.2 billion from $700.0 million.

Exchange of Senior Term Loans. On May 1, 2008, the Company issued $650.0 million in Senior Notes due 2015 in exchange for an equal outstanding principal amount of its fixed rate term loans and $350.0 million of its Senior Floating Rate Notes due 2014 in exchange for an equal outstanding principal amount of its variable rate term loans. The exchange was made pursuant to a private placement exchange offer that commenced on March 28, 2008 and expired on April 28, 2008. The newly issued senior notes have terms that are substantially identical to those of the exchanged senior term loans, except that the senior notes have been issued with registration rights.

Conversion of Redeemable Convertible Preferred Stock. In May 2008, the Company converted the remaining outstanding 1,844,464 shares of its redeemable convertible preferred stock into 18,810,260 shares of its common stock as permitted under the terms of the redeemable convertible preferred stock. This conversion resulted in a one-time charge to retained earnings of $6.1 million in accelerated accretion expense related to the remaining offering costs of the redeemable convertible preferred shares. Prorated dividends totaling $0.5 million for the period from May 2, 2008 to the date of conversion (May 7, 2008) were paid to the holders of the converted shares on May 7, 2008.

Sale of Assets. In May 2008, we entered into an agreement, along with other parties, to sell substantially all of our assets located in the Piceance Basin of Colorado to a subsidiary of The Williams Companies, Inc. The total purchase price is $285 million with net proceeds to the Company estimated to be approximately $140 million, subject to closing adjustments and allocation of the sales price among multiple sellers. Assets to be sold include undeveloped acreage, working interests in wells, gathering and compression systems and other facilities related to the wells. The sale is subject to customary closing conditions and is expected to close during the second quarter of 2008.

Capital Expenditures

We make and expect to continue to make substantial capital expenditures in the exploration, development, production and acquisition of natural gas and crude oil reserves.

We estimate that our total capital expenditures for 2008, excluding acquisitions, will be approximately $1.5 billion. Our planned 2008 capital expenditures are consistent with 2007 levels. As in 2007, our 2008 capital expenditures for our exploration and production segment will be focused on growing and developing our reserves and production on our existing acreage and acquiring additional leasehold interests, primarily in the WTO. Of our total $1.5 billion capital expenditure budget, approximately $1.2 billion is budgeted for exploration and production activities. Included in our 2008 exploration and production capital expenditure budget is $723 million for drilling in the WTO, including the Piñon field, $241 million for drilling in areas other than the WTO, $33 million dedicated to our tertiary oil recovery program and $241 million for land and seismic. Based on encouraging initial results from our 3-D seismic acquisition program that we commenced in 2007, we have budgeted $151 million of our 2008 WTO capital expenditures to explore for new fields within the WTO. We plan to drill approximately 440 gross wells in 2008.

During 2008, we expect to complete our rig fleet expansion program that we started in 2005. We have accepted the delivery of all of the rigs ordered from Chinese manufacturers. We are in the process of retro-fitting and rigging up one of these rigs, which we expect to join our fleet during the second quarter of 2008. We are also continuing to upgrade and modernize our rig fleet. Approximately $67 million of our 2008 capital expenditure budget will be spent on our drilling and oil field services segment.

We anticipate spending approximately $195 million in capital expenditures in our midstream gas services and other segments as we expand our network of gas gathering lines and plant and compression capacity.

We believe that our cash flows from operations, current cash and investments on hand and availability under our senior credit facility will be sufficient to meet our capital expenditure budget for the next twelve months. The majority of our capital expenditures will be discretionary and could be curtailed if our cash flows decline from expected levels or we are unable to obtain capital on attractive terms; however, we have various sources of capital in the form of our revolving credit facility, potential asset sales or the incurrence of additional long-term debt.

Operating Activities. Net cash provided by operating activities for the three months ended March 31, 2008 and 2007 were $156.7 million and $44.0 million, respectively. The increase in cash provided by operating activities from 2007 to 2008 was primarily due to our 78.1% increase in production volumes as a result of our drilling success

in the WTO as well as various acquisitions throughout 2007 and the first three months of 2008. Also, contributing to this increase was a 27.8% increase in the combined average prices we received for the natural gas and crude oil produced. These increases were partially offset by increases in general and administrative costs, such as salaries and wages.

Investing Activities. Cash flows used in investing activities increased to $419.0 million in the three month period ended March 31, 2008 from $182.5 million in the comparable 2007 period as we continued to ramp up our capital expenditure program. For the three month period ended March 31, 2008, our capital expenditures were $354.8 million in our exploration and production segment, $17.9 million for drilling and oil field services, $38.7 million for midstream gas services and $7.2 million for other capital expenditures. During the same period in 2007, capital expenditures were $127.6 million in our exploration and production segment, $41.2 million for drilling and oil field services, $9.5 million for midstream gas services and $2.7 million for other capital expenditures.

Financing Activities. Since December 2005, we have used equity issuances, borrowings and, to a lesser extent, our cash flows from operations to fund our rapid growth. Proceeds from borrowings decreased to $340.2 million for the three months ended March 31, 2008, and we repaid approximately $128.9 million leaving net borrowings during the period of approximately $211.3 million. Our financing activities provided $199.9 million in cash for the three month period ended March 31, 2008 compared to $293.1 million in the comparable period in 2007.

Credit Facilities and Other Indebtedness

Senior Credit Facility. On November 21, 2006, we entered into a new $750.0 million senior secured revolving credit facility (the “senior credit facility”) with Bank of America, N.A., as Administrative Agent. The senior credit facility matures on November 21, 2011 and is available to be drawn on and repaid without restriction so long as we are in compliance with its terms, including certain financial covenants. The initial proceeds of the senior credit facility were used to (i) partially finance the NEG acquisition, (ii) refinance our existing senior secured revolving credit facility and NEG’s existing credit facility, and (iii) pay fees and expenses related to the NEG acquisition and our existing credit facility.

The senior credit facility contains various covenants that limit our and certain of our subsidiaries’ ability to grant certain liens; make certain loans and investments; make distributions; redeem stock; redeem or prepay debt; merge or consolidate with or into a third party; or engage in certain asset dispositions, including a sale of all or substantially all of our assets. Additionally, the senior credit facility limits our and certain of our subsidiaries’ ability to incur additional indebtedness.

The senior credit facility also contains financial covenants, including maintenance of agreed upon levels for (i) the ratio of total funded debt to EBITDAX (as defined in the senior credit facility), which may not exceed 4.5:1.0 calculated using the last fiscal quarter on an annualized basis as of the end of fiscal quarters ending on or before September 30, 2008 and calculated using the last four completed fiscal quarters thereafter, (ii) the ratio of EBITDAX to interest expense plus current maturities of long-term debt, which must be at least 2.5:1.0 calculated using the last four completed fiscal quarters, and (iii) the current ratio, which must be at least 1.0:1.0. As of March 31, 2008, we were in compliance with all of the covenants under the senior credit facility.

The obligations under the senior credit facility are secured by first priority liens on all shares of capital stock of each of our present and future subsidiaries; all intercompany debt of us and our subsidiaries; and substantially all of our assets and the assets of our guarantor subsidiaries, including proved natural gas and crude oil reserves representing at least 80% of the present discounted value (as defined in the senior credit facility) of our proved natural gas and crude oil reserves reviewed in determining the borrowing base for the senior credit facility (as determined by the administrative agent). Additionally, the obligations under the senior credit facility are guaranteed by certain of our subsidiaries.

The borrowing base is subject to review semi-annually; however, the lenders reserve the right to have one additional redetermination of the borrowing base per calendar year. Unscheduled redeterminations may be made at our request, but are limited to one request per year. The borrowing base is determined based on proved developed producing reserves, proved developed non-producing reserves and proved undeveloped reserves and was $700.0 million as of March 31, 2008. As of March 31, 2008, we had outstanding indebtedness of $237.7 million under our senior credit facility, including outstanding letters of credit of $22.7 million. The committed loan amount for the facility was increased to $1.75 billion and the borrowing base was increased to $1.2 billion during April 2008. As of May 5, 2008, the balance outstanding under our senior credit facility was $410.0 million.

At our election, interest under the senior credit facility is determined by reference to (i) LIBOR plus an applicable margin between 1.25% and 2.00% per annum or (ii) the higher of the federal funds rate plus 0.5% or the prime rate plus, in either case, an applicable margin between 0.25% and 1.00% per annum. Interest is payable quarterly for prime rate loans and at the applicable maturity date for LIBOR loans, except that if the interest period for a LIBOR loan is six months, interest is paid at the end of each three-month period. The average interest rate paid on amounts outstanding under our senior credit facility for the three month period ended March 31, 2008 was 4.57%.

Senior Term Loans. On March 22, 2007, we issued $1.0 billion principal amount of senior unsecured term loans. The proceeds of the term loans were used to partially repay the senior bridge facility described below. The senior term loans include both a floating rate tranche and fixed rate tranche as described below.

We issued $350.0 million at a variable rate with interest payable quarterly and principal due on April 1, 2014 (the “variable rate term loans”). The variable rate term loans bear interest, at our option, at LIBOR plus 3.625% or the higher of (i) the federal funds rate, as defined, plus 3.125% or (ii) a bank’s prime rate plus 2.625%. After April 1, 2009, the variable rate term loans may be prepaid in whole or in part with a prepayment penalty. The average interest rates paid on amounts outstanding under our variable rate term loans for the three month period ended March 31, 2008 was 8.36%. In January 2008, we entered into a $350 million notional amount interest rate swap agreement with a financial institution that effectively fixed our interest rate on the variable rate term loans at 6.2625% for the period from April 1, 2008 to April 1, 2011.

We also issued $650.0 million at a fixed rate of 8.625% with principal due on April 1, 2015 (the “fixed rate term loans”). Under the terms of the fixed rate term loans, interest is payable quarterly and during the first four years interest may be paid, at our option, either entirely in cash or entirely with additional fixed rate term loans. If we elect to pay the interest due during any period in additional fixed rate term loans, the interest rate increases to 9.375% during such period. After April 1, 2011, the fixed rate term loans may be prepaid in whole or in part with prepayment penalties.

On March 28, 2008, we commenced an offer to exchange the senior term loans for senior unsecured notes with registration rights, as required under the senior term loan credit agreement. The offer expired on April 28, 2008, and on May 1, 2008, we issued $650.0 million of Senior Notes due 2015 in exchange for an equal outstanding principal amount of fixed rate term loans and $350.0 million of Senior Floating Rate Notes due 2014 in exchange for an equal outstanding principal amount of variable rate term loans. The newly issued senior notes have terms that are substantially identical to those of the exchanged senior term loans, except that the senior notes have been issued with registration rights.

Debt covenants under the senior term loans include financial covenants similar to those of the senior credit facility and include limitations on the incurrence of indebtedness, payment of dividends, asset sales, certain asset purchases, transactions with related parties and consolidation or merger agreements. We incurred $26.1 million of debt issuance costs in connection with the senior term loans. These costs are included in other assets and amortized over the term of the senior term loans.

Other Indebtedness. We have financed a portion of our drilling rig fleet and related oil field services equipment through notes payable. At March 31, 2008, the aggregate outstanding balance of these notes was $44.3 million, with annual fixed interest rates ranging from 7.64% to 8.87%. The notes have a final maturity date of December 1, 2011, require aggregate monthly installments for principal and interest in the amount of $1.2 million and are secured by the equipment. The notes have a prepayment penalty (currently ranging from 1 to 3%) that is triggered if we repay the notes prior to maturity.

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