UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K

Annual Report Pursuant to Section 13 or 15(d)
of the Securities Exchange Act of 1934

Carrizo Oil & Gas, Inc.

Texas		76-0415919
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)
1000 Louisiana Street, Suite 1500 Houston, Texas (Principal executive offices)		77002 (Zip Code)

Registrant’s telephone number, including area code: (713) 328-1000

Securities Registered Pursuant to Section 12(b) of the Act:

     Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.  

YES o NO þ

     Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Exchange Act.

YES o NO þ

     Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    

YES þ NO o

     Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.  o

     Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting Company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act (Check one):

Large accelerated filer þ		Accelerated filer o		Non-accelerated filer   o (Do not check if a smaller reporting company)		Smaller Reporting Company o

     Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).

YES o NO þ

     At June 29, 2007, the aggregate market value of the registrant’s Common Stock held by non-affiliates of the registrant was approximately $952.8 million based on the closing price of such stock on such date of $41.47.

     At February 15, 2008, the number of shares outstanding of the registrant’s Common Stock was 28,018,346.

      DOCUMENTS INCORPORATED BY REFERENCE

     Portions of the definitive proxy statement for the Registrant’s 2008 Annual Meeting of Shareholders are incorporated by reference in Part III of this Form 10-K. Such definitive proxy statement will be filed with the Securities and Exchange Commission not later than 120 days subsequent to December 31, 2007.

 

 

TABLE OF CONTENTS

PART I			2
Item 1. and Item 2. Business and Properties			2
Item 1A. Risk Factors			22
Item 1B. Unresolved Staff Comments			30
Item 3. Legal Proceedings			33
Item 4. Submission of Matters to a Vote of Security Holders			33
Executive Officers of the Registrant			33
PART II			34
Item 5. Market for Registrant’s Common Stock, Related Shareholder Matters and Issuer Purchases of Equity Securities			34
Item 6. Selected Financial Data			35
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations			37
Item 7A. Qualitative and Quantitative Disclosures About Market Risk			50
Item 8. Financial Statements and Supplementary Data			51
Item 9. Changes In and Disagreements With Accountants on Accounting and Financial Disclosure			51
Item 9A. Controls and Procedures			51
Item 9B. Other Information			53
PART III			53
Item 10. Directors, Executive Officers and Corporate Governance			53
Item 11. Executive Compensation			53
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Shareholder Matters			53
Item 13. Certain Relationships and Related Transactions, and Director Independence			53
Item 14. Principal Accountant Fees and Services			53
PART IV			53
Item 15. Exhibits and Financial Statement Schedules			53
Third Amendment to Credit Agreement
Director Compensation
Base Salaries and 2007 Annual Bonuses for Certain Executive Officers
Subsidiaries
Consent of Pannell Kerr Forster of Texas, P.C.
Consent of Ryder Scott Company Petroleum Engineers
Consent of Fairchild & Wells, Inc.
Consent of LaRoche Petroleum Consultants, Ltd.
Certification of CEO Pursuant to Section 302
Certification of CFO Pursuant to Section 302
Certification of CEO Pursuant to Section 906
Certification of CFO Pursuant to Section 906
Summary of Reserve Report
Summary of Reserve Report
Summary of Reserve Report

PART I

 
Item 1. and Item 2. Business and Properties

 
General

     Carrizo Oil & Gas, Inc. (“Carrizo,” the “Company” or “We”) is an independent energy company engaged in the exploration, development and production of natural gas and oil. Our current operations are focused in proven, producing natural gas and oil geologic trends in the Barnett Shale area in North Texas and along the onshore Gulf Coast area in Texas and Louisiana, primarily in the Miocene, Wilcox, Frio and Vicksburg trends. Our other interests include properties in the U.K. North Sea and acreage in shale plays in the Fayetteville in Arkansas, Barnett/Woodford in West Texas/New Mexico, Floyd/Neal in Mississippi, the western New Albany in Kentucky/Illinois and the Marcellus in Pennsylvania/New York. We also have coalbed methane investments in the Rocky Mountains, largely through our minority interest in Pinnacle Gas Resources, Inc.

     We have traditionally grown our production through our 3-D seismic-driven exploratory drilling program. Our compound production growth rate for the period December 31, 2003 through December 31, 2007 on an annualized basis was 23.6%. From our inception through December 31, 2007, we participated in the drilling of 604 wells (268.5 net) with an apparent success rate of approximately 70.8% in our onshore Gulf Coast area and an apparent success rate of 100% in the Barnett Shale area in North Texas (also called “Barnett Shale area” or “Ft. Worth Barnett Shale area”). Exploratory wells accounted for 79% of the total wells we drilled. Our total proved reserves as of December 31, 2007 were an estimated 347.6 Bcfe with a pre-tax PV-10 value of $840.0 million. During 2007, we added a record 155.1 Bcfe to proved reserves and produced a record 17.5 Bcfe. We finance the majority of our drilling activity through internal cash flow generated primarily from oil and natural gas production sales revenue, proceeds from the issuance of equity securities and borrowings under our credit facilities.

     As a main component of our business strategy, we have acquired licenses for over 12,385 square miles of 3-D seismic data for processing and evaluation. Historically, we either (1) sought to acquire seismic permits from landowners that included options to lease the acreage prior to conducting proprietary surveys or (2) participated in 3-D group shoots in which we typically sought to obtain leases or farm-ins rather than lease options. Our 3-D seismic holdings in our onshore Gulf Coast area have remained relatively unchanged in recent years with approximately 8,396 square miles. Since 2003, we have also grown our 3-D seismic holdings in the Barnett Shale area to over 491 square miles.

     One of our primary strengths is the experience of our management and technical staff in the development, processing and analysis of this 3-D seismic data to generate and drill natural gas and oil prospects. Our technical and operating employees have an average of over 20 years of industry experience, in many cases with major and large independent oil and gas companies, including Shell Oil, Ocean Energy, ARCO, Conoco, Burlington Resources, Unocal, Pennzoil and Tenneco. Analyzing and reprocessing our 3-D seismic database, our highly qualified technical staff is continually adding to and refining our substantial inventory of drilling locations.

     We believe that our utilization of large-scale 3-D seismic surveys and related technology allows us to create and maintain a multiyear inventory of high-quality exploration prospects. As of December 31, 2007, we had 198,930 net acres in Texas and Louisiana under lease or lease option (all references to acres under lease in this Form 10-K also include lease option acres unless otherwise indicated), including 85,429 net acres in our Barnett Shale area, 50,312 net acres in our onshore Gulf Coast area, predominantly all covered by 3-D seismic data, and 58,297 net acres in our West Texas Woodford/Barnett Shale area. We have identified: (1) over 817 potential exploratory and development horizontal drilling locations on our leased acreage in the Ft. Worth Barnett Shale area and (2) 136 potential exploratory drilling locations in our onshore Gulf Coast area, comprised of 69 leased exploratory drillsites, 26 of which are field extension wells based on initial drilling activities, and 67 seismically defined prospects on which we are pursuing acreage. The vast majority of our 3-D seismic data covers productive geological trends in our onshore Gulf Coast area, where we have made 269 completions as a result of our utilization and evaluation of this data.

     In our onshore Gulf Coast area, most of our drilling targets prior to 2000 were shallow (from 4,000 to 7,000 feet), normally pressured reservoirs that generally involved moderate cost (typically $0.3 million to $0.4 million per completed well) and risk. Since then, the depth of many of the wells that we have drilled, as well as our current drilling prospects, are deeper, over-pressured targets with greater economic potential but generally higher cost (typically $1.0 million to $4.0 million per completed well) and risk. We seek to sell a portion of these deeper prospects to reduce our exploration risk and financial exposure while retaining significant upside potential. More recently, we have begun to retain larger percentages of, and increased our exposure to, higher cost, higher potential wells.

     In mid-2003, we became active in the Barnett Shale area in North Texas (primarily in the Tarrant, Parker, Denton, Johnson,

Hill and Erath counties). Improvements in fracture techniques in recent years have dramatically changed the economics of producing reserves in the Barnett Shale, which is now considered one of the most active natural gas plays in North America. The reserve profile from the typical productive wells we drill in the Barnett Shale area is notably longer-lived compared to the typical reserve profile from our wells drilled in our onshore Gulf Coast area.

     We are drilling primarily horizontal wells in the Barnett Shale area. Typical costs to drill and complete a horizontal well range from approximately $2.0 million to $3.5 million. Our Barnett horizontal wells generally have target depths of 8,500 to 11,500 feet including the lateral section. During 2007, we held an average 78 percent working interest participation in the Barnett wells drilled as we shifted to a primarily Carrizo-operated program and operated a majority of the wells drilled. For wells drilled in 2008, we plan to increase our average working interests to between 90 and 95 percent.

     Accordingly, we believe that continued development of producing reserves in the Barnett Shale play has lengthened our overall average reserve life and, on balance, added a long-lived cash flow stream to help fund our future capital exploration and development program. In our Barnett Shale area through December 31, 2007, we had acquired 85,429 net acres, drilled 182 gross (118.2 net) wells and increased our total proved reserves in the Barnett Shale area to 276.0 Bcfe. As of February 7, 2008, our current net production in the Barnett Shale area was estimated at 57 MMcfe/d.

     As of December 31, 2007, we operated 153 producing oil and gas wells, which accounted for approximately 75% of the onshore Gulf Coast area production and approximately 85% of the Barnett Shale production.

     During 2001, through our wholly-owned subsidiary, CCBM, Inc. (“CCBM”), we acquired 50% of the working interests held by Rocky Mountain Gas, Inc. (“RMG”) in approximately 107,000 net mineral acres prospective for coalbed methane located in the Powder River Basin in Wyoming and Montana. In 2003, we contributed a majority of our coalbed methane property interests into a newly formed company, Pinnacle Gas Resources, Inc. (“Pinnacle”), in return for an interest in Pinnacle. As of December 31, 2007, we owned approximately 8.3% of the common stock of Pinnacle on a fully diluted basis. During the second quarter of 2007, Pinnacle became a publicly traded entity on the Nasdaq Global Market.

     Certain terms used herein relating to the oil and natural gas industry are defined in “Glossary of Certain Industry Terms” below.

Business Strategy

Growth Through the Drillbit

     Our objective is to create shareholder value through the execution of a business strategy designed to capitalize on our strengths. Key elements of our business strategy include:

	•		Grow Primarily Through Drilling. We are pursuing an active technology-driven exploration drilling program. We generate exploration prospects through geological and geophysical analysis of 3-D seismic and other data. Our ability to successfully define and drill exploratory prospects is demonstrated by our exploratory drilling success rate in the onshore Gulf Coast area of 85% over the last four years and a 100% drilling success rate in our Barnett Shale area since inception in 2003. During 2008, we are drilling or plan to drill approximately 15 gross (5.8 net) wells in the onshore Gulf Coast area and 68 gross (62.6 net) wells in the Barnett Shale area. We have planned approximately $300 million for capital expenditures in 2008, approximately $250 million of which we expect to use for drilling activities, including $185 million in the Barnett Shale area and $23 million in onshore Gulf Coast area.
	•		Focus on Prolific and Industry-Proven Trends. We focus our activities both in the industry-proven Barnett Shale trend in which our wells have generally longer-lived reserves and the prolific onshore Gulf Coast area where our management, our technical staff and our field operations teams have significant prior experience. Although we have broadened our areas of operations to include the Rocky Mountains, the U.K. North Sea and shale trends in Arkansas, West Texas/New Mexico, Mississippi/Alabama, Illinois/Kentucky and Pennsylvania/New York, we plan to focus a majority of our near-term capital expenditures in the Barnett Shale area in North Texas, where we have acquired a significant acreage position and accumulated a large drillsite inventory, and in the onshore Gulf Coast area, where we believe our accumulated data and knowledge base provide a competitive advantage.
	•		Aggressively Evaluate 3-D Seismic Data and Acquire Acreage to Maintain a Large Drillsite Inventory. We have accumulated and continue to add to a multiyear inventory of 3-D seismic and geologic data along the prolific producing trend of the onshore Gulf Coast area and industry-proven trend of the Barnett Shale area. We continue to

			evaluate and acquire acreage in new emerging resource project areas. In 2007, we added approximately 588 square miles of newly released or proprietary 3-D seismic data. We believe our utilization of large-scale 3-D seismic surveys and related technology provides us with the opportunity to maximize our exploration success in the Gulf Coast, Barnett Shale, and new resource project areas. As of December 31, 2007, we had accumulated licenses for approximately 12,385 square miles of 3-D seismic data (including 10,786 square miles in our significant project areas) and identified over 953 drilling locations and extension opportunities (comprised of 817 locations in the Barnett Shale area and 136 locations in the Gulf Coast area). We believe our use of 3-D seismic surveys reduces, but does not eliminate, the risk of drilling.
	•		Maintain a Balanced Exploration Drilling Portfolio. We seek to balance our drilling program between projects with relatively lower risk and moderate potential and drilling prospects that have relatively higher risk and substantial potential. We believe we have furthered this strategy through the expansion of the Barnett Shale operations in which our wells generally have longer-lived reserves and generally lower risk/lower reward than our average onshore Gulf Coast area wells. We will continue to expand our exploratory drilling portfolio, including lease acquisitions with exploration potential.
	•		Manage Risk Exposure by Market Testing Prospects and Optimizing Working Interests. We seek to limit our financial and operating risks by varying our level of participation in drilling prospects with differing risk profiles and by seeking additional technical input and economic review from knowledgeable industry participants regarding our prospects. Additionally, we rely on advanced technologies, including 3-D seismic analysis, to better define geologic risks, thereby enhancing the results of our drilling efforts. The use of 3-D seismic analysis does not guarantee that hydrocarbons are present or, if present, that they can be recovered economically. We also seek to operate our projects in order to better control drilling costs and the timing of drilling.
	•		Retain and Incentivize a Highly Qualified Technical Staff. We employ 36 natural gas and oil professionals, including geophysicists, petrophysicists, geologists, petroleum engineers and production and reservoir engineers and technical support staff, who have an average of over 20 years of experience. This level of expertise and experience gives us an in-house ability to apply advanced technologies to our drilling and production activities, including our extensive experience in fracturing and horizontal drilling technologies. Our technical staff is granted stock-based awards and participates in an incentive bonus pool based on production resulting from our exploratory successes.

Exploration Approach

     In the Barnett Shale area, our exploration strategy has been to accumulate significant leasehold positions with known shale thickness and thermal maturity in the proximity of known or emerging pipeline infrastructures, followed by the acquisition and processing of 3-D seismic data.

     In the onshore Gulf Coast area, our exploration strategy has generally been to accumulate large amounts of 3-D seismic data along primarily prolific, producing trends after obtaining options to lease areas covered by the data. We typically seek to explore in locations within our areas of expertise that we believe have numerous accumulations of normally pressured reserves at shallow depths and in geologic traps that are difficult to define without the interpretation of 3-D seismic data or the potential for large accumulations of deeper, over-pressured reserves.

     In emerging resource project areas, our strategy has been to acquire acreage positions in plays that exhibit geologic and economic characteristics that meet our criteria described in the preceding paragraphs. We strive to achieve a balance between acquiring acreage and timely project evaluation through the drillbit to ensure that we minimize the costs to test for commercial reserves while building a significant lease position.

     As a result of the increased availability of economic onshore 3-D seismic surveys and the improvement and increased affordability of data interpretation technologies, we have relied almost exclusively on the interpretation of 3-D seismic data in our exploration strategy. We generally do not invest any substantial portion of the drilling costs for an exploration well without first interpreting 3-D seismic data. The principal advantage of 3-D seismic data over traditional 2-D seismic analysis is that it affords the geoscientist the ability to interpret a three dimensional cube of data as compared to interpreting between widely separated two dimensional vertical profiles. Consequently, the geoscientist is able to more fully and accurately evaluate prospective areas, improving the probability of drilling commercially successful wells in both exploratory and development drilling.

     Even in the relatively lower-risk, reserve-proven trends, such as the Barnett Shale trend, 3-D seismic data interpretation is instrumental in our exploration approach, significantly reducing geologic risk and allowing optimized reserve development.

     Historically, we sought to obtain large volumes of 3-D seismic data by participating in large seismic data acquisition programs either alone or pursuant to joint venture arrangements with other energy companies, or through “group shoots” in which we shared the costs and results of seismic surveys. By participating in joint ventures and group shoots, we were able to share the up-front costs of seismic data acquisition and interpretation, thereby enabling us to participate in a larger number of projects and diversify exploration costs and risks. Most of our operations are conducted through joint operations with industry participants.

     We have also participated in 3-D data licensing swaps, whereby we transfer license rights to certain proprietary 3-D data we own in exchange for license rights to other 3-D data within our areas, thus allowing us to obtain access to additional 3-D data within our onshore Gulf Coast area at either minimal or no out-of-pocket cash cost. Since 2001, we also have made significant purchases of 3-D data from the libraries of seismic companies at favorable pricing.

     In more recent years, we have focused less on conducting proprietary 3-D surveys and have focused instead on (1) the continual interpretation and evaluation of our existing 3-D seismic database and the drilling of identified prospects on such acreage and (2) the acquisition of existing non-proprietary 3-D data at reduced prices, in many cases contiguous to or near existing project areas where we have extensive knowledge and subsequent acquisition of related acreage as we deem to be prospective based upon our interpretation of such 3-D data.

     In late 2005, we entered into an agreement that committed us to acquire approximately 800 square miles of 3-D seismic data in our onshore Gulf Coast area over a three-year period. In 2007, we increased this commitment of 3-D seismic data by an additional 225 square miles of data over the next two years. Specific operating areas to which new data were added as a result of the 2007 data acquisition include 157 square miles of newly released 3-D data in south Louisiana and 302 square miles of newly released 3-D data in Texas. These data acquisitions consist of existing nonproprietary data sets obtained from seismic companies at what we believe to be attractive pricing.

     We maintain a flexible and diversified approach to project identification by focusing on the estimated financial results of a project area rather than limiting our focus to any one method or source for obtaining leads for new project areas. Our current project areas result from leads developed primarily by our internal staff. Additionally, we monitor competitor activity and review outside prospect generation by small, independent “prospect generators,” or our joint venture partners. We complement our exploratory drilling portfolio through the use of these outside sources of project generation and typically retain operation rights. Specific drill-sites are typically chosen by our own geoscientists.

Operating Approach

     Our management team has extensive experience in the development and management of exploration projects in the Barnett Shale area and along the Texas and Louisiana Gulf Coast. We believe that the experience we have gained in the Barnett Shale area, along with our extensive experience in fracturing and horizontal drilling technologies and the experience of our management in the development, processing and analysis of 3-D projects and data in the onshore Gulf Coast will play a significant part in our future success.

     We generally seek to obtain lease operator status and control over field operations, and in particular seek to control decisions regarding 3-D survey design parameters and drilling and completion methods. As of December 31, 2007, we operated 153 producing oil and natural gas wells. Although we initially did not act as operator for most of our projects in the Barnett Shale area, we now generally seek to control operations for most new exploration and development in that area, taking advantage of our technical staff experience in horizontal drilling and hydraulic fracturing.

     We emphasize preplanning in project development to lower capital and operational costs and to efficiently integrate potential well locations into the existing and planned infrastructure, including gathering systems and other surface facilities. In constructing surface facilities, we seek to use reliable, high quality, used equipment in place of new equipment to achieve cost savings. We also seek to minimize cycle time from drilling to hook-up of wells, thereby accelerating cash flow and improving ultimate project economics.

     We seek to use advanced production techniques to exploit and expand our reserve base. Following the discovery of proved reserves, we typically continue to evaluate our producing properties through the use of 3-D seismic data to locate undrained fault blocks and identify new drilling prospects and perform further reserve analysis and geological field studies using computer aided exploration techniques. We have integrated our 3-D seismic data with reservoir characterization and management systems through the use of geophysical workstations which are compatible with industry standard reservoir simulation programs.

SIGNIFICANT PROJECT AREAS

     This section is an explanation and detail of some of the relevant project groupings from our overall inventory of productive wells, seismic data and prospects. Our operations are focused primarily in the Barnett Shale trend in North Texas and in the onshore Gulf Coast area extending from South Louisiana to South Texas. Our other areas of interest are in the Camp Hill Field in Texas, Other Texas areas, the U.K. North Sea and Other Shale trends in West Texas, New Mexico, Mississippi, Alabama, Kentucky, Arkansas, Pennsylvania, New York and North Dakota. The table below highlights our main areas of activity:

										3-D Seismic				Net Options/				Drilling Capital
		Productive Wells								Data				Leased				Expenditures
		Gross				Net				(Sq. Miles)				Acres				2007				2008 Plan
																		(In millions)
Barnett Shale			145				93.6				491				85,429			$	132.4			$	184.9
Gulf Coast			102				31.7				8,396				50,312				22.8				22.7
Camp Hill			54				52.9				—				1,470				2.0				5.6
Other Texas			—				—				531				11,025				1.6				8.0
Other Shales			4				0.1				18				244,625				6.9				9.6
U.K. North Sea			—				—				1,350				24,798				9.4				17.3
Total			305				178.3				10,786				417,659			$	175.1			$	248.1

Barnett Shale Area

     We began active participation in the Barnett Shale area in the Fort Worth Basin on acreage located west of the city of Fort Worth, Texas in mid-2003. In 2003, we acquired leases on approximately 4,100 net acres and invested $0.9 million to drill six wells (2.6 net), two of which were completed and producing and four of which were awaiting pipeline hookup at year end. Net production from the two online wells (0.6 net) was a combined 380 Mcfe per day at year end 2003.

     In February 2004 we purchased specified wells and leases in the Barnett Shale trend in Denton County, Texas from a private company for $8.2 million. These non-operated properties have an average 39 percent working interest. The acquisition included 21 existing gross wells (6.7 net) and interests in approximately 1,500 net acres. Production at year end 2004 was approximately 2,800 Mcfe/d.

     In April 2005 we acquired 600 net acres and working interests in 14 existing wells (7.3 net) with an estimated 5.4 MMcfe of proved reserves in the Barnett Shale trend for $2.3 million in cash and 112,697 shares of our common stock. In 2005, we drilled 37 additional wells (22.1 net) and acquired an additional 49,632 net acres.

     In 2006, we drilled 46.0 additional wells (33.9 net) and acquired an additional 6,400 net acres, increasing our acreage at the end of 2006 to 86,752 net acres (primarily in Tarrant, Parker, Denton, Johnson, Hill and Erath counties). Carrizo was operator on 32 of the gross wells drilled. At year-end 2006, 31 of the gross wells drilled were producing and the remaining 15 wells were awaiting completion and/or pipeline connection.

     During 2007, we drilled 60 additional wells (46.5 net) and our net acreage position was 85,429 net acres at December 31, 2007. Net proved reserves have grown by 88% from 146.6 Bcfe on December 31, 2006 to 276.0 Bcfe on December 31, 2007. We expect to invest approximately $184.9 million (representing nearly 75% of our total 2008 drilling expenditures) to drill 68 gross (62.6 net) wells in this area in 2008.

     On January 3, 2008 we announced that the four New Dawn horizontal wells located in southeast Tarrant County, Texas completed fracture stimulation and began sales at a combined initial flow rate of 17.0 MMcf/d gross (12.8 MMcf/d net). These wells, in addition to three horizontal wells in the Tier 1 Parker County area, helped bring our year-end 2007 aggregate net production rate in the Barnett Shale to approximately 48 Mmcfe/d, 153% higher than the year-end 2006 rate of 19 MMcfe/d. In addition, the five wells on our Taylor lease in southeast Tarrant County that began production and sales in early February  2008 had gross production rates totaling 23.0 MMcfe/d. Including these new wells, our estimated net production in the Barnett Shale as of February 7, 2008 was an estimated 57 MMcfe/d.

     We currently operate four rigs that are drilling horizontal wells in the Barnett Shale and we have contracted for a fifth rig in this area that will commence drilling beginning in April 2008. One of these rigs is dedicated to drilling our lease on The University of Texas at Arlington and adjacent areas. The drilling of the first well on The

University of Texas at Arlington campus is complete, and a second well was spud on January 2, 2008. Once six wells have been drilled, all six will be fracture stimulated and, if successful, begin sales before additional drilling begins.

Gulf Coast Area

     Our Gulf Coast area generally contains geologically complex as well as amplitude and amplitude versus offset supported natural gas objectives well-suited for drilling using 3-D seismic evaluation.

     In our Gulf Coast area, we have a total inventory of 69 leased exploratory drillsites, 26 of which are field extension wells based on initial drilling success. We are pursuing acreage on an additional 67 seismically defined prospects. We plan to spend approximately $22.7 million on drilling expenditures in 2008, comprised of approximately 15 gross wells (5.8 net). We also plan to spend $1.9 million to purchase and reprocess 3-D seismic surveys during 2008.

     We have licenses for approximately 8,396 square miles of 3-D seismic data and 50,312 net acres of leasehold in the Gulf Coast area. From January 1, 2003 through December 31, 2007, we drilled and completed 96 wells (28.1 net) on 113 attempts in this area. In 2007, we incurred capital drilling expenditures of $22.8 million and drilled 8 gross (2.3 net) wells, four of which were in Southeast Texas and included the Doberman #1 well.

Camp Hill Field

     We own interests in approximately 2,611 gross acres in the Camp Hill Field in Anderson County, Texas. We currently operate all of these leases. During the year ended December 31, 2007, the project produced an average of 26 Bbls/d of 19 API gravity oil. The wells produce from a depth of 500 feet and have utilized and plan to utilize a tertiary steam drive as an enhanced oil recovery process. Although efficient at maximizing oil recovery, the steam drive process is relatively expensive to operate because natural gas or produced crude is burned to create the steam injectant. Lifting costs during the year ended December 31, 2007 averaged $96.70 per barrel ($16.12 per Mcfe). Costs were high, as expected, because oil production response typically lags the startup of steam injection. Over the remaining reserve life of the Camp Hill field, as presented in the 2007 year-end reserve report, we estimate the average future operating cost, including steam cost, to be approximately $18.60 per barrel (or $3.11 Mcfe). The oil produced, although viscous, commands a comparable price to West Texas Intermediate crude (an average premium of $0.15 per Bbl to Koch WTI during the year ended December 31, 2007) due to its suitability as a lube oil feedstock.

     As of December 31, 2007, we had 8.0 MMBbls of proved oil reserves in this project, with 1.6 MMBbls of oil reserves currently developed. The proved undeveloped reserves at the Camp Hill Field constitute 11% of our proved reserves and account for 17% of our present value of net future revenues from proved reserves as of December 31, 2007. We have an average working interest of approximately 92.1% in this field and an approximate net revenue interest of 71.0%.

     Prior to 2003, we estimated an ultimate recovery efficiency (i.e. the percentage of the oil in the ground that we would be able to produce economically) after steam drive of 45% of the original oil in place in the Camp Hill Field. As of January 1, 2003, we raised our estimate to an ultimate recovery of 55% of the estimated original oil in place based upon our review of recovery efficiencies from prior projects by other companies in both the Camp Hill Field as well as in nearby projects that we considered to have similar geologic and hydrocarbon attributes. We lowered our estimated recovery efficiency as of December 31, 2005 to 49% of the estimated original oil in place in the field. We believe this revised recovery efficiency is reasonable, particularly in light of the fact that a project that we have operated in the Camp Hill Field since 1993 has a current 49% recovery efficiency as of December 31, 2007 and is currently still producing.

     Although we have increased our development activities in the Camp Hill Field since 2005, this follows an extended period during which we deferred development in the field. We deferred development (1) to optimize returns by awaiting an economic entry point for developing a cogeneration plant as further explained below, (2) to pursue other opportunities in both our onshore Gulf Coast and later, Barnett Shale areas with higher rates of return and (3) to continue increasing our net acreage position in the field in a competitive environment. Although we at all times believed that we could develop this field on a profitable basis, we nonetheless believed that we were optimizing our economic position by deferring development. We acquired our initial interests in the Camp Hill Field in 1993. We performed remedial work on the existing wells and steam generators and began injecting steam in March 1994. From 1994 through 1998 and during the first nine months of 2000, we injected steam in 31 patterns. In the fourth quarter of 2000, we suspended steam injection in response to high fuel gas prices and to pursue a lower steam cost solution through our cogeneration negotiations. Thereafter, we drilled one well in 2001, seven wells in 2005, ten wells (including six injection wells) in 2006 and 30 wells (including 13 injection wells) in 2007.

     The most important reason for our delay in both resuming steam injection and moving to full development was the potential for significantly improved profitability that would result from the construction of a nearby cogeneration plant. Cogeneration plants typically provided steam at less than half the cost of small steam generators. Steam costs are critical to

the economics of the development of the field. Expected steam costs far outweigh the capital costs for the development of the Camp Hill Field. We currently estimate approximately $129.3 million in steam costs compared to $21.4 million for drilling and development capital that is needed to fully develop the proved undeveloped reserves in this field. Previously, our management believed that the demand for electricity in the East Texas area would increase in the future such that it would become lucrative for us or a third party to build a cogeneration plant in the area. In this cogeneration plant, a gas turbine would be used to generate electricity, and the waste heat would be used to produce steam. The steam would be captured for injection in the Camp Hill Field, while the electricity would be sold into the Texas electric power grid. In 2000, we engaged in discussions with another party regarding the building of a cogeneration facility, but we ultimately did not reach acceptable terms with that party. We subsequently continued to explore the possibility of a cogeneration facility in the Camp Hill Field and worked with electricity industry consultants in 2002 and 2005.

     During the time we were continuing to assess the relative attractiveness of building a cogeneration plant, and in light of relatively high fuel gas costs at that time, we pursued other exploration projects primarily along the onshore Gulf Coast and in the Barnett Shale, starting in 2003, that we believed offered us potentially higher rates of return. These other projects have been the primary focus of our operations over the last several years. Our timing of Camp Hill development has also been impacted by our leasing activities in the field by which we increased our working interest and net revenue interest in our leases in the field so that we would own a greater share of these properties when we later developed them. We believe that we were able to increase our interests on more favorable terms by deferring the full scale development of the field. The addition of working interests in the Camp Hill leases further improved the economics of the development of this field as well as favorably affect the development plan for the steam drive patterns in the field.

     In mid-2005, we reengaged an electricity industry consultant with cogeneration experience to further investigate the feasibility of establishing a cogeneration plant in the area. After extensive discussions with the consultant, we concluded that there continued to be overcapacity of electricity in the regional market and that overcapacity was not likely to reverse itself in the near term and that the capital expenditures associated with building a cogeneration plant were not likely to be warranted for a period of several years. As a result, we determined that, rather than awaiting the construction of a cogeneration plant, we would instead further develop our Camp Hill properties with the existing steam generators.

     In August 2005, management proposed the acceleration of the Camp Hill development to our board of directors. Accordingly, a development plan was formally approved by the board for increased drilling activity in the Camp Hill Field, beginning with an initial 60-well drilling program. In February 2006, our board of directors formally approved a multi-year plan to fully develop the entire Camp Hill Field. In furtherance of this plan, we expect to drill 40 gross wells (40.0 net), including 17 service wells, in this area at an estimated cost of $5.6 million during 2008. To fully develop the field, we expect to drill approximately 296 gross wells (including 135 injection wells) from 2008 through 2024, at a total cost of approximately $21.4 million and total operating costs including steam of approximately $148.8 million. The precise timing and amount of our expenditures on additional well drilling and increased steam injection to develop the proved undeveloped reserves in this project will depend on several factors including the relative prices of oil and natural gas.

     In 2007, we continued to invest the majority of our budgeted capital expenditures in our Barnett Shale and onshore Gulf Coast areas where the rates of return are traditionally higher and our leases expire sooner, which gives these projects greater immediacy. We did, however, drill 17 gross wells (17 net) and 13 gross injection wells in the Camp Hill Field in 2007.

     During 2007, we experienced delays in our development plan of the Camp Hill field. Our 2007 drilling program in the Camp Hill field was delayed primarily due to the unavailability of the rig we use to drill in the field. However, during the fourth quarter of 2007, we received a firm commitment from our drilling contractor to drill exclusively for us through February 2008 with options to extend the contract for four additional three-month periods, providing us the expected rig availability needed to execute our 2008 drilling plan. The steam generators we expected to use were not available due to delays in repairs and permitting issues. We injected steam in the Camp Hill field through one of our generators until it encountered operational damage in January 2007. We expect to receive a replacement generator in March 2008 and expect this generator to commence steam injection in April 2008. Our other two generators have not been available for injection due to unexpected permitting issues and the need for repair work. We currently expect that these two generators will be ready to inject steam by the end of July 2008 with respect to one generator and by the end of October 2008, with respect to the other. In addition, we plan to obtain a small portable generator by October 2008. We received the permits for these two generators to recommence injection in the fourth quarter of 2007. Although these permits will only allow us to inject steam at 80% of the rate that we had anticipated, based upon the rate under the prior permits for these same generators, we expect to continue to appeal to the regulatory authorities to reinstate the 100 % rate of generation allowed under the original permits. The impact of a lower generation rate assumption (incorporated into our December 31, 2007 proved reserves), does not reduce our proved reserves, however, it does extend the productive life of the field with a corresponding reduction in the present value of the estimated future net revenues discounted at 10% per annum. Prospectively, we expect to continue to use the lower generation rate assumption in our proved reserve estimates, unless and until such time that we are successful in increasing the generation rates in our permits.

Other Texas Area

     The Other Texas area encompasses multiple objectives, including the Cotton Valley, Rodessa, and Travis Peak intervals. We have licenses for over 531 square miles of 3-D seismic data in this area and 11,025 net acres under lease. We expect to invest $8.0 million to drill five wells (4.2 net) in this area during 2008. Four of these wells are designed to continue the evaluation of new projects that represent low to moderate risk opportunities with upside reserve potential.

      The primary focus project in this area is the Tortuga Grande Prospect, a Rodessa and Travis Peak opportunity. In 2007 we completed the acquisition of a 20 square mile 3-D survey to evaluate additional potential of the Tortuga Grande area. During 2008, we expect to invest $2.6 million to drill two additional wells (0.9 net) based on the integration of new data with the well information. We believe that, assuming successful drilling in 2008, there will be an inventory in excess of eleven additional locations on the Tortuga Grande project area.

     In our Other Texas area, we have a total inventory of 32 leased exploratory drillsites, 31 of which are field extension wells based on initial drilling success. We are pursuing acreage on an additional 25 technically defined prospects.

Other Shale Project Areas

     We are continuing to expand our acreage position and databases in new resource shale projects. Regional mapping of shale extent, depth, thickness, organic content, thermal maturation, mineralogy, as well as cost and availability of acquiring leases were analyzed to define the project fairways to lease. We have been successful in acquiring approximately 23,900 (including approximately 7,000 net acres related to 2008 acquisitions) net acres in the Fayetteville Shale in Arkansas, and approximately 65,000 net acres in the Woodford/Barnett Shale in West Texas and New Mexico comprised of over 58,000 net acres in the Marfa Basin and 6,651 net acres in the Delaware Basin. We have leased 22,751 net acres in the New Albany shale project located in Illinois and Kentucky where we plan to drill and core a test well in 2008. In addition, we have leased 12,482 net acres (related to a 2008 acquisition) in the Marcellus Shale in New York and Pennsylvania. We anticipate acquiring seismic data and will begin drilling initial test wells in this project in 2008. In 2007 we drilled three wells (1.6 net) to evaluate these Other Shale plays. In 2008 we expect to invest $9.6 million to drill 20 wells (6.7 net) to continue our evaluation of these shale projects. Our 2008 drilling program includes one additional well to test the Floyd shale where we currently have 139,800 net acres of leasehold and eleven gross (0.6 net) wells in the Fayetteville trend.

U.K. North Sea Region  

     Our U.K. North Sea interests are a natural extension of our business model to exploit resources in proven mature regions through 3-D seismic surveys, related technology and proper risk management. The U.K. North Sea includes proven hydrocarbon trends with established technological expertise, available large and state-of-the-art 3-D seismic datasets and significant exploration potential. What began as a low-cost option less than five years ago could soon become a new core area as we attempt to build on our early success with our recent material discovery at Huntington.

     Our Huntington well (15% working interest and 3% overriding royalty interest) in the Central Graben Area was drilled in the second quarter of 2007 resulting in two independent discoveries from the same wellbore, one in the shallower Paleocene Forties reservoir and another in the deeper Upper Jurassic Fulmar objective, which tested at a combined maximum rate of over 11,000 Bbls/d equivalent.

     The Huntington Forties reservoir was largely appraised by year-end 2007 with eight high-angle deviated side-tracks (laterals) drilled radially from a central top hole location at a net cost of approximately $9.2 million. Appraisal of the Fulmar discovery was also commenced before year-end 2007. Current plans are to submit an application to the U.K. authorities for a Forties field development plan during 2008 with early first oil production expected between late 2009 and early 2010.

     Our plan is to seek fast-track development of the Forties reservoir and to use any resulting early cash flow to help fund possible development of the Fulmar, which we expect will be appraised and tested in 2008 at an estimated net cost of $14.5 million. We also plan to participate in the upcoming U.K. 25^th license round to further build on our core acreage positions by seeking nearby open acreage that is available and deemed prospective.

     Our involvement in the North Sea began in 2003 when we were awarded seven acreage blocks in 2003 from the U.K.’s 21st license round. We subsequently generated over a dozen prospects from these blocks and renewed two of the licenses with four-year terms in 2006, while relinquishing three of the less prospective blocks. As of December 31, 2007, we held three 4-year licenses over four exploration blocks, totaling over 110,600 gross acres (24,800 net) all located in mature producing areas of the Central and Southern North Sea in water depths of 30 to 350 feet. As of year-end 2007, we had met all associated drilling commitments under these license agreements.

     On three of our licenses, we successfully promoted our interests to other parties more experienced in drilling and operating in this region, leaving us with a carried interest on four exploration wells. Two of the four drilled wells resulted in three discoveries, including two discoveries at Huntington and an apparent gas discovery at our Monterey prospect in the Southern Gas Basin. Monterey (25% working interest and 3% overriding royalty interest) was a late-2006 discovery that tested at 2 MMcf/d, and is currently shut-in awaiting completion of pre-development studies by the operator. A final decision on development by the partners is expected in the coming year.

     From inception of our activity in this area in early 2003 through year-end 2006, we incurred only $1.7 million in total project costs (net of partner reimbursements) in an effort to create substantial value while minimizing front-end cost. We spent $9.4 million in the U.K. North Sea in 2007, largely for our participation in the Huntington Forties appraisal drilling during the second half of 2007. Our estimated net firm project commitments for the Huntington Forties field in 2008 includes approximately $6.6 million, largely for development planning, engineering and geological and geophysical studies, seismic acquisition and reprocessing, new acreage acquisition, and further prospect generation.

OTHER PROJECT AREAS

Wyoming/Montana Coalbed Methane Project Area

     Our interests in coalbed methane areas include a direct ownership in 14,056 net acres in Wyoming and Montana at December 31, 2007. In addition, through our subsidiary CCBM, Inc., we have a minority interest of approximately 8.3% of the shares (on a fully diluted basis) of Pinnacle Gas Resources, Inc., a publicly traded coalbed methane production company.

Working Interest and Drilling in Project Areas

     The actual working interest we will ultimately own in a well will vary based upon several factors, including the depth, cost and risk of each well relative to our strategic goals, activity levels and budget availability. From time to time some fraction of these wells may be sold to industry partners either on a prospect by prospect basis or a program basis. In addition, we may also contribute acreage to larger drilling units thereby reducing prospect working interest. We have, in the past, retained less than 100% working interest in our drilling prospects. References to our interests are not intended to imply that we have or will maintain any particular level of working interest.

     Although we have identified or budgeted for numerous drilling prospects, we may not be able to lease or drill those prospects within our expected time frame or at all. Wells that are currently part of our capital budget may be based on statistical results of drilling activities in other 3-D project areas that we believe are geologically similar rather than on analysis of seismic or other data in the prospect area, in which case actual drilling and results are likely to vary, possibly materially, from those statistical results. In addition, our drilling schedule may vary from our expectations because of future uncertainties. Our final determination of whether to drill any scheduled or budgeted wells will be dependent on a number of factors, including (1) the results of our exploration efforts and the acquisition, review and analysis of the seismic data; (2) the availability of sufficient capital resources to us and the other participants for the drilling of the prospects; (3) the approval of the prospects by the other participants after additional data has been compiled; (4) economic and industry conditions at the time of drilling, including prevailing and anticipated prices for natural gas and oil and the availability and prices of drilling rigs and crews; and (5) the availability of leases and permits on reasonable terms for the prospects. There can be no assurance that these projects can be successfully developed or that any identified drillsites or budgeted wells discussed will, if drilled, encounter reservoirs of commercially productive oil or natural gas. We may seek to sell or reduce all or a portion of our interest in a project area or with respect to prospects or wells within a project area.

     Our success will be materially dependent upon the success of our exploratory drilling program, which is an activity that involves numerous risks. See “Item 1A. Risk Factors Natural gas and oil drilling is a speculative activity and involves numerous risks and substantial and uncertain costs that could adversely affect us.”

Oil and Natural Gas Reserves

     The following table sets forth our estimated net proved oil and natural gas reserves and the PV-10 value of such reserves as of December 31, 2007. The reserve data and the present value as of December 31, 2007 were prepared by Ryder Scott Company, LaRoche Petroleum Consultants, Ltd. and Fairchild & Wells, Inc., Independent Petroleum Engineers. For further information concerning these independent engineers’ estimates of our proved reserves at December 31, 2007, see the reserve reports included as exhibits to this Annual Report on Form 10-K. The PV-10 value was prepared using constant prices as of the calculation date, discounted at 10% per annum on a pretax basis, and is not intended to represent the current market value

of the estimated oil and natural gas reserves owned by us. For further information concerning the present value of future net revenues from these proved reserves, see Notes 2 and 12 of Notes to Consolidated Financial Statements.  

		Proved Reserves
		Developed				Undeveloped				Total
		(Dollars in thousands)
Oil and condensate (MBbls)			6,536				9,995				16,531
Natural gas (MMcf)			122,598				125,835				248,433
Total proved reserves (MMcfe)			161,816				185,802				347,618
PV-10 Value(1)(2)		$	503,223			$	336,772			$	839,995

     No estimates of proved reserves comparable to those included herein have been included in reports to any federal agency other than the Securities and Exchange Commission (the “Commission”). The reserve data set forth in this Annual Report on Form 10-K represent only estimates. See “Item 1A. Risk Factors Our reserve data and estimated discounted future net cash flows are estimates based on assumptions that may be inaccurate and are based on existing economic and operating conditions that may change in the future.”

     Our future oil and natural gas production is highly dependent upon our level of success in finding or acquiring additional reserves. See “Item 1A. Risk Factors We depend on successful exploration, development and acquisitions to maintain reserves and revenue in the future.” Also, the failure of an operator of our wells to adequately perform operations, or such operator’s breach of the applicable agreements, could adversely impact us. See “ Item 1A. Risk Factors We cannot control the activities on properties we do not operate and are unable to ensure their proper operation and profitability.”

     In accordance with SEC regulations, Ryder Scott Company Petroleum Engineers, Fairchild & Wells, Inc. and LaRoche Petroleum Consultants, Ltd. each used year-end oil and natural gas prices in effect at December 31, 2007, adjusted for basis and quality differentials. The prices used in calculating the estimated future net revenue attributable to proved reserves do not necessarily reflect market prices for oil and natural gas production subsequent to December 31, 2007. There can be no assurance that all of the proved reserves will be produced and sold within the periods indicated, that the assumed prices will actually be realized for such production or that existing contracts will be honored or judicially enforced.

     LaRoche Petroleum Consultants, Ltd. determined 276.0 Bcfe, or 79% of our proved reserves, for the year ended December 31, 2007, which reserves were located on our Barnett Shale properties. Fairchild & Wells, Inc. determined 47.9 Bcfe, or 14% of our proved reserves, for the year ended December 31, 2007, which reserves were located on our properties in the Camp Hill Field. Ryder Scott Company Petroleum Engineers determined 23.7 Bcfe, or 7% of our proved reserves, for the year ended December 31, 2007, which reserves were located on our Gulf Coast and all other remaining properties.

Oil and Natural Gas Reserve Replacement

Finding and developing sufficient amounts of natural gas and crude oil reserves at economical costs are critical to our long-term success. Given the inherent decline of hydrocarbon reserves resulting from the production of those reserves, it is important for an exploration and production company to demonstrate a long-term trend of more than offsetting produced volumes with new reserves that will provide for future production. Management uses the reserve replacement ratio, as defined below, as an indicator of our ability to replenish annual production volumes and grow our reserves, thereby providing some information on the sources of future production. We believe reserve replacement information is frequently used by analysts, investors and others in the industry to evaluate the performance of companies like ours. The reserve replacement ratio is calculated by dividing the sum of reserve additions from all sources (revisions, extensions, discoveries, other additions, acquisitions and sales of reserves in place) by the actual production for the corresponding period. The values for these reserve additions are derived directly from the proved reserves table above. We do not use unproved reserve quantities in calculating our reserve replacement ratio. It should be noted that the reserve replacement ratio is a statistical indicator that has limitations. As an annual measure, the ratio is limited because it typically varies widely based on the extent and timing of new discoveries and property acquisitions. Its predictive and comparative value is also limited for the same reasons. In addition, since the ratio does not take into consideration the cost or timing of future production of new reserves, it cannot be used as a measure of value creation. The ratio does not distinguish between changes in reserve quantities that are producing and those that will require additional time and funding to begin producing. In that regard, it might be noted that percentage of reserves that were producing varied from 38.2% in 2007, to 25.0% in 2006, and to 19.1% in 2005. Set forth below is our reserve replacement ratio for the years ended December 31, 2007, 2006 and 2005.

		2007				2006				2005
Reserve Replacement Ratio			887	%			607	%			530	%

Volumes, Prices and Oil & Natural Gas Operating Expense

     The following table sets forth certain information regarding the production volumes of, average sales prices received for and average production costs associated with our sales of oil and natural gas for the periods indicated.

		Year Ended December 31,
		2007				2006				2005
Production volumes Oil (MBbls)			241				255				234
Natural gas (MMcf)			16,042				10,176				8,206
Natural gas equivalent (MMcfe)			17,487				11,705				9,612
Average sales prices Oil (per Bbl)		$	71.42			$	63.62			$	56.36
Natural gas (per Mcf)			6.77				6.56				7.90
Natural gas equivalent (per Mcfe)			7.19				7.09				8.13
Average costs (per Mcfe)
Camp Hill operating expenses		$	16.12			$	11.50			$	4.57
Other operating expenses			1.36				1.33				0.62
Total operating expenses(1)			1.41				1.40				1.09

Finding and Development Costs

     The table below reconciles our calculation of finding cost to our costs incurred in the purchase of proved and unproved properties and in development and exploration activities, excluding capitalized interest on unproved properties of $11.7 million, $10.0 million and $5.8 million for the years ended December 31, 2007, 2006 and 2005, respectively. We have also included capitalized overhead in our finding cost of $4.5 million, $3.5 million and $2.1 million for the years ended December 31, 2007, 2006 and 2005, respectively. We have also included non-cash asset retirement obligations of $2.0 million, $0.3 million and $1.8 million for the years ended December 31, 2007, 2006 and 2005, respectively.

		Year Ended December 31,
		2007				2006				2005
						(In thousands)
Acquisition costs:
Other unproved properties		$	54,467			$	48,409			$	49,089
Proved properties			—				—				1,954
Exploration			144,402				104,473				50,303
Development			30,562				37,889				20,883
Asset retirement obligation			1,961				299				1,820
			.
Total costs incurred		$	231,392			$	191,070			$	124,049
Total proved reserves added (MMcfe)			155,139				71,066				50,929
Average all-sources finding cost (per Mcfe)		$	1.49			$	2.69			$	2.44

     For the three year period ended December 31, 2007, our total adjusted costs for exploration, development and acquisition activities was approximately $546.5 million. Total exploration, development and acquisition activities for the three year period ended December 31, 2007 have added approximately 277.1 Bcfe of net proved reserves at an all-sources finding cost of $1.97 per Mcfe.

     Our finding and development cost computation excludes net additions/reductions to total future development costs with respect to proved undeveloped properties necessary to convert those properties into proved developed properties of $75.7 million, $31.4 million and $99.8 million at December 31, 2007, 2006 and 2005, respectively, and includes total additions to proved undeveloped reserves of 59.6 Bcfe, 28.4 Bcfe and 25.4 Bcfe for the years ended December 31, 2007, 2006 and 2005, respectively. Accordingly, had we included future development costs in our computations, the average all-sources finding costs would have been $1.98, $3.13 and $4.39 per Mcfe for the years ended December 31, 2007, 2006 and 2005, respectively.

     In order to maintain continued growth and profitability, our annual goal is to add new reserves exceeding our yearly production at a finding and development cost that contributes to an acceptable profit margin. Accordingly, we use the finding and development cost in combination with our reserve replacement ratio, as previously defined, to measure our operating and financial performance.

     Our all-source finding cost measure is a measure with limitations. Consistent with industry practice, our finding and development costs have historically fluctuated on a year-to-year basis based on a number of factors including the extent and timing of new discoveries and property acquisitions. Due to the timing of proved reserve additions and timing of the related costs incurred to find and develop our reserves, our all-sources finding cost measure often includes quantities of reserves for which a majority of the costs of development have not yet been incurred. Conversely, the measure often includes costs to develop proved reserves that had been added in earlier years. Finding and development costs, as measured annually, may not be indicative of our ability to economically replace oil and natural gas reserves because the recognition of costs may not necessarily coincide with the addition of proved reserves. Our all-sources finding cost may also be calculated differently than the comparable measure of other oil and gas companies.

Development, Exploration and Acquisition Capital Expenditures

     The following table sets forth certain information regarding the gross costs incurred in the purchase of proved and unproved properties and in development and exploration activities.

		Year Ended December 31,
		2007				2006				2005
						(In thousands)
Acquisition costs
Unproved prospects		$	54,467			$	48,409			$	49,089
Proved properties			—				—				1,954
Exploration			144,402				104,473				50,303
Development			30,562				37,889				20,883
Asset retirement obligation			1,961				299				1,820
Total costs incurred(1)		$	231,392			$	191,070			$	124,049

Drilling Activity

     The following table sets forth our drilling activity for the years ended December 31, 2007, 2006 and 2005. In the table, “gross” refers to the total wells in which we have a working interest and “net” refers to gross wells multiplied by our working interest therein. Our drilling activity from January 1, 1996 to December 31, 2007 has resulted in an apparent commercial success rate of approximately 81%.

		Year Ended December 31,
		2007								2006								2005
		Gross				Net				Gross				Net				Gross				Net
Exploratory Wells Productive			65				42.8				47				26.9				38				20.6
Nonproductive			1				0.4				3				0.9				4				1.2
Total			66				43.2				50				27.8				42				21.8
Development Wells Productive			29				24.0				20				17.1				23				14.0
Nonproductive			1				1.0				—				—				—				—
Total			30				25.0				20				17.1				23				14.0

     The table excludes six gross wells (1.1 net) drilled by CCBM during 2005. The wells are in various stages of development and/or stages of production.

Productive Wells

     The following table sets forth the number of productive oil and natural gas wells in which we owned an interest as of December 31, 2007. This table excludes all wells drilled or acquired by CCBM through 2003, a majority of which were contributed to Pinnacle in that year.

		Company
		Operated								Other								Total
		Gross				Net				Gross				Net				Gross				Net
Oil			63.0				56.2				1.0				0.1				64.0				56.3
Natural gas			90.0				75.0				151.0				47.0				241.0				122.0
Total			153.0				131.2				152.0				47.1				305.0				178.3

Acreage Data

     The following table sets forth certain information regarding our developed and undeveloped lease acreage as of December 31, 2007. Developed acres refers to acreage on which wells have been drilled or completed to a point that would permit production of oil and gas in commercial quantities. Undeveloped acreage refers to acreage on which wells have not been drilled or completed to a point that would permit production of oil and gas in commercial quantities whether or not the acreage contains proved reserves.

		Developed Acreage								Undeveloped Acreage								Total
		Gross				Net				Gross				Net				Gross				Net
North Sea			—				—				110,628				24,798				110,628				24,798
Louisiana			1,665				706				4,597				3,609				6,262				4,315
Texas			56,902				26,012				221,622				151,536				278,524				177,548
Mississippi			—				—				262,925				139,793				262,925				139,793
Montana/Wyoming			—				—				75,089				8,110				75,089				8,110
Other			2,154				596				140,049				66,205				142,203				66,801
Total			60,721				27,314				814,910				394,051				875,631				421,365

     The table does not include 16,059 gross and 5,547 net acres under lease option that we had a right to acquire in Texas pursuant to various seismic and lease option agreements at December 31, 2007. Under the terms of our option agreements, we typically have the right for a period of one year, subject to extensions, to exercise our option to lease the acreage at predetermined terms. Our lease agreements generally terminate if producing wells have not been drilled on the acreage within a period of three years. Further, the table does not include 23,784 gross and 5,946 net acres under lease option in Wyoming that CCBM has the right to earn pursuant to certain drilling obligations and other predetermined terms. We make certain statements in “Business and Properties-General” above regarding acreage that we are currently pursuing in various project areas. This acreage is not included in the table above. We have no rights in acreage that we are only pursuing because the acreage is not under lease or option and, in many cases, we are not in negotiations with respect to such acreage. Moreover, there can be no assurance that we will ever acquire such acreage.

Marketing

     Our production is marketed to third parties consistent with industry practices. Typically, oil is sold at the wellhead at field-posted prices plus a bonus and natural gas is sold under contract at a negotiated price based upon factors normally considered in the industry, such as distance from the well to the pipeline, well pressure, estimated reserves, quality of natural gas and prevailing supply and demand conditions.

     Our marketing objective is to receive the highest possible wellhead price for our product. We are aided by the presence of multiple outlets near our production in the Barnett Shale area and the Texas and Louisiana onshore Gulf Coast area. We take an active role in determining the available pipeline alternatives for each property based on historical pricing, capacity, pressure, market relationships, seasonal variances and long-term viability.

       There are a variety of factors that affect the market for natural gas and oil, including:

	•		demand for natural gas and oil;
	•		the extent of production of natural gas and oil and, in particular, domestic production and imports;
	•		the proximity and capacity of natural gas pipelines and other transportation facilities;
	•		the marketing of competitive fuels; and
	•		the effects of state and federal regulations on natural gas and oil production and sales.

     See “Item 1A. Risk Factors—Natural gas and oil prices are highly volatile, and lower prices will negatively affect our financial results,” “Item 1A. Risk Factors—We are subject to various governmental regulations and environmental risks,” and “Item 1A. Risk Factors—The marketability of our natural gas production depends on facilities that we typically do not own or control, which could result in a curtailment of production and revenues.”

     We from time to time market our own production where feasible with a combination of market-sensitive pricing and forward-fixed pricing. We utilize forward pricing to take advantage of anomalies in the futures market and to hedge a portion of our production deliverability at prices exceeding forecast. All of these hedging transactions provide for financial rather than physical settlement. For a discussion of these matters, our hedging policy and recent hedging positions, see “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Summary of Critical Accounting Policies —Derivative Instruments,” “Item 7A. Qualitative and Quantitative Disclosures About Market Risk—Commodity Risk,” and “Item 1A. Risk Factors—We may continue to enter into derivative transactions to manage the price risks associated with our production. Our derivative transactions may result in our making cash payments or prevent us from benefiting from increases in prices for natural gas and oil.”

Competition and Technological Changes

     We encounter competition from other natural gas and oil companies in all areas of our operations, including the acquisition of exploratory prospects and proven properties. Many of our competitors are large, well-established companies that have been engaged in the natural gas and oil business for much longer than we have and possess substantially larger operating staffs and greater capital resources than we do. We may not be able to conduct our operations, evaluate and select suitable properties and consummate transactions successfully in this highly competitive environment.

     The natural gas and oil industry is characterized by rapid and significant technological advancements and introductions of new products and services using new technologies. If one or more of the technologies we use now or in the future were to become obsolete or if we are unable to use the most advanced commercially available technology, our business, financial condition and results of operations could be materially adversely affected.

Regulation

     Natural gas and oil operations are subject to various federal, state, local and international environmental regulations that may change from time to time, including regulations governing natural gas and oil production, federal and state regulations governing environmental quality and pollution control and state limits on allowable rates of production by well or proration unit. These regulations may affect the amount of natural gas and oil available for sale, the availability of adequate pipeline and other regulated transportation and processing facilities and the marketing of competitive fuels. For example, a productive natural gas well may be “shut-in” because of an oversupply of natural gas or lack of an available natural gas pipeline in the areas in which we may conduct operations. State and federal regulations generally are intended to prevent waste of natural gas and oil, protect rights to produce natural gas and oil between owners in a common reservoir, control the amount of natural gas and oil produced by assigning allowable rates of production and control contamination of the environment. Pipelines are subject to the jurisdiction of various federal, state and local agencies. We are also subject to changing and extensive tax laws, the effects of which cannot be predicted.

     The following discussion summarizes the regulation of the United States oil and gas industry. We believe we are in substantial compliance with the various statutes, rules, regulations and governmental orders to which our operations may be subject, although we cannot assure you that this is or will remain the case. Moreover, those statutes, rules, regulations and government orders may be changed or reinterpreted from time to time in response to economic or political conditions, and any such changes or reinterpretations could materially adversely affect our results of operations and financial condition. The following discussion is not intended to constitute a complete discussion of the various statutes, rules, regulations and governmental orders to which our operations may be subject.

Regulation of Natural Gas and Oil Exploration and Production

     Our operations are subject to various types of regulation at the federal, state and local levels that:

	•		require permits for the drilling of wells;
	•		mandate that we maintain bonding requirements in order to drill or operate wells; and
	•		regulate the location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled, the plugging and abandoning of wells and the disposal of fluids used in connection with operations.

     Our operations are also subject to various conservation laws and regulations. These regulations govern the size of drilling and spacing units or proration units, the density of wells that may be drilled in natural gas and oil properties and the unitization or pooling of natural gas and oil properties. In this regard, some states (including Louisiana) allow the forced pooling or integration of tracts to facilitate exploration while other states (including Texas) rely primarily or exclusively on voluntary pooling of lands and leases. In areas where pooling is primarily or exclusively voluntary, it may be more difficult to form units and therefore more difficult to develop a project if the operator owns less than 100% of the leasehold. In addition, state conservation laws establish maximum rates of production from natural gas and oil wells, generally prohibit the venting or flaring of natural gas and impose specified requirements regarding the ratability of production. The effect of these regulations may limit the amount of natural gas and oil we can produce from our wells and may limit the number of wells or the locations at which we can drill. The regulatory burden on the natural gas and oil industry increases our costs of doing business and, consequently, affects our profitability. Because these laws and regulations are frequently expanded, amended and reinterpreted, we are unable to predict the future cost or impact of complying with such regulations.

Regulation of Sales and Transportation of Natural Gas

     Federal legislation and regulatory controls have historically affected the price of natural gas we produce and the manner in which our production is transported and marketed. Under the Natural Gas Act of 1938 (“NGA”), the Federal Energy Regulatory Commission (“FERC”) regulates the interstate transportation and the sale in interstate commerce for resale of natural gas. Effective January 1, 1993, the Natural Gas Wellhead Decontrol Act (the “Decontrol Act”) deregulated natural gas prices for all “first sales” of natural gas, including all of our sales of our own production. As a result, all of our domestically produced natural gas may now be sold at market prices, subject to the terms of any private contracts that may be in effect. The FERC’s jurisdiction over interstate natural gas transportation, however, was not affected by the Decontrol Act.

     Under the NGA, facilities used in the production or gathering of natural gas are exempt from the FERC’s jurisdiction. We own certain natural gas pipelines that we believe satisfy the FERC’s criteria for establishing that these are all gathering facilities not subject to FERC jurisdiction under the NGA. State regulation of gathering facilities generally includes various safety, environmental, and in some circumstances, nondiscriminatory take requirements but does not generally entail rate regulation.

     Although we therefore do not own or operate any pipelines or facilities that are directly regulated by the FERC, its regulations of third-party pipelines and facilities could indirectly affect our ability to market our production. Beginning in the 1980s the FERC initiated a series of major restructuring orders that required pipelines, among other things, to perform open access transportation, “unbundle” their sales and transportation functions, and allow shippers to release their pipeline capacity to other shippers. As a result of these changes, sellers and buyers of natural gas have gained direct access to the particular pipeline services they need and are better able to conduct business with a larger number of counterparties. We believe these changes generally have improved our access to markets while, at the same time, substantially increasing competition in the natural gas marketplace. It remains to be seen, however, what effect the FERC’s other activities will have on access to markets, the fostering of competition and the cost of doing business. We cannot predict what new or different regulations the FERC and other regulatory agencies may adopt, or what effect subsequent regulations may have on our activities.

     In the past, Congress has been very active in the area of natural gas regulation. However, the more recent trend has been in favor of deregulation or “lighter handed” regulation and the promotion of competition in the gas industry. In light of this increased reliance on competition, the Energy Policy Act of 2005 amended the NGA to prohibit any forms of market manipulation in connection with the transportation, purchase or sale of natural gas. In addition to the regulations implementing these prohibitions, the FERC has established new regulations that are intended to increase natural gas pricing transparency through, among other things, expanded dissemination of information about the availability and prices of gas sold, and has proposed new regulations that would require both interstate pipelines and certain non-interstate pipelines to post daily information regarding their capacity, scheduled flow volumes, and actual flow volumes at certain points on their systems. The Energy Policy Act of 2005 also significantly increases the penalties for violations of the NGA to up to $1 million per day for each violation. There regularly are other legislative proposals pending in the federal and state legislatures which, if enacted, would significantly affect the petroleum industry. At the present time, it is impossible to predict what proposals, if any, might actually be enacted by Congress or the various state legislatures and what effect, if any, such proposals might have on us. Similarly, and despite the trend toward federal deregulation of the natural gas industry, whether or to what extent that trend will continue, or what the ultimate effect will be on our sales of gas, cannot be predicted.

Oil Price Controls and Transportation Rates

     Our sales of oil, condensate and natural gas liquids are not currently regulated and are made at market prices. The price we receive from the sale of these products may be affected by the cost of transporting the products to market. Much of that transportation is through interstate common carrier pipelines. Effective as of January 1, 1995, the FERC implemented regulations generally grandfathering all previously approved interstate transportation rates and establishing an indexing system

for those rates by which adjustments are made annually based on the rate of inflation, subject to specified conditions and limitations. These regulations may tend to increase the cost of transporting natural gas and oil liquids by interstate pipeline, although the annual adjustments may result in decreased rates in a given year. Every five years, the FERC must examine the relationship between the annual change in the applicable index and the actual cost changes experienced in the oil pipeline industry. In March 2006, to implement the second of the required five-yearly re-determinations, the FERC established an upward adjustment in the index to track oil pipeline cost changes. The FERC determined that the Producer Price Index for Finished Goods plus 1.3 percent (PPI plus 1.3 percent) should be the oil pricing index for the five-year period beginning July 1, 2006. We are not able at this time to predict the effects of these regulations or FERC proceedings, if any, on the transportation costs associated with oil production from our oil producing operations.

Environmental Regulations

     Our operations are subject to numerous international, federal, state and local laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. These laws and regulations may require the acquisition of a permit before drilling commences, restrict the types, quantities and concentration of various substances that can be released into the environment in connection with drilling and production activities, limit or prohibit drilling activities on specified lands within wilderness, wetlands and other protected areas, require remedial measures to mitigate pollution from former operations, such as pit closure and plugging abandoned wells, and impose substantial liabilities for pollution resulting from production and drilling operations. The failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, imposition of investigatory or remedial obligations or the issuance of injunctions prohibiting or limiting the extent of our operations. Public interest in the protection of the environment has increased dramatically in recent years. The trend of applying more expansive and stricter environmental legislation and regulations to the natural gas and oil industry could continue, resulting in increased costs of doing business and consequently affecting our profitability. To the extent laws are enacted or other governmental action is taken that restricts drilling or imposes more stringent and costly waste handling, disposal and cleanup requirements, our business and prospects could be adversely affected.

     We generate waste that may be subject to the federal Resource Conservation and Recovery Act (“RCRA”) and comparable state statutes. The U.S. Environmental Protection Agency (“EPA”), and various state agencies have limited the approved methods of disposal for certain hazardous and nonhazardous waste. Furthermore, certain waste generated by our natural gas and oil operations that are currently exempt from treatment as “hazardous waste” may in the future be designated as “hazardous waste” and therefore become subject to more rigorous and costly operating and disposal requirements.

     We currently own or lease numerous properties that for many years have been used for the exploration and production of natural gas and oil. Although we believe that we have implemented appropriate operating and waste disposal practices, prior owners and operators of these properties may not have used similar practices, and hydrocarbons or other waste may have been disposed of or released on or under the properties we own or lease or on or under locations where such waste have been taken for disposal. In addition, many of these properties have been operated by third parties whose treatment and disposal or release of hydrocarbons or other waste was not under our control. These properties and the waste disposed thereon may be subject to the Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”), RCRA and analogous state laws as well as state laws governing the management of natural gas and oil waste. Under these laws, we could be required to remove or remediate previously disposed waste (including waste disposed of or released by prior owners or operators) or property contamination (including groundwater contamination) or to perform remedial plugging operations to prevent future contamination. See “Item 1A. Risk Factors We are subject to various governmental regulations and environmental risks.”

     CERCLA, also known as the “Superfund” law, and analogous state laws impose liability, without regard to fault or the legality of the original conduct, on specified classes of persons that are considered to have contributed to the release of a “hazardous substance” into the environment. These classes of persons include the owner or operator of the disposal site or sites where the release occurred and companies that disposed or arranged for the disposal of the hazardous substances found at the site. Persons who are or were responsible for releases of hazardous substances under CERCLA may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies, and it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment.

     Our operations may be subject to the Clean Air Act (“CAA”) and comparable state and local requirements. In 1990 Congress adopted amendments to the CAA containing provisions that have resulted in the gradual imposition of certain pollution control requirements with respect to air emissions from our operations. The EPA and states have developed and continue to develop regulations to implement these requirements. We may be required to incur certain capital expenditures in the next several years for air pollution control equipment in connection with maintaining or obtaining operating permits and approvals addressing other air emission-related issues. However, we do not believe our operations will be materially adversely affected by any such requirements.

     Federal regulations require certain owners or operators of facilities that store or otherwise handle oil, such as us, to prepare and implement spill prevention, control, countermeasure (“SPCC”) and response plans relating to the possible discharge of oil into surface waters. The Oil Pollution Act of 1990 (“OPA”) contains numerous requirements relating to the prevention of and response to oil spills into waters of the United States. The OPA subjects owners of facilities to strict joint and several liability for all containment and cleanup costs and certain other damages arising from a spill, including, but not limited to, the costs of responding to a release of oil to surface waters. The OPA also requires owners and operators of offshore facilities that could be the source of an oil spill into federal or state waters, including wetlands, to post a bond, letter of credit or other form of financial assurance in amounts ranging from $10 million in specified state waters to $35 million in federal outer continental shelf waters to cover costs that could be incurred by governmental authorities in responding to an oil spill. These financial assurances may be increased by as much as $150 million if a formal risk assessment indicates that the increase is warranted. Noncompliance with OPA may result in varying civil and criminal penalties and liabilities. Our operations are also subject to the federal Clean Water Act (“CWA”) and analogous state laws. In accordance with the CWA, the State of Louisiana issued regulations prohibiting discharges of produced water in state coastal waters effective July 1, 1997. Pursuant to other requirements of the CWA, the EPA has adopted regulations concerning discharges of storm water runoff. This program requires covered facilities to obtain individual permits or seek coverage under an EPA general permit. Like OPA, the CWA and analogous state laws relating to the control of water pollution provide varying civil and criminal penalties and liabilities for releases of petroleum or its derivatives into surface waters or into the ground.

     We also are subject to a variety of federal, state, local and international permitting and registration requirements relating to protection of the environment. We believe we are in substantial compliance with current applicable environmental laws and regulations and that continued compliance with existing requirements will not have a material adverse effect on us.

     Our offshore operations in the U.K. North Sea and onshore operations in the U.S. are subject to similar regulations covering permit requirements and the discharge of oil and other contaminants in connection with drilling operations.

Coalbed Methane Proceedings in Montana

     The issuance of new coalbed methane drilling permits in Montana was halted temporarily pending the Federal Bureau of Land Management’s (“BLM”) approval of a final record of decision on Montana’s Resource Management Plan environmental impact statement and the Montana Department of Environmental Quality’s approval of a statewide oil and gas environmental impact statement. These two program approvals were obtained in April and August of 2003, respectively. Environmental groups initiated six lawsuits, challenging these program approvals. On February 25, 2005, the Federal District Court for the District of Montana issued an opinion in Northern Plains Resource Council v. BLM and a companion case vacating BLM’s approval of the state plan and remanding the plan to BLM for further consideration. The Court further entered an order limiting the issuance of federal drilling permits to 500 per year and placed additional restrictions on certain operations. Various parties appealed these orders to the Ninth Circuit Court of Appeals. On May 31, 2005, the Ninth Circuit entered an order halting the issuance of any new permits pending their review of the parties’ various appeals. Oral argument was held in the case on September 15, 2005. On September 11, 2007, the Ninth Circuit affirmed the trial court’s issuance of the partial injunction limiting the issuance of drilling permits and withdrew the total ban on issuing permits entered by the Court of Appeals.

     During the pendency of the Ninth Circuit case, on February 2, 2007, in response to the orders issued by the Federal District Court for the District of Montana, BLM published the Draft Supplement to the Montana Statewide Oil and Gas Environmental Impact Statement and Amendment to the Powder River and Billings Resource Management Plan (“SEIS”). Public comments were received on the draft SEIS on May 2, 2007. On June 6, 2007, BLM responded to EPA concerns regarding the analysis of air quality impacts in the draft SEIS by committing to prepare Supplemental Air Quality Analyses for public comment by September 2007. On December 14, 2007, BLM issued the Supplemental Air Quality Analyses for public comment. This public comment period will end on March 13, 2008. The draft SEIS attempts to address the Federal District Court’s concerns.

     Although this decision could result in a continued suspension of the state’s authority to issue new drilling permits or could effect the continued viability of existing permits in Montana, we believe that the decisions by the Federal Bureau of Land Management and the State of Montana ultimately will be upheld on appeal and/or BLM’s reconsideration will address the Federal District Court’s concerns and new coalbed methane development will continue to be authorized in Montana. There can be no assurance that any new permits will be obtained in a given time period or at all.

Global Climate Change

     In response to recent studies suggesting that emissions of carbon dioxide and certain other gases may be contributing to warming of the Earth’s atmosphere, the current session of the U.S. Congress is considering climate change-related legislation to restrict greenhouse gas emissions. One bill recently approved by the U.S. Senate Environment and Public Works Committee, known as the Lieberman-Warner Climate Security Act or S.2191, would require a 70% reduction in emissions of greenhouse gases from sources within the United States between 2012 and 2050. The Lieberman-Warner bill proposes a “cap and trade” scheme of regulation of greenhouse gas emissions that generally would ban emissions above a defined reducing annual cap. Covered parties would be authorized to emit greenhouse emissions through the acquisition and subsequent surrender of emission allowances that may be traded or acquired on the open market. A vote on this bill by the full Senate is expected to occur before mid-year 2008. In addition, at least 17 states have already taken legal measures to reduce emissions of greenhouse gases, primarily through the planned development of greenhouse gas emission inventories and/or regional greenhouse gas cap and trade programs. Most of these cap and trade programs require either major sources of emissions, such as electric power plants, or major producers of fuels, such as refineries or gas processing plants, to acquire and surrender emission allowances. The number of allowances available for purchase is reduced each year until the overall greenhouse gas emission reduction goal is achieved.

     Depending on the particular program, we could be required to purchase and surrender allowances, either for greenhouse gas emissions resulting from our operations or from combustion of oil or natural gas we produce. Although we would not be impacted to a greater degree than other similarly situated producers of oil and gas, a stringent greenhouse gas control program could have an adverse effect on our cost of doing business and could reduce demand for the oil and gas we produce.

     Also, as a result of the U.S. Supreme Court’s decision in April 2007 in Massachusetts v. Environmental Protection Agency, the EPA may be required to regulate carbon dioxide and other greenhouse gas emissions from mobile sources such as cars and trucks, even if Congress does not adopt new legislation specifically addressing emissions of greenhouse gases. The EPA has indicated that it will issue a rulemaking notice to address carbon dioxide and other greenhouse gas emissions from vehicles and automobile fuels, although the date for issuance of this notice has not been finalized. The Court’s holding in Massachusetts that greenhouse gases including carbon dioxide fall under the federal Clean Air Act’s definition of “air pollutant” may also result in future regulation of carbon dioxide and other greenhouse gas emissions from stationary sources under certain Clean Air Act programs. New federal or state restrictions on emissions of carbon dioxide that may be imposed in areas of the United States in which we conduct business could also adversely affect our cost of doing business and demand for the oil and gas we produce.

     In addition to the effects of future regulation, the meteorological effects of global climate change could pose additional risks to our onshore and offshore operations in the form of more frequent and/or more intense storms and flooding, which could in turn adversely affect our cost of doing business.

Operating Hazards and Insurance

     The natural gas and oil business involves a variety of operating hazards and risks that could result in substantial losses to us from, among other things, injury or loss of life, severe damage to or destruction of property, natural resources and equipment, pollution or other environmental damage, cleanup responsibilities, regulatory investigation and penalties and suspension of operations.

     In addition, we may be liable for environmental damages caused by previous owners of property we purchase and lease. As a result, we may incur substantial liabilities to third parties or governmental entities, the payment of which could reduce or eliminate the funds available for exploration, development or acquisitions or result in the loss of our properties.

     In accordance with customary industry practices, we maintain insurance against some, but not all, potential losses. We do not carry business interruption insurance or protect against loss of revenues. We cannot assure you that any insurance we obtain will be adequate to cover any losses or liabilities. We cannot predict the continued availability of insurance or the availability of insurance at premium levels that justify its purchase. We may elect to self-insure if we believe that the cost of available insurance is excessive relative to the risks presented. In addition, pollution and environmental risks generally are not fully insurable. The occurrence of an event not fully covered by insurance could have a material adverse effect on our financial condition and results of operations.

     We participate in a substantial percentage of our wells on a nonoperated basis, and may be accordingly limited in our ability to control the risks associated with natural gas and oil operations.

Title to Properties; Acquisition Risks

     We believe we have satisfactory title to all of our producing properties in accordance with standards generally accepted in the natural gas and oil industry. Our properties are subject to customary royalty interests, liens incident to operating agreements, liens for current taxes and other burdens which we believe do not materially interfere with the use of or affect the value of these properties. As is customary in the industry in the case of undeveloped properties, we make little investigation of record title at the time of acquisition (other than a preliminary review of local records). Investigations, including a title opinion of local counsel, are generally made before commencement of drilling operations. Our credit facilities are secured by substantially all of our natural gas and oil properties.

     In acquiring producing properties, we assess the recoverable reserves, future natural gas and oil prices, operating costs, potential liabilities and other factors relating to the properties. Our assessments are necessarily inexact and their accuracy is inherently uncertain. Our review of a subject property in connection with our acquisition assessment will not reveal all existing or potential problems or permit us to become sufficiently familiar with the property to assess fully its deficiencies and capabilities. We may not inspect every well, and we may not be able to observe structural and environmental problems even when we do inspect a well. If problems are identified, the seller may be unwilling or unable to provide effective contractual protection against all or part of those problems. Any acquisition of property interests may not be economically successful, and unsuccessful acquisitions may have a material adverse effect on our financial condition and future results of operations. See “Item 1A. Risk Factors — Our future acquisitions may yield revenues or production that varies significantly from our projections.”

Customers

     The Company sold oil and natural gas production representing more than 10% of its oil and natural gas revenues as follows:

		Year Ended December 31,
		2007				2006				2005
Cokinos Natural Gas Company			11	%			—				—
Reichmann Petroleum			—				10	%			11	%
Chevron/Texaco			—				11	%			12	%
Houston Pipeline Company			11	%			—				—
Energy Transfer			10	%			—				—
Crosstex Energy			15	%			—				—

     Because alternate purchasers of oil and natural gas are readily available, we believe that the loss of any of our purchasers would not have a material adverse effect on our financial results.

Employees

     At December 31, 2007, we had 75 full-time employees, including eight landmen, six geoscientists and seven engineers. We believe that our relationships with our employees are good.

     In order to optimize prospect generation and development, we utilize the services of independent consultants and contractors to perform various professional services, particularly in the areas of 3-D seismic data mapping, acquisition of leases and lease options, construction, design, well site surveillance, permitting and environmental assessment. Independent contractors generally provide field and on-site production operation services, such as pumping, maintenance, dispatching, inspection and testings. We believe that this use of third-party service providers has enhanced our ability to contain general and administrative expenses.

     We depend to a large extent on the services of certain key management personnel and the loss of any could have a material adverse effect on our operations. We do not maintain key-man life insurance with respect to any of our employees.

Available Information

     Our website address is www.crzo.net. We make our website content available for informational purposes only. It should not be relied upon for investment purposes, nor is it incorporated by reference in this Form 10-K. We make available on this website, through a direct link to the Securities and Exchange Commission’s website at www.sec.gov, free of charge, 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 those materials.

     You may also find information related to our corporate governance, board committees and company code of ethics at our website. Among the information you can find there is the following:

	•		Audit Committee Charter;
	•		Compensation Committee Charter;
	•		Nominating Committee Charter;
	•		Code of Ethics and Business Conduct; and
	•		Compliance Employee Report Line.

     We intend to satisfy the requirement under Item 5.05 of Form 8-K to disclose any amendments to our Code of Ethics and any waiver from a provision of our Code of Ethics by posting such information in our Corporate Governance section of our website at www.crzo.net.

Item 1A. Risk Factors

  Natural gas and oil drilling is a speculative activity and involves numerous risks and substantial and uncertain costs that could adversely affect us.

     Our success will be largely dependent upon the success of our drilling program. Drilling for natural gas and oil involves numerous risks, including the risk that no commercially productive natural gas or oil reservoirs will be discovered. The cost of drilling, completing and operating wells is substantial and uncertain, and drilling operations may be curtailed, delayed or canceled as a result of a variety of factors beyond our control, including:

	•		unexpected or adverse drilling conditions;
	•		elevated pressure or irregularities in geologic formations;
	•		equipment failures or accidents;
	•		adverse weather conditions;
	•		compliance with governmental requirements; and
	•		shortages or delays in the availability of drilling rigs, crews and equipment.

     Because we identify the areas desirable for drilling from 3-D seismic data covering large areas, we may not seek to acquire an option or lease rights until after the seismic data is analyzed or until the drilling locations are also identified; in those cases, we may not be permitted to lease, drill or produce natural gas or oil from those locations.

     Even if drilled, our completed wells may not produce reserves of natural gas or oil that are economically viable or that meet our earlier estimates of economically recoverable reserves. Our overall drilling success rate or our drilling success rate for activity within a particular project area may decline. Unsuccessful drilling activities could result in a significant decline in our production and revenues and materially harm our operations and financial condition by reducing our available cash and resources. Because of the risks and uncertainties of our business, our future performance in exploration and drilling may not be comparable to our historical performance described in this Form 10-K.

We may not adhere to our proposed drilling schedule.

     Our final determination of whether to drill any scheduled or budgeted wells will be dependent on a number of factors, including:

	•		the results of our exploration efforts and the acquisition, review and analysis of the seismic data;
	•		the availability of sufficient capital resources to us and the other participants for the drilling of the prospects;
	•		the approval of the prospects by the other participants after additional data has been compiled;
	•		economic and industry conditions at the time of drilling, including prevailing and anticipated prices for natural gas and oil and the availability and prices of drilling rigs and crews; and
	•		the availability of leases and permits on reasonable terms for the prospects.

     Although we have identified or budgeted for numerous drilling prospects, we may not be able to lease or drill those prospects within our expected time frame or at all. Wells that are currently part of our capital budget may be based on statistical results of drilling activities in other 3-D project areas that we believe are geologically similar rather than on analysis of seismic or other data in the prospect area, in which case actual drilling and results are likely to vary, possibly materially, from those statistical results. In addition, our drilling schedule may vary from our expectations because of future uncertainties.

Our reserve data and estimated discounted future net cash flows are estimates based on assumptions that may be inaccurate and are based on existing economic and operating conditions that may change in the future.

     There are uncertainties inherent in estimating natural gas and oil reserves and their estimated value, including many factors beyond the control of the producer. The reserve data set forth in this Form 10-K represents only estimates. Reservoir engineering is a subjective and inexact process of estimating underground accumulations of natural gas and oil that cannot be measured in an exact manner and is based on assumptions that may vary considerably from actual results.

     Accordingly, reserve estimates may be subject to upward or downward adjustment, and actual production, revenue and expenditures with respect to our reserves likely will vary, possibly materially, from estimates. Additionally, there recently has been increased debate and disagreement over the classification of reserves, with particular focus on proved undeveloped reserves. Changes in interpretations as to classification standards, or disagreements with our interpretations, could cause us to write down these reserves.

     As of December 31, 2007, approximately 62% of our proved reserves were proved undeveloped and proved nonproducing. Moreover, some of the producing wells included in our reserve reports as of December 31, 2007 had produced for a relatively short period of time as of that date. Because most of our reserve estimates are calculated using volumetric analysis, those estimates are less reliable than estimates based on a lengthy production history. Volumetric analysis involves estimating the volume of a reservoir based on the net feet of pay of the structure and an estimation of the area covered by the structure based on seismic analysis. In addition, realization or recognition of our proved undeveloped reserves will depend on our development schedule and plans. Lack of certainty with respect to development plans for proved undeveloped reserves could cause the discontinuation of the classification of these reserves as proved. Although we have increased our development of the Camp Hill Field in East Texas, we have in the past chosen to delay development of our proved undeveloped reserves in the Camp Hill Field in favor of pursuing shorter-term exploration projects with higher potential rates of return, adding to our lease position in this field and further evaluating additional economic enhancements for this field’s development.

     The discounted future net cash flows included in this Form 10-K are not necessarily the same as the current market value of our estimated natural gas and oil reserves. As required by the Commission, the estimated discounted future net cash flows from proved reserves are based on prices and costs as of the date of the estimate. Actual future net cash flows also will be affected by factors such as:

	•		the actual prices we receive for natural gas and oil;
	•		our actual operating costs in producing natural gas and oil;
	•		the amount and timing of actual production;
	•		supply and demand for natural gas and oil;

	•		increases or decreases in consumption of natural gas and oil; and
	•		changes in governmental regulations or taxation.

     In addition, the 10% discount factor we use when calculating discounted future net cash flows for reporting requirements in compliance with the Financial Accounting Standards Board Statement of Financial Accounting Standards No. 69 may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the natural gas and oil industry in general.

We depend on successful exploration, development and acquisitions to maintain reserves and revenue in the future.

     In general, the volume of production from natural gas and oil properties declines as reserves are depleted, with the rate of decline depending on reservoir characteristics. Except to the extent we conduct successful exploration and development activities or acquire properties containing proved reserves, or both, our proved reserves will decline as reserves are produced. Our future natural gas and oil production is, therefore, highly dependent on our level of success in finding or acquiring additional reserves. In addition, we are dependent on finding partners for our exploratory activity. To the extent that others in the industry do not have the financial resources or choose not to participate in our exploration activities, we will be adversely affected.

Natural gas and oil prices are highly volatile, and lower prices will negatively affect our financial results.

     Our revenue, profitability, cash flow, future growth and ability to borrow funds or obtain additional capital, as well as the carrying value of our properties, are substantially dependent on prevailing prices of natural gas and oil. Historically, the markets for natural gas and oil prices have been volatile, and those markets are likely to continue to be volatile in the future. It is impossible to predict future natural gas and oil price movements with certainty. Prices for natural gas and oil are subject to wide fluctuation in response to relatively minor changes in the supply of and demand for natural gas and oil, market uncertainty and a variety of additional factors beyond our control. These factors include:

	•		the level of consumer product demand;
	•		overall economic conditions;
	•		weather conditions;
	•		domestic and foreign governmental relations, regulations and taxes;
	•		the price and availability of alternative fuels;
	•		political conditions;
	•		the level and price of foreign imports of oil and liquefied natural gas; and
	•		the ability of the members of the Organization of Petroleum Exporting Countries to agree upon and maintain production constraints and oil price controls.

     Declines in natural gas and oil prices may materially adversely affect our financial condition, liquidity and ability to finance planned capital expenditures and results of operations.

We face strong competition from other natural gas and oil companies.

     We encounter competition from other natural gas and oil companies in all areas of our operations, including the acquisition of exploratory prospects and proven properties. Our competitors include major integrated natural gas and oil companies and numerous independent natural gas and oil companies, individuals and drilling and income programs. Many of our competitors are large, well-established companies that have been engaged in the natural gas and oil business much longer than we have and possess substantially larger operating staffs and greater capital resources than we do. These companies may be able to pay

more for exploratory projects and productive natural gas and oil properties and may be able to define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit. In addition, these companies may be able to expend greater resources on the existing and changing technologies that we believe are and will be increasingly important to attaining success in the industry. Such competitors may also be in a better position to secure oilfield services and equipment on a timely basis or on favorable terms. We may not be able to conduct our operations, evaluate and select suitable properties and consummate transactions successfully in this highly competitive environment.

We may not be able to keep pace with technological developments in our industry.

     The natural gas and oil industry is characterized by rapid and significant technological advancements and introductions of new products and services using new technologies. As others use or develop new technologies, we may be placed at a competitive disadvantage, and competitive pressures may force us to implement those new technologies at substantial cost. In addition, other natural gas and oil companies may have greater financial, technical and personnel resources that allow them to enjoy technological advantages and may in the future allow them to implement new technologies before we can. We may not be able to respond to these competitive pressures and implement new technologies on a timely basis or at an acceptable cost. If one or more of the technologies we use now or in the future were to become obsolete or if we are unable to use the most advanced commercially available technology, our business, financial condition and results of operations could be materially adversely affected.

We are subject to various governmental regulations and environmental risks.

     Natural gas and oil operations are subject to various federal, state, local and foreign government regulations that may change from time to time. Matters subject to regulation include discharge permits for drilling operations, plug and abandonment bonds, reports concerning operations, the spacing of wells, unitization and pooling of properties and taxation. From time to time, regulatory agencies have imposed price controls and limitations on production by restricting the rate of flow of natural gas and oil wells below actual production capacity in order to conserve supplies of natural gas and oil. Other federal, state and local laws and regulations relating primarily to the protection of human health and the environment apply to the development, production, handling, storage, transportation and disposal of natural gas and oil, by-products thereof and other substances and materials produced or used in connection with natural gas and oil operations. In addition, we may be liable for environmental damages caused by previous owners of property we purchase or lease. As a result, we may incur substantial liabilities to third parties or governmental entities and may be required to incur substantial remediation costs. Further, we or our affiliates hold certain mineral leases in the State of Montana that require coalbed methane drilling permits, the issuance of which has been challenged in pending litigation. We may not be able to obtain new permits in an optimal time period or at all. We also are subject to changing and extensive tax laws, the effects of which cannot be predicted. Compliance with existing, new or modified laws and regulations could have a material adverse effect on our business, financial condition and results of operations.

We are subject to various operating and other casualty risks that could result in liability exposure or the loss of production and revenues.

       The natural gas and oil business involves operating hazards such as:

	•		well blowouts;
	•		mechanical failures;
	•		explosions;
	•		uncontrollable flows of oil, natural gas or well fluids;
	•		fires;
	•		geologic formations with abnormal pressures;
	•		pipeline ruptures or spills;
	•		releases of toxic gases; and
	•		other environmental hazards and risks.

     Any of these hazards and risks can result in the loss of hydrocarbons, environmental pollution, personal injury claims and other damage to our properties and the property of others.

     Offshore operations are subject to a variety of operating risks, such as capsizing, collisions and damage or loss from hurricanes or other adverse weather conditions. These conditions can and have caused substantial damage to facilities and interrupt production. Our operations in the U.K. North Sea are dependent upon the availability, proximity and capacity of pipelines, natural gas gathering systems and processing facilities. Any significant change affecting these infrastructure facilities could materially harm our business. We deliver crude oil and natural gas through gathering systems and pipelines that we do not own. These facilities may be temporarily unavailable due to adverse weather conditions or may not be available to us in the future. As a result, we could incur substantial liabilities or experience reductions in revenue that could reduce or eliminate the funds available for our exploration and development programs and acquisitions, or result in the loss of properties.

A substantial portion of our operations is exposed to the additional risk of tropical weather disturbances.

     A substantial portion of our production and reserves is located onshore South Louisiana and Texas. Operations in this area are subject to tropical weather disturbances. Some of these disturbances can be severe enough to cause substantial damage to facilities and possibly interrupt production. For example, a number of our wells in the Gulf Coast were shut in following Hurricanes Katrina and Rita in 2005. In accordance with customary industry practices, we maintain insurance against some, but not all, of these risks.

     Losses could occur for uninsured risks or in amounts in excess of existing insurance coverage. We cannot assure you that we will be able to maintain adequate insurance in the future at rates we consider reasonable or that any particular types of coverage will be available. An event that is not fully covered by insurance could have a material adverse effect on our financial position and results of operations.

We may not have enough insurance to cover all of the risks we face.

     We maintain insurance against losses and liabilities in accordance with customary industry practices and in amounts that management believes to be prudent; however, insurance against all operational risks is not available to us. We do not carry business interruption insurance. We may elect not to carry insurance if management believes that the cost of available insurance is excessive relative to the risks presented. In addition, we cannot insure fully against pollution and environmental risks. The occurrence of an event not fully covered by insurance could have a material adverse effect on our financial condition and results of operations.

We cannot control the activities on properties we do not operate and are unable to ensure their proper operation and profitability.

     We do not operate all of the properties in which we have an interest. As a result, we have limited ability to exercise influence over, and control the risks associated with, operations of these properties. The failure of an operator of our wells to adequately perform operations, an operator’s breach of the applicable agreements or an operator’s failure to act in ways that are in our best interests could reduce our production and revenues. The success and timing of our drilling and development activities on properties operated by others therefore depend upon a number of factors outside of our control, including the operator’s

	•		timing and amount of capital expenditures;
	•		expertise and financial resources;
	•		inclusion of other participants in drilling wells; and
	•		use of technology.

The marketability of our natural gas production depends on facilities that we typically do not own or control, which could result in a curtailment of production and revenues.

     The marketability of our production depends in part upon the availability, proximity and capacity of natural gas gathering systems, pipelines and processing facilities. We generally deliver natural gas through gas gathering systems and gas pipelines that we do not own under interruptible or short-term transportation agreements. Under the interruptible transportation agreements, the transportation of our gas may be interrupted due to capacity constraints on the applicable system, for maintenance or repair of the system, or for other reasons as dictated by the particular agreements. Our ability to produce and market natural gas on a commercial basis could be harmed by any significant change in the cost or availability of such markets, systems or pipelines.

Our future acquisitions may yield revenues or production that varies significantly from our projections.

     In acquiring producing properties, we assess the recoverable reserves, future natural gas and oil prices, operating costs, potential liabilities and other factors relating to the properties. Our assessments are necessarily inexact and their accuracy is inherently uncertain. Our review of a subject property in connection with our acquisition assessment will not reveal all existing or potential problems or permit us to become sufficiently familiar with the property to assess fully its deficiencies and capabilities. We may not inspect every well, and we may not be able to observe structural and environmental problems even when we do inspect a well. If problems are identified, the seller may be unwilling or unable to provide effective contractual protection against all or part of those problems. Any acquisition of property interests may not be economically successful, and unsuccessful acquisitions may have a material adverse effect on our financial condition and future results of operations.

Our business may suffer if we lose key personnel.

     We depend to a large extent on the services of certain key management personnel, including our executive officers and other key employees, the loss of any of whom could have a material adverse effect on our operations. We have entered into employment agreements with each of S.P. Johnson IV, our President and Chief Executive Officer, Paul F. Boling, our Vice President and Chief Financial Officer, J. Bradley Fisher, our Vice President and Chief Operating Officer, Gregory E. Evans, our Vice President of Exploration and Richard H. Smith, our Vice President of Land. We do not maintain key-man life insurance with respect to any of our employees. Our success will be dependent on our ability to continue to employ and retain skilled technical personnel.

We may experience difficulty in achieving and managing future growth.

     We have experienced growth in the past primarily through the expansion of our drilling program. Future growth may place strains on our financial, technical, operational and administrative resources and cause us to rely more on project partners and independent contractors, possibly negatively affecting our financial condition and results of operations. Our ability to grow will depend on a number of factors, including:

	•		our ability to obtain leases or options on properties, including those for which we have 3-D seismic data;
	•		our ability to acquire additional 3-D seismic data;
	•		our ability to identify and acquire new exploratory prospects;
	•		our ability to develop existing prospects;
	•		our ability to continue to retain and attract skilled personnel;
	•		our ability to maintain or enter into new relationships with project partners and independent contractors;
	•		the results of our drilling program;
	•		hydrocarbon prices; and
	•		our access to capital.

     We may not be successful in upgrading our technical, operations and administrative resources or in increasing our ability to internally provide certain of the services currently provided by outside sources, and we may not be able to maintain or enter into new relationships with project partners and independent contractors. Our inability to achieve or manage growth may adversely affect our financial condition and results of operations.

We may continue to enter into derivative transactions to manage the price risks associated with our production. Our derivative transactions may result in our making cash payments or prevent us from benefiting from increases in prices for natural gas and oil.

     Because natural gas and oil prices are unstable, we periodically enter into price-risk-management transactions such as swaps, collars, futures and options to reduce our exposure to price declines associated with a portion of our natural gas and oil production and thereby to achieve a more predictable cash flow. The use of these arrangements limits our ability to benefit from increases in the prices of natural gas and oil. Our derivative arrangements may apply to only a portion of our production, thereby providing only partial protection against declines in natural gas and oil prices. These arrangements may expose us to the risk of financial loss in certain circumstances, including instances in which production is less than expected, our customers fail to purchase contracted quantities of natural gas and oil or a sudden, unexpected event materially impacts natural gas or oil prices.

We have substantial capital requirements that, if not met, may hinder operations.

     We have experienced and expect to continue to experience substantial capital needs as a result of our active exploration, development and acquisition programs. We expect that additional external financing will be required in the future to fund our growth. We may not be able to obtain additional financing, and financing under existing or new credit facilities may not be available in the future. Even if additional capital becomes available, it may not be on terms acceptable to us. Without additional capital resources, we may be forced to limit or defer our planned natural gas and oil exploration and development program and thereby adversely affect the recoverability and ultimate value of our natural gas and oil properties, in turn negatively affecting our business, financial condition and results of operations.

High demand for field services and equipment and the ability of suppliers to meet that demand may limit our ability to drill and produce our oil and natural gas properties.

     Due to current industry demands, well service providers and related equipment and personnel are in short supply. This is causing escalating prices, delays in drilling and other exploration activities, the possibility of poor services coupled with potential damage to downhole reservoirs and personnel injuries. Such pressures will likely increase the actual cost of services, extend the time to secure such services and add costs for damages due to any accidents sustained from the overuse of equipment and inexperienced personnel.

Our credit facilities contain operating restrictions and financial covenants, and we may have difficulty obtaining additional credit.

     Over the past few years, increases in commodity prices and proved reserve amounts and the resulting increase in our estimated discounted future net revenue have allowed us to increase our available borrowing amounts. In the future, commodity prices may decline, we may increase our borrowings or our borrowing base may be adjusted downward, thereby reducing our borrowing capacity. Our credit facilities are secured by a pledge of substantially all of our producing natural gas and oil properties and assets, are guaranteed by our subsidiaries CCBM, Inc., CLLR, Inc. and Hondo Pipeline, Inc. and contain covenants that limit additional borrowings, dividends, the incurrence of liens, investments, sales or pledges of assets, changes in control, repurchases or redemptions for cash of our common stock, speculative commodity transactions and other matters. The credit facilities also require that specified financial ratios be maintained. We may not be able to refinance our debt or obtain additional financing, particularly in view of the restrictions of our credit facilities on our ability to incur additional debt and the fact that substantially all of our assets are currently pledged to secure obligations under the credit facilities. The restrictions of our credit facilities and our difficulty in obtaining additional debt financing may have adverse consequences on our operations and financial results including:

	•		our ability to obtain financing for working capital, capital expenditures, our drilling program, purchases of new technology or other purposes may be impaired;
	•		the covenants in our credit facilities that limit our ability to borrow additional funds and dispose of assets may affect our flexibility in planning for, and reacting to, changes in business conditions;
	•		because our indebtedness is subject to variable interest rates, we are vulnerable to increases in interest rates;

	•		any additional financing we obtain may be on unfavorable terms;
	•		we may be required to use a substantial portion of our cash flow to make debt service payments, which will reduce the funds that would otherwise be available for operations and future business opportunities;
	•		a substantial decrease in our operating cash flow or an increase in our expenses could make it difficult for us to meet debt service requirements and could require us to modify our operations, including by curtailing portions of our drilling program, selling assets, reducing our capital expenditures, refinancing all or a portion of our existing debt or obtaining additional financing; and
	•		we may become more vulnerable to downturns in our business or the economy.

     In addition, under the terms of our credit facilities, our borrowing base is subject to redeterminations at least semi-annually based in part on prevailing natural gas and oil prices. In the event the amount outstanding exceeds the redetermined borrowing base, we could be forced to repay a portion of our borrowings. We may not have sufficient funds to make any required repayment. If we do not have sufficient funds and are otherwise unable to negotiate renewals of our borrowings or arrange new financing, we may have to sell a portion of our assets.

We may record ceiling limitation write-downs that would reduce our shareholders’ equity.

     We use the full-cost method of accounting for investments in natural gas and oil properties. Accordingly, we capitalize all the direct costs of acquiring, exploring for and developing natural gas and oil properties. Under the full-cost accounting rules, the net capitalized cost of natural gas and oil properties may not exceed a “ceiling limit” that is based on the present value of estimated future net revenues from proved reserves, discounted at 10%, plus the lower of the cost or the fair market value of unproved properties. If net capitalized costs of natural gas and oil properties exceed the ceiling limit, we must charge the amount of the excess to operations through depreciation, depletion and amortization expense. This charge is called a “ceiling limitation write-down.” This charge does not impact cash flow from operating activities but does reduce our shareholders’ equity. The risk that we will be required to write down the carrying value of our natural gas and oil properties increases when natural gas and oil prices are low or volatile. In addition, write-downs would occur if we were to experience sufficient downward adjustments to our estimated proved reserves or the present value of estimated future net revenues, as further discussed in “—Our reserve data and estimated discounted future net cash flows are estimates based on assumptions that may be inaccurate and are based on existing economic and operating conditions that may change in the future.” Once incurred, a write-down of natural gas and oil properties is not reversible at a later date. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Summary of Critical Accounting Policies” for additional information on these matters.

We participate in oil and natural gas leases with third parties.

     We may own less than 100% of the working interest in certain leases acquired by us, and other parties will own the remaining portion of the working interest. Financial risks are inherent in any operation where the cost of drilling, equipping, completing and operating wells is shared by more than one person. We could be held liable for the joint activity obligations of the other working interest owners such as nonpayment of costs and liabilities arising from the actions of the working interest owners. In the event other working interest owners do not pay their share of such costs, we would likely have to pay those costs, which could materially adversely affect our financial condition.

We may incur losses as a result of title deficiencies.

     We purchase working and revenue interests in the natural gas and oil leasehold interests upon which we will perform our exploration activities from third parties or directly from the mineral fee owners. The existence of a material title deficiency can render a lease worthless and can adversely affect our results of operations and financial condition. Title insurance covering mineral leaseholds is not generally available and, in all instances, we forego the expense of retaining lawyers to examine the title to the mineral interest to be placed under lease or already placed under lease until the drilling block is assembled and ready to be drilled. As is customary in our industry, we rely upon the judgment of natural gas and oil lease brokers or independent landmen who perform the field work in examining records in the appropriate governmental offices and abstract facilities before attempting to acquire or place under lease a specific mineral interest. We, in some cases, perform curative work to correct deficiencies in the marketability of the title to us. The work might include obtaining affidavits of heirship or causing an estate to be administered. In cases involving more serious title problems, the amount paid for affected natural gas and oil leases can be generally lost, and the target area can become undrillable.

We have risks associated with our foreign operations.

     We currently have international activities and we continue to evaluate and pursue new opportunities for international expansion in select areas. Ownership of property interests and production operations in areas outside the United States is subject to the various risks inherent in foreign operations. These risks may include:

	•		currency restrictions and exchange rate fluctuations;
	•		loss of revenue, property and equipment as a result of expropriation, nationalization, war or insurrection;
	•		increases in taxes and governmental royalties;
	•		renegotiation of contracts with governmental entities and quasi-governmental agencies;
	•		changes in laws and policies governing operations of foreign-based companies;
	•		labor problems; and
	•		other uncertainties arising out of foreign government sovereignty over our international operations.

     Our international operations also may be adversely affected by the laws and policies of the United States affecting foreign trade, taxation and investment. In addition, if a dispute arises with respect to our foreign operations, we may be subject to the exclusive jurisdiction of foreign courts or may not be successful in subjecting foreign persons to the jurisdiction of the courts of the United States.

The threat and impact of terrorist attacks or similar hostilities may adversely impact our operations.

     We cannot assess the extent of either the threat or the potential impact of future terrorist attacks on the energy industry in general, and on us in particular, either in the short-term or in the long-term. Uncertainty surrounding such hostilities may affect our operations in unpredictable ways, including the possibility that infrastructure facilities, including pipelines and gathering systems, production facilities, processing plants and refineries, could be targets of, or indirect casualties of, an act of terror or war.

Item 1B. Unresolved Staff Comments

       None.

Glossary of Certain Industry Terms

     The definitions set forth below shall apply to the indicated terms as used herein. All volumes of natural gas referred to herein are stated at the legal pressure base of the state or area where the reserves exist and at 60 degrees Fahrenheit and in most instances are rounded to the nearest major multiple.

     After payout. With respect to an oil or gas interest in a property, refers to the time period after which the costs to drill and equip a well have been recovered.

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

      Bbls/d. Stock tank barrels per day.

      Bcf. Billion cubic feet.

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

     Before payout. With respect to an oil or gas interest in a property, refers to the time period before which the costs to drill and equip a well have been recovered.

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

     Completion. The installation of permanent equipment for the production of oil or natural gas or, in the case of a dry hole, the reporting of abandonment to the appropriate agency.

     Developed acreage. The number of acres which are allocated or assignable to producing wells or wells capable of production.

     Development well. A well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive.

     Dry hole or well. A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes.

     Exploratory well. A well drilled to find and produce oil or natural gas reserves not classified as proved, to find a new reservoir in a field previously found to be productive of oil or natural gas in another reservoir or to extend a known reservoir.

     Farm-in or farm-out. An agreement where under the owner of a working interest in an oil and natural gas lease assigns the working interest or a portion thereof to another party who desires to drill on the leased acreage. Generally, the assignee is required to drill one or more wells in order to earn its interest in the acreage. The assignor usually retains a royalty or reversionary interest in the lease. The interest received by an assignee is a “farm-in” while the interest transferred by the assignor is a “farm-out.”

     Field. An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition.

     Finding costs. Costs associated with acquiring and developing proved oil and natural gas reserves which are capitalized by us pursuant to generally accepted accounting principles, including all costs involved in acquiring acreage, geological and geophysical work and the cost of drilling and completing wells.

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

MBbls. One thousand barrels of oil or other liquid hydrocarbons.

MBbls/d. One thousand barrels of oil or other liquid hydrocarbons per day.

Mcf. One thousand cubic feet of natural gas.

Mcf/d. One thousand cubic feet of natural gas per day.

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

MMBbls. One million barrels of oil or other liquid hydrocarbons.

MMBtu. One million British Thermal Units.

MMcf. One million cubic feet.

MMcf/d. One million cubic feet per day.

     MMcfe. One million cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of oil, condensate or natural gas liquids, which approximates the relative energy content of oil, condensate and natural gas liquids as compared to natural gas. Prices have historically often been higher or substantially higher for oil than natural gas on an energy equivalent basis, although there have been periods in which they have been lower or substantially lower.

     Net acres or net wells. The sum of the fractional working interests owned in gross acres or gross wells.

     Net Revenue Interest. The operating interest used to determine the owner’s share of total production.

     Normally pressured reservoirs. Reservoirs with a formation-fluid pressure equivalent to 0.465 psi per foot of depth from the surface. For example, if the formation pressure is 4,650 psi at 10,000 feet, then the pressure is considered to be normal.

     Over-pressured reservoirs. Reservoirs subject to abnormally high pressure as a result of certain types of subsurface formations.

     Petrophysical study. Study of rock and fluid properties based on well log and core analysis.

     Present value. When used with respect to oil and natural gas reserves, the estimated future gross revenue to be generated from the production of proved reserves, net of estimated production and future development costs, using prices and costs in effect as of the date indicated, without giving effect to nonproperty-related expenses such as general and administrative expenses, debt service and future income tax expense or to depreciation, depletion and amortization, discounted using an annual discount rate of 10%.

     Productive well. A well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes.

     Proved developed nonproducing reserves. Proved developed reserves expected to be recovered from zones behind casing in existing wells.

     Proved developed producing reserves. Proved developed reserves that are expected to be recovered from completion intervals currently open in existing wells and able to produce to market.

     Proved developed reserves. Proved reserves that can be expected to be recovered from existing wells with existing equipment and operating methods.

     Proved reserves. The estimated quantities of crude oil, natural gas and natural gas liquids that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions.

     Proved undeveloped location. A site on which a development well can be drilled consistent with spacing rules for purposes of recovering proved undeveloped reserves.

     Proved undeveloped reserves. Proved reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion.

     PV-10 Value. The present value of estimated future revenues to be generated from the production of proved reserves calculated in accordance with Securities and Exchange Commission guidelines, net of estimated production and future development costs, using prices and costs as of the date of estimation without future escalation, without giving effect to non-property related expenses such as general and administrative expenses, debt service, future income tax expense and depreciation, depletion and amortization, and discounted using an annual discount rate of 10%.

     Recompletion. The completion for production of an existing well bore in another formation from that in which the well has been previously completed.

     Reservoir. A porous and permeable underground formation containing a natural accumulation of producible oil and/or gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.

     Royalty interest. An interest in an oil and natural gas property entitling the owner to a share of oil or natural gas production free of costs of production.

     3-D seismic data. Three-dimensional pictures of the subsurface created by collecting and measuring the intensity and timing of sound waves transmitted into the earth as they reflect back to the surface.

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

     Working interest. The operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and a share of production.

     Workover. Operations on a producing well to restore or increase production.

Item 3. Legal Proceedings

     From time to time, we are party to certain legal actions and claims arising in the ordinary course of business. While the outcome of these events cannot be predicted with certainty, management does not expect these matters to have a materially adverse effect on our financial position or results of operations.

Item 4. Submission of Matters to a Vote of Security Holders

None.

Executive Officers of the Registrant

     Pursuant to Instruction 3 to Item 401(b) of Regulation S-K and General Instruction G(3) to Form 10-K, the following information is included in Part I of this Form 10-K.

       The following table sets forth certain information with respect to our executive officers

Name		Age				Position
S.P. Johnson IV			52			President, Chief Executive Officer and Director
Paul F. Boling			54			Chief Financial Officer, Vice President, Secretary and Treasurer
J. Bradley Fisher			47			Vice President and Chief Operating Officer
Gregory E. Evans			58			Vice President of Exploration
Richard H. Smith			50			Vice President of Land

       Set forth below is a description of the backgrounds of each of our executive officers.

     S.P. Johnson IV has served as our President and Chief Executive Officer and a director since December 1993. Prior to that, he worked for Shell Oil Company for 15 years. His managerial positions included Operations Superintendent, Manager of Planning and Finance and Manager of Development Engineering. Mr. Johnson is also a director of Basic Energy Services, Inc. (a well servicing contractor) and Pinnacle Gas Resources, Inc. (a coalbed methane production company). Mr. Johnson is a Registered Petroleum Engineer and has a B.S. in Mechanical Engineering from the University of Colorado.

     Paul F. Boling has served as our Chief Financial Officer, Vice President, Secretary and Treasurer since August 2003. From 2001 to 2003, Mr. Boling was the Global Controller for Resolution Performance Products, LLC, an international epoxy resins manufacturer. From 1990 to 2001, Mr. Boling served in a number of financial and managerial positions with Cabot Oil & Gas Corporation, serving most recently as Vice President, Finance. Mr. Boling is a CPA and holds a B.B.A. from Baylor University.

     J. Bradley Fisher has served as Vice President and Chief Operating Officer since March 2005. Prior to that time, he served as Vice President of Operations since July 2000 and General Manager of Operations from April 1998 to June 2000. Prior to joining us, Mr. Fisher was the Vice President of Engineering and Operations for Tri-Union Development Corp. from August 1997 to April 1998. He spent the prior 14 years with Cody Energy and its predecessor Ultramar Oil & Gas Limited where he held various managerial and technical positions, last serving as Senior Vice President of Engineering and Operations. Mr. Fisher holds a B.S. degree in Petroleum Engineering from Texas A&M University.

     Gregory E. Evans has served as Vice President of Exploration since March 2005. Prior to joining us, Mr. Evans was Vice President North America Onshore Exploration for Ocean Energy from 2001 to 2003. Prior to that time, he spent 19 years at Burlington Resources where he served as Chief Geophysicist North America during 1999 to 2000, Gulf of Mexico Deep Water Exploration Manager during 1998 to 1999 and Geoscience Manager for the Western Gulf of Mexico Shelf during 1996 to 1998. Between 1982 to 1996, Mr. Evans held various other technical and managerial positions with Burlington Resources, including Division Exploration Manager of both the Rocky Mountain Region as well as the Gulf Coast area. Mr. Evans received a B.S. in Geophysical Engineering from the Colorado School of Mines receiving the Cecil H. Green award for outstanding geophysical student.

     Richard H. Smith has served as Vice President of Land since August 2006. Prior to joining us, Mr. Smith held the position of Vice President of Land for Petrohawk Energy Corporation from March 2004 through August 2006. Mr. Smith served with Unocal Corporation from April 2001 until March 2004 where he held the position of Land Manager – Gulf Region USA with areas of concentration in the OCS, Onshore Texas and Louisiana and Louisiana State Waters. From September 1997 until

March 2001 Mr. Smith held the position of Land Manager – Gulf Coast Region with Basin Exploration, Inc. Mr. Smith held various land management positions with Sonat Exploration Company, Michel T. Halbouty Energy Co., Pend Oreille Oil & Gas Company and Norcen Explorer, Inc. from the time he began his career in 1980 until the time he joined Basin Exploration. Mr. Smith is a Certified Professional Landman with a B.B.A. in Petroleum Land Management from the University of Texas at Austin. 

PART II

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

     Our common stock, par value $0.01 per share, trades on the Nasdaq Global Select Market under the symbol “CRZO.” The following table sets forth the high and low sales prices per share of our common stock on the Nasdaq Global Select Market for the periods indicated.

		High				Low
2007
First Quarter		$	35.58			$	25.54
Second Quarter			47.70				34.44
Third Quarter			46.23				34.51
Fourth Quarter			57.38				43.90
2006
First Quarter		$	29.70			$	21.57
Second Quarter			32.95				24.99
Third Quarter			32.42				24.31
Fourth Quarter			33.94				23.08

     The closing market price of our common stock on February 15, 2008 was $53.61 per share. As of February 15, 2008, there were an estimated 111 owners of record of our common stock.

     We have not paid any dividends on our common stock in the past and do not intend to pay such dividends in the foreseeable future. We currently intend to retain any earnings for the future operation and development of our business, including exploration, development and acquisition activities. Our credit facilities restrict our ability to pay dividends. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources.”

     The following graph presents a comparison of the yearly percentage change in the cumulative total return on the Common Stock over the period from December 31, 2002 to December 31, 2007, with the cumulative total return of the S&P 500 Index and the American Stock Exchange Natural Resources Industry Index of publicly traded companies over the same period. The graph assumes that $100 was invested on December 31, 2002 in our common stock at the closing market price at the beginning of this period and in each of the other two indices and the reinvestment of all dividends, if any.

     The graph is presented in accordance with requirements of the Securities and Exchange Commission. Shareholders are cautioned against drawing any conclusions from the date contained therein, as past results are not necessarily indicative of future financial performance.

		S&P				AMEX				COGI
December 31, 2002		$	100			$	100			$	100
December 31, 2003			126				148				137
December 31, 2004			138				190				214
December 31, 2005			142				290				469
December 31, 2006			161				323				551
December 31, 2007			167				411				1,039

     Pursuant to SEC rules, the foregoing graph is not deemed “filed” with the SEC.

     The following table presents information regarding the Company’s purchases of its common stock on a monthly basis during the fourth quarter of 2007:

										Total Number of				Maximum Number
										Shares Purchased as				(or Appropriate Dollar
		Total Number								Part of Publicly				Value) of Shares that May
		of Shares				Average Price				Announced Plans or				Yet Be Purchased Under
Period		Purchased(1)				Paid Per Share				Programs				the Plan or Programs
October 2007			1,960			$	45.29				—				—
November 2007			854				48.87				—				—
December 2007			432				53.29				—				—
Total			3,246			$	47.29				—				—

Item 6. Selected Financial Data

     Our financial information set forth below for each of the five years in the period ended December 31, 2007, has been derived from our audited consolidated financial statements. The information should be read in conjunction with such section and our consolidated financial statements and related notes included in Item 8. Financial Statements and Supplementary Data.

		Year Ended December 31,
		2007				2006				2005				2004				2003
						(In thousands, except per share data)
Statement Of Operations Data:
Oil and natural gas revenues		$	125,789			$	82,945			$	78,155			$	52,397			$	38,508
Costs and expenses:
Oil and natural gas operating expenses			24,662				16,428				10,437				8,392				6,724
Depreciation, depletion and amortization			41,899				31,129				21,374				15,464				11,868
General and administrative			18,912				14,909				11,243				8,255				5,952
Accretion expense related to asset retirement			374				496				70				23				41
Total costs and expenses			85,847				62,962				43,124				32,134				24,585
Operating income			39,942				19,983				35,031				20,263				13,923
Gain (loss) on derivatives			(1,366	)			16,457				(5,882	)			(625	)			—
Loss on extinguishment of debt			—				(294	)			(3,721	)			—				—
Equity in net income/(loss) of Pinnacle Gas Resources, Inc.			—				35				(2,542	)			(1,399	)			(830	)
Interest (expense) income, net of amounts capitalized and interest income			(13,994	)			(8,127	)			(4,295	)			(622	)			(19	)
Other income and expenses, net			130				427				(457	)			506				29
Income before income taxes			24,712				28,481				18,134				18,123				13,103
Income tax expense			9,243				10,233				7,500				7,009				5,063
Income before cumulative effect of change in accounting principle			15,469				18,248				10,634				11,114				8,040
Dividends and accretion of discount on preferred stock			—				—				—				350				741
Income available to common shareholders before cumulative effect of change in accounting principle			15,469				18,248				10,634				10,764				7,299
Cumulative effect of change in accounting principle			—				—				—				—				(128	)
Net income available to common shareholders		$	15,469			$	18,248			$	10,634			$	10,764			$	7,171
Basic earnings per common share		$	0.59			$	0.74			$	0.45			$	0.54			$	0.50
Diluted earnings per common share		$	0.57			$	0.71			$	0.44			$	0.49			$	0.43
Basic weighted average shares outstanding			26,287				24,827				23,492				19,958				14,312
Diluted weighted average shares outstanding			27,120				25,565				24,361				21,818				16,744
Statements of Cash Flow Data:
Net cash provided by operating activities		$	95,231			$	65,437			$	38,839			$	32,501			$	33,631
Net cash used in investing activities			(227,724	)			(161,576	)			(111,417	)			(80,294	)			(29,673	)
Net cash provided by (used in) financing activities			135,111				72,822				95,635				50,139				(5,379	)
Other Operating Data:
Capital expenditures		$	247,003			$	201,773			$	135,156			$	83,891			$	31,930
Debt repayments (1)			108,258				40,536				101,021				13,737				5,951

		As of December 31,
		2007				2006				2005				2004				2003
										(In thousands)
Balance Sheet Data:
Working capital (deficit)		$	(50,053	)		$	(17,014	)		$	10,307			$	(8,937	)		$	(11,817	)
Property and equipment, net			646,810				445,447				314,074				205,482				135,273
Total assets			709,670				494,795				383,101				234,345				156,803
Long-term debt, including current maturities			254,501				188,758				149,294				62,974				36,253
Convertible participating preferred stock							—				—				—				7,114
Total equity			310,721				212,274				155,385				121,060				76,072

     Forward-Looking Statements. The statements contained in all parts of this document, (including any portion attached hereto) including, but not limited to, those relating to our schedule, targets, estimates or results of future drilling, including the number, timing and results of wells, budgeted wells, increases in wells, the timing and risk involved in drilling follow-up wells, expected working or net revenue interests, planned expenditures, prospects budgeted and other future capital expenditures, risk profile of oil and gas exploration, acquisition of 3-D seismic data (including number, timing and size of projects), planned evaluation of prospects, probability of prospects having oil and natural gas, expected production or reserves, increases in reserves, acreage, working capital requirements, hedging activities, the ability of expected sources of liquidity to implement our business strategy, future exploration activity, production rates, financing for our 2008 exploration and development program, growth in production, development of new drilling programs, hedging of production and exploration and development expenditures, Camp Hill steam injection and development, all and any other statements regarding future operations, financial results, business plans and cash needs and other statements that are not historical facts are forward looking statements. When used in this document, the words “anticipate,” “budgeted,” “planned,” “targeted,” “potential,” “estimate,” “expect,” “may,” “project,” “believe” and similar expressions are intended to be among the statements that identify forward looking statements. Such statements involve risks and uncertainties, including, but not limited to, those relating to our dependence on our exploratory drilling activities, the volatility of oil and natural gas prices, the need to replace reserves depleted by production, operating risks of oil and natural gas operations, our dependence on our key personnel, factors that affect our ability to manage our growth and achieve our business strategy, risks relating to our limited operating history, technological changes, our significant capital requirements, the potential impact of government regulations, adverse regulatory determinations, litigation, competition, the uncertainty of reserve information and future net revenue estimates, property acquisition risks, availability of equipment, weather, availability of financing, ability to obtain permits and other factors detailed herein and in our other filings with the Securities and Exchange Commission. Some of the factors that could cause actual results to differ from those expressed or implied in forward-looking statements are described under “Item 1A. Risk Factors” and in other sections of this report. Should one or more of these risks or uncertainties materialize, or should underlying assumptions prove incorrect, actual outcomes may vary materially from those indicated. All subsequent written and oral forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by reference to these risks and uncertainties. You should not place undue reliance on forward-looking statements. Each forward-looking statement speaks only as of the date of the particular statement and we undertake no obligation to update or revise any forward-looking statement.

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

     You should read this discussion together with the consolidated financial statements and other financial information included in this Form 10-K.

General Overview

     In 2007, we recognized record revenues of $125.8 million, record production of 17.5 Bcfe and a record level of oil and gas proved reserves of 347.6 Bcfe. The key drivers to our success for 2007 included the following:

Drilling program. Our success is largely dependent on the results of our drilling program. During the year ended December 31, 2007, we drilled 96 gross wells (68.2 net wells) with an apparent success rate of 98% that was comprised of: (1) 60 of 60 gross wells (46.5 net wells) in the Barnett Shale area, (2) seven of eight gross wells (1.9 of 2.3 net wells) in the onshore Gulf Coast area, (3) one of one gross well (0.2 net well) in the U.K. North Sea, (4) 16 of 17 gross wells (16 of 17 net wells) in the Camp Hill field and (5) 10 of 10 gross wells (2.2 net wells) in other areas. We also drilled 13 gross service wells (13 net wells) in the Camp Hill area and one gross appraisal well (0.2 net) in the U.K. North Sea. At December 31, 2007, 53 of these gross wells were awaiting completion or pipeline connections.

Reserve Growth. As a result of our drilling program discussed above, our reserves increased 66 percent to a record level of 347.6 Bcfe at December 31, 2007, replacing 887 percent of 2007 production.

Production. Our 2007 annual production of 17.5 Bcfe, or 47.9 MMcfe/d was a record high. The 2007 production increased 49% from 2006 production of 11.7 Bcfe. The increase from the 2006 to the 2007 production was primarily due to new Barnett Shale wells and the addition of the Baby Ruth and Doberman #1 wells in the Gulf Coast area.

Commodity prices. Our average natural gas price during 2007 was $6.77 per Mcf (excluding the impact of our hedges), $0.21 per Mcf higher than the 2006 price of $6.56. Our average oil price in 2007 was $71.42 per Bbl, or $7.80 higher than in 2006. Commodity prices are affected by changes in market demands, overall economic activity, weather, pipeline capacity constraints, inventory storage levels, basis differentials and other factors. Our financial results are largely dependent on commodity prices, particularly natural gas prices, which are beyond our control and have been and are expected to remain volatile.

Capital funding. In order to fund our growth, we have taken steps to enhance our liquidity. During the first quarter of 2007, we received $72.1 million of net proceeds from borrowings under the amended Second Lien Facility. During the third quarter of 2007, we received approximately $72.0 million in net proceeds from a registered direct offering of 1.8 million shares of our common stock. The proceeds were used to repay borrowings under the Senior Credit Facility and to fund in part our 2007 drilling program and for general corporate purposes. In December 2007, our borrowing base availability on the Senior Credit Facility increased from $117.0 million to $145.0 million, leaving us with a borrowing capacity of $111 million at December 31, 2007. The next borrowing base redetermination is scheduled for May 2008. In February 2008, we received approximately $135.4 million in net proceeds from an underwritten public offering of 2.59 million shares of our common stock.

Outlook for 2008

     Our outlook for the future remains positive. Production growth and strong commodity prices are key to our future success and we believe the following measures will help continue our success in 2008:

2008 drilling and capital program. In 2008 we plan to drill 68 gross (62.6 net) wells in the Barnett Shale area, 15 gross (5.8 net) wells in the Gulf Coast area, 40 gross (40.0 net) wells in the Camp Hill field (which includes approximately 17 service wells), three gross (0.5 net) U.K. North Sea appraisal wells and 29 gross (14.5 net) wells in other areas. Our 2008 capital budget is approximately $300 million and includes approximately $250 million for drilling, comprised of $185 million in Barnett Shale, $23 million in Gulf Coast, $17 million in the U.K. North Sea, $6 million in the Camp Hill Field, and $19 million in other areas, and approximately $50 million for land and seismic activities. The actual number of wells drilled will vary depending upon various factors, including the availability and cost of drilling rigs, land and industry partner issues, our cash flow, success of drilling programs, weather delays and other factors. If we drill the number of wells we have budgeted for 2008, depreciation, depletion and amortization, oil and natural gas operating expenses and production are expected to increase over levels incurred in 2007.

Barnett Shale operations. During the first quarter of 2008, we entered into a drilling contract which is expected to bring our operated rig count to five starting in April 2008. Three of the rigs will be used in southeast Tarrant County, including one in the development of The University of Texas – Arlington (“UTA”) campus. For 2008, we have a six well plan for UTA in which we plan to drill all six wells then fracture stimulate these wells and begin sales before further drilling in the area. In early February 2008, the five wells in our Taylor lease in southeast Tarrant County, began production and sales with initial production rates totaling 23.0 MMcfe/d. There are currently 17 net horizontal wells in the Barnett Shale area already drilled but waiting on completion and/or pipeline connection.

North Sea operations. Following the positive results from the Forties appraisal drilling in the Huntington discovery during the fourth quarter of 2007, we are defining those field limits and establishing reservoir properties in preparation for making application for field development in late 2008. After we receive regulatory approval for our field development we will assess whether we will be able to book proved reserves in connection with this portion of the Huntington discovery. During the first quarter of 2008, we also completed the first appraisal well targeting the Jurassic Fulmar sands in the Huntington discovery and anticipate further appraisal will be required to delineate this reservoir. We currently expect that we will seek to significantly expand our expenditures in this area over the next several years. In 2008, we expect to seek project financing or conventional reserves-based financing to fund the development of the Huntington discovery.

Camp Hill. We have a firm commitment from our drilling contractor to drill exclusively for us through February 2008 with options to extend the contract for four additional three-month periods, providing us the expected rig availability needed to execute our 2008 drilling plan. By the end of 2008, we plan to have four natural gas-fired steam generators operating at the field, of which the first generator is expected to be working near full capacity by April 2008.

Other areas. In the Marcellus Shale in New York and Pennsylvania, where we have acquired approximately 12,500 net acres, we expect to drill four gross (2.8 net) wells. In the Floyd Shale we expect to drill a well in the northwest end of the play where a competitor’s well has reported a commercial flow rate. In the Fayetteville Shale, we expect to participate in the drilling of eleven outside-operated gross (0.6 net) wells with an average working interest of about five percent.

Natural gas and oil hedges. We expect to hedge production to decrease our exposure to natural gas and oil price fluctuations. At December 31, 2007, we had hedged approximately 14,624,000 MMBtus of natural gas production through 2009 and 45,700 Bbls of oil production through 2008.

Results of Operations

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

     Oil and natural gas revenues for 2007 increased 52% to $125.8 million from $82.9 million in 2006. Production volumes for oil and natural gas in 2007 increased 49% to 17.5 Bcfe from 11.7 Bcfe in 2006. Realized average natural gas sales price for 2007 increased 3% to $6.77 per Mcf compared to $6.56 per Mcf in 2006, and the average oil sales price for 2007 increased 12% to $71.42 per barrel from $63.62 per barrel in 2006. The increase in natural gas production was primarily due to the production from new wells in the Barnett Shale area and the Baby Ruth and Doberman #1 wells in the Gulf Coast area.

     The following table summarizes production volumes, average sales prices and operating revenues for our oil and natural gas operations for the years ended December 31, 2007 and 2006:

										2007 Period
										Compared to 2006 Period
		December 31,								Increase				% Increase
		2007				2006				(Decrease)				(Decrease)
Production volumes-
Oil and condensate (Mbbls)			241				255				(14	)			(5	)%
Natural gas (MMcf)			16,042				10,176				5,866				58	%
Average sales prices-
Oil and condensate (per Bbl)		$	71.42			$	63.62			$	7.80				12	%
Natural gas (per Mcf)			6.77				6.56				0.21				3	%
Operating revenues (In thousands) -
Oil and condensate		$	17,197			$	16,217			$	980				6	%
Natural gas			108,592				66,728				41,864				63	%
Total		$	125,789			$	82,945			$	42,844				52	%

     Oil and natural gas operating expenses for 2007 increased 50% to $24.7 million (or $1.41 per Mcfe) from $16.4 million (or $1.40 per Mcfe) in 2006. While total costs increased primarily due to increased production, costs per Mcfe remained relatively unchanged from 2006 to 2007. The increase in total operating expenses was due to (1) approximately $3.3 million in higher transportation gathering and treating costs in the Barnett Shale, (2) higher saltwater disposal costs of $2.2 million, (3) increased compression costs of $1.1 million, (4) higher severance taxes of $0.9 million and (5) increased workover expenses of $0.4 million.

     Depreciation, depletion and amortization (“DD&A”) expense for 2007 increased 35% to $41.9 million from $31.1 million in 2006. This increase was primarily due to an increase in production volumes partially offset by a decrease in the DD&A rate primarily due to lower overall finding cost of new reserves added in 2007.

     General and administrative (“G&A”) expense for 2007 increased 27% to $18.9 million from $14.9 million for 2006. The increase in G&A was due primarily to (1) increased employee related costs of $2.5 million, (2) increased stock-based compensation expense of $2.0 million due to additional restricted shares issued in 2007 and higher stock prices (3) increased office expense of $0.6 million and (4) increased legal-professional fees of $0.3 million. These increases were partially offset by decreased bad debt expense of $1.6 million primarily related to a 2006 outside operator bankruptcy filing.

     The net loss on derivatives was $1.4 million for the year ended December 31, 2007, comprised of (1) a $8.0 million of unrealized mark-to-market net losses on derivatives ($5.2 million loss on oil and gas derivatives and $2.8 million loss on interest rate swaps) and (2) $6.6 million of net realized gains ($6.4 million gain from oil and gas derivatives and $0.2 million gain from interest rate swaps).

     Interest expense and capitalized interest in 2007 were $26.4 million and ($11.7) million, respectively, as compared to $19.1 million and $(10.0) million in 2006. These increases were attributable to the $75.0 million increase in borrowings under the Second Lien Credit Facility in January 2007, increased borrowings under the Senior Credit Facility and higher effective interest rates.

     Income taxes decreased to $9.2 million in 2007 from $10.2 million in 2006 due to the decrease in pre-tax income.

Year Ended December 31, 2006 Compared to the Year Ended December 31, 2005

     Oil and natural gas revenues for 2006 increased 6% to $82.9 million from $78.2 million in 2005. Production volumes for oil and natural gas in 2006 increased 22% to 11.7 Bcfe from 9.6 Bcfe in 2005. Realized average natural gas sales price for 2006 decreased 17% to $6.56 per Mcf compared to $7.90 per Mcf in 2005, and the average oil sales price for 2006 increased 13% to $63.62 per barrel from $56.36 per barrel in 2005. The increase in natural gas production was primarily due to the production from the three Galloway Gas Unit wells and new wells in the Barnett Shale area. The gas production volume increases were partially offset by production declines from the Delta Farms #1 and the Beach House #1 wells.

     The following table summarizes production volumes, average sales prices and operating revenues for our oil and natural gas operations for the years ended December 31, 2006 and 2005:

										2006 Period
										Compared to 2005 Period
		December 31,								Increase				% Increase
		2006				2005				(Decrease)				(Decrease)
Production volumes-
Oil and condensate (Mbbls)			255				234				21				9	%
Natural gas (MMcf)			10,176				8,206				1,970				24	%
Average sales prices-(1)
Oil and condensate (per Bbl)		$	63.62			$	56.36			$	7.26				13	%
Natural gas (per Mcf)			6.56				7.90				(1.34	)			(17	%)
Operating revenues (In thousands) -
Oil and condensate		$	16,217			$	13,204			$	3,013				23	%
Natural gas			66,728				64,951				1,777				3	%
Total		$	82,945			$	78,155			$	4,790				6	%

     Oil and natural gas operating expenses for 2006 increased 57% to $16.4 million from $10.4 million in 2005. Oil and natural gas operating expenses increased primarily due to (i) increased production, (ii) increased well count of Barnett Shale wells, (iii) higher workover expenses, (iv) higher ad valorem taxes and (v) rising costs of oil field services. This was partially offset by a $0.6 million decrease in severance taxes due to lower average natural gas prices in 2006 and a lower effective severance tax rate for our Barnett Shale wells which qualify for high cost gas tax well credits.

     Depreciation, depletion and amortization (“DD&A”) expense for 2006 increased 46% to $31.1 million from $21.4 million in 2005. This increase was primarily due to (1) an increase in production volumes and (2) an increase in the DD&A rate primarily due to additions to the proved property cost base.

     General and administrative (“G&A”) expense for 2006 increased 33% to $14.9 million from $11.2 million for 2005. The increase in G&A was due primarily to (i) higher incentive compensation and base salary costs of $0.6 million, (ii) increased contract labor cost of $1.0 million to cover certain accounting staff vacancies and to support the continued phase-in of our new integrated software system, (iii) $0.2 million in higher audit fees primarily related to the Company’s 2005 financial restatement for mark-to-market accounting derivatives and (iv) increased bad debt expenses of $1.5 million primarily due to an outside operator bankruptcy filing.

     The net gain on derivatives was $16.5 million for the year ended December 31, 2006, comprised of (1) a $9.3 million of unrealized mark-to-market net gains on derivatives ($9.9 million gain on oil and gas derivatives and $0.6 million losses on interest rate swaps) and (2) a $7.2 million of net realized gains ($5.6 million gain from oil and gas derivatives, $1.0 million gain from interest rate swaps and $0.6 million gain from the sell down of the interest rate swap position as a result of an amendment to the Company’s second lien credit facility in December 2006).

     Interest expense and capitalized interest in 2006 were $19.1 million and ($10.0) million, respectively, as compared to $11.0 million and $(5.8) million in 2005. These increases were attributable to the debt refinancing in July 2005 and borrowings under the Company’s Senior Secured Credit Facility beginning in May 2006.

     Income taxes increased to $10.2 million in 2006 from $7.5 million in 2005 due to the increase in pre-tax income.

Liquidity and Capital Resources

     Sources and Uses of Cash. During the year ended December 31, 2007, capital expenditures, net of proceeds from property sales, exceeded our net cash. During 2007, we funded our capital expenditures with cash generated from operations, additional borrowings under the Second Lien Credit Facility and the Senior Credit Facility and proceeds from the issuance of common stock. Potential primary sources of future liquidity include the following:

	•		Cash on hand and cash generated by operations. Cash flows from operations are highly dependent on commodity prices and market conditions for oil and gas field services. We hedge a portion of our production to reduce the downside risk of declining natural gas and oil prices.
	•		Available borrowings under the Senior Credit Facility. On December 20, 2007, the borrowing base availability under the Senior Credit Facility increased from $117.0 million to $145.0 million. At February 21, 2008, borrowings available under the Senior Credit Facility were $145.0 million (after repaying $85.0 million of outstanding borrowings, using a portion of the net proceeds from the February 2008 equity offering). The next borrowing base redetermination is scheduled for May 2008.
	•		Other debt and equity financings. As situations or conditions arise, we may seek to issue additional debt or equity to supplement our cash flows. We raised approximately $71.9 million and $135.4 million from the issuances of our common stock in September 2007 and February 2008, respectively.
	•		Asset sales. In order to fund our drilling program, we may consider the sale of certain properties or assets that we no longer deem core to our future growth.

     Our primary use of cash is capital expenditures related to our drilling and leasing program. Our capital expenditures budget in 2008 provides for approximately $250 million for drilling and approximately $50 million for lease and seismic acquisitions. In 2008 we plan to drill 68 gross (62.6 net) wells in the Barnett Shale area, 15 gross (5.8 net) wells in the Gulf Coast area, 40 gross (40.0 net) wells in the Camp Hill Field (which includes approximately 17 service wells), three (0.5 net) U.K. North Sea appraisal wells and 29 gross (14.5 net) wells in other areas. The actual number of wells drilled and capital expended is dependent upon our available financing, cash flow, availability and cost of drilling rigs, land and partner issues and other factors. Capital expenditures do not include operating costs such as the steam costs that will be required for the multi-year development of our Camp Hill project. In addition to our capital expenditure program, we have contractual obligations as discussed below.

     We have increased the development of our Camp Hill project. In August 2005, management proposed the acceleration of the Camp Hill development to our board of directors. Accordingly, a development plan was formally approved by the board for increased drilling activity in the Camp Hill Field, beginning with an initial 60-well drilling program. In February 2006, our board of directors formally approved a multi-year plan to fully develop the entire Camp Hill Field. In furtherance of this plan, we expect to drill 40 gross wells in this area at an estimated cost of $5.6 million during 2008. To fully develop the field, we expect to drill approximately 296 wells from 2008 through 2024, at a total cost of approximately $21.4 million and total operating costs including steam of approximately $148.8 million. The precise timing and amount of our expenditures on additional well drilling and increased steam injection to develop the proved undeveloped reserves in this project will depend on several factors including the relative prices of oil and natural gas.

     Overview of Cash Flow Activities. Cash flows provided by operating activities were $95.2 million, $65.4 million and $38.8 million for the years ended December 31, 2007, 2006 and 2005, respectively. The increase from 2006 to 2007 was primarily due to an increase in operating income largely attributable to increased production and higher average oil and natural gas prices.

     Cash flows used in investing activities were $227.7 million for the year ended December 31, 2007 and related primarily to oil and gas property expenditures. Cash flows used in investing activities of $161.6 million for the year ended December 31, 2006 were largely attributable to capital expenditures for oil and gas properties of $201.8 million partially offset by proceeds from the sale of properties of $38.3 million. The 2005 cash flows used in investing activities of $111.4 million were largely attributable to capital expenditures for oil and gas properties.

     Net cash provided by financing activities for the year ended December 31, 2007 was $135.1 million and related primarily to the additional borrowings of $75.0 million under the Second Lien Credit Facility in January 2007 and net proceeds of $71.9 million from the issuance of common stock in September 2007. These cash proceeds were partially offset by the repayment of borrowings under the Senior Credit Facility. Net cash provided by financing activities for the year ended December 31, 2006 was $72.8 million and related primarily to additional borrowings under the Senior Credit Facility of $80.0 million and net proceeds of $33.5 million from the issuance of common stock, partially offset by $40.5 million of debt repayments. During 2005, net cash flow provided by financing activities was $95.6 million and was primarily comprised of $183.6 million of net proceeds from borrowings primarily from the Second Lien Credit Facility and also advances under the Senior Credit Facility

and the net proceeds of $17.0 million from the 2005 private placement of common stock. The proceeds were partially offset by $101.0 million of debt repayments.

     Liquidity/Cash Flow Outlook. In February 2008, we received approximately $135.4 million, before expenses, from an underwritten public offering of 2,587,500 shares of our common stock priced at $54.50 per share. With a portion of the proceeds we repaid the $85.0 million of borrowings outstanding under the Senior Credit Facility. We believe that the proceeds from this offering and cash generated from operations along with cash on hand and the cash available under the Senior Credit Facility is sufficient to fund our immediate needs but we may need to seek other financing alternatives, including additional debt or equity financings, to fully fund our 2008 capital expenditures program, especially if there are additional capital needs in connection with our Floyd Shale or U.K. North Sea operations or new opportunities in our Other Shale areas.

     We may not be able to obtain financing needed in the future on terms that would be acceptable to us. If we cannot obtain adequate financing, we may be required to limit or defer our planned oil and natural gas exploration and development program, thereby adversely affecting the recoverability and ultimate value of our oil and natural gas properties.

Contractual Obligations

     The following table sets forth estimates of our contractual obligations as of December 31, 2007:

		Payments Due by Year
		(In thousands)
		Total				2008				2009				2010				2011				2012
Long-term Debt		$	254,501			$	2,251			$	2,250			$	250,000			$	—			$	—
Operating Leases			4,213				1,000				1,009				1,102				1,102				—
Drilling Contracts			21,953				11,369				5,293				5,291				—				—
Seismic Data Commitments			150				150				—				—				—				—
Total Contractual
Cash Obligations		$	280,817			$	14,770			$	8,552			$	256,393			$	1,102			$	—

Off Balance Sheet Arrangements

       We currently do not have any off balance sheet arrangements.  

Financing Arrangements

  Second Lien Credit Facility

     On July 21, 2005, we entered into a Second Lien Credit Agreement with Credit Suisse, as administrative agent and collateral agent and the lenders party thereto (the “Second Lien Credit Facility”) that matures on July 21, 2010. The Second Lien Credit Facility, as amended, provides for a term loan facility in an aggregate principal amount of $225.0 million. It is secured by substantially all of our assets and is guaranteed by our subsidiaries. The liens securing the Second Lien Credit Facility are second in priority to the liens securing the Senior Secured Revolving Credit Facility (discussed below).

     The interest rate on each base rate loan will be the greater of the agent’s prime rate and the federal funds effective rate plus 0.5%, plus a margin of 3.75%. The interest on each Eurodollar loan will be the adjusted LIBO rate plus a margin of 4.75%. Interest on Eurodollar loans is payable on either the last day of each period or every three months, whichever is earlier. Interest on our outstanding borrowings under the Second Lien Credit Facility is payable quarterly. On December 31, 2007, the interest rate was approximately 9.6%, excluding the impact of interest rate swaps.

     We are subject to certain covenants under the Second Lien Credit Facility. These covenants include, but are not limited to, the maintenance of the following financial covenants: (1) a minimum current ratio of 1.0 to 1.0 including availability under the borrowing base under the Senior Credit Facility; (2) a minimum quarterly interest coverage ratio of 2.75 to 1.0 through December 31, 2007 and 3.0 to 1.0 thereafter; (3) a minimum quarterly proved reserve coverage ratio of 1.5 to 1.0 through December 31, 2007 and 2.0 to 1.0 thereafter; and (4) a maximum total net recourse debt to EBITDA (as defined in the Second Lien Credit Facility) ratio of not more than 3.75 to 1.0 through December 31, 2007 and 3.25 to 1.0 thereafter.

     The Second Lien Credit Facility also places restrictions on additional indebtedness, dividends to shareholders, liens, investments, mergers, acquisitions, asset dispositions, repurchase or redemption of our common stock, speculative commodity transactions, transactions with affiliates and other matters.

     The Second Lien Credit Facility is subject to customary events of default. Subject to certain exceptions, if an event of default occurs and is continuing, the agent may accelerate amounts due under the Second Lien Credit Facility (except for a bankruptcy event of default, in which case such amounts will automatically become due and payable). If an event of default occurs under the Second Lien Credit Facility as a result of an event of default under the Senior Credit Facility, the agent may not accelerate the amounts due under the Second Lien Credit Facility until the earlier of 45 days after the occurrence of the event resulting in the default and acceleration of the loans under the Senior Credit Facility.

     In January 2007, we drew an additional $75.0 million in borrowings under the Second Lien Facility and received net proceeds of $72.1 million. As of December 31, 2007, we had $220.5 million of borrowings outstanding under the Second Lien Credit Facility. Maturities of the Second Lien Credit Facility are $2.25 million in 2008 and 2009 and the remaining balance is due in 2010.

Senior Secured Revolving Credit Facility

     On May 25, 2006, we entered into a Senior Secured Revolving Credit Facility (“Senior Credit Facility”) with JPMorgan Chase Bank, National Association, as administrative agent that matures on May 25, 2010. The Senior Credit Facility provides for a revolving credit facility up to the lesser of the borrowing base and $200.0 million. It is secured by substantially all of our assets and is guaranteed by our subsidiaries. The liens securing the Senior Credit Facility are first in priority to the liens securing the Second Lien Credit Facility.

     As of December 31, 2007, we had $34.0 million of borrowings outstanding on a borrowing base availability of $145.0 million.

     On September 11, 2007, we entered into the Second Amendment (the “Second Amendment”) to the Senior Credit Facility. The Second Amendment provides that in the event the scheduled redetermination of the borrowing base is not made on or prior to January 1, 2008 as a result of our failure to comply with the requirement to deliver required engineering reports, the borrowing base will be reduced by $3.0 million commencing on January 1, 2008 and continuing on the first day of each month thereafter until the borrowing base is redetermined. The conforming and non-conforming borrowing bases (as defined in the Senior Credit Facility) were amended to be $100.0 million and $17.0 million, respectively. In connection with the Second Amendment, a second bank was added to the credit agreement. In addition, the Second Amendment increased the amount of investments in unrestricted subsidiaries that we may make.

     On December 20, 2007, we entered into the Third Amendment (the “Third Amendment”) to the Senior Credit Facility. The conforming and non-conforming borrowing bases were amended to be $125.0 million and $20.0 million, respectively. In connection with the Third Amendment, the co-lending group was expanded to four banks and the $3.0 million borrowing base reduction associated with the delivery of engineering reports at January 1, 2008 was removed.

     If the outstanding principal balance of the revolving loans under the Senior Credit Facility exceeds the borrowing base at any time, we have the option within 30 days to take any of the following actions, either individually or in combination: make a lump sum payment curing the deficiency, pledge additional collateral sufficient in the lenders’ opinion to increase the borrowing base and cure the deficiency or begin making equal monthly principal payments that will cure the deficiency within the ensuing six-month period. Those payments would be in addition to any payments that may come due as a result of the quarterly borrowing base reductions. Otherwise, any unpaid principal or interest will be due at maturity.

     The annual interest rate on each base rate borrowing will be (1) the greatest of the Agent’s Prime Rate, the Base CD Rate plus 1.0% and the Federal Funds Effective Rate plus 0.5%, plus (2) a margin between 0.25% and 1.75% (depending on the current level of borrowing base usage). The interest rate on each Eurodollar Loan will be the adjusted LIBO rate plus a margin between 1.5% to 3.0% (depending on the current level of borrowing base usage).

     We are subject to certain covenants under the amended terms of the Senior Credit Facility which include, but are not limited to, the maintenance of the following financial ratios: (1) a minimum current ratio of 1.0 to 1.0; and (2) a maximum total net debt to Consolidated EBITDAX (as defined in the Senior Credit Facility) of 3.75 to 1.0 for the fiscal quarters through and including December 31, 2007 and 3.25 to 1.0 thereafter. The Senior Credit Facility also places restrictions on indebtedness, dividends to shareholders, liens, investments, mergers, acquisitions, asset dispositions, repurchase or redemption of our common stock, speculative commodity transactions, transactions with affiliates and other matters.

     The Senior Credit Facility is subject to customary events of default, the occurrence and continuation of which could result in the acceleration of amounts due under the facility by the agent or the lenders.

     At December 31, 2007, we were in compliance with all of our debt covenants.

Public Offerings in 2008 and 2007; and Private Placements of Common Stock in 2006 and 2005.

     In February 2008, we sold 2,587,500 shares of our common stock in an underwritten public offering at a price of $54.50 per share. With a portion of the proceeds we repaid $85.0 million of borrowings then outstanding under the Senior Credit Facility. We plan to use the remaining proceeds to fund in part our 2008 capital expenditure program.

     In September 2007, we sold 1,800,000 shares of our common stock to certain qualified investors in a registered direct offering at a price of $41.40 per share. We used the net proceeds to repay $54 million of outstanding borrowings under the Senior Credit Facility and to fund in part our 2007 capital expenditure program.

     In July 2006, we sold 1,350,000 shares of our common stock to institutional investors at a price of $26.00 per share in a private placement (the “2006 Private Placement”). The net proceeds, after deducting placement agents’ fees but before paying offering expenses, of approximately $33.7 million were principally used to fund a portion of our 2006 capital expenditures program. In connection with the 2006 Private Placement, we entered into Subscription and Registration Rights Agreements (the “Subscription and Registration Rights Agreements”) with the investors in the 2006 Private Placement. The Subscription and Registration Rights Agreements provide registration rights with respect to the shares purchased in the 2006 Private Placement. We filed a resale shelf registration statement in connection with the 2006 Private Placement that has been declared effective by the SEC. We are generally subject to specified penalties in the event we do not maintain the effectiveness of the registration statement. We are subject to certain covenants under the terms of the Subscription and Registration Rights Agreements, including the requirement that the registration statement be kept effective for resale of shares for two years. In certain situations, we are required to indemnify the investors in the 2006 Private Placement, including without limitation, for certain liabilities under the Securities Act.

     In the second quarter of 2005, we sold 1,200,000 shares of our common stock to institutional investors at a price of $15.25 per share in a private placement (the “2005 Private Placement”), a 4.7% discount to the close price on the Nasdaq stock market for our common stock the day prior to pricing. The net proceeds from the 2005 Private Placement, after the placement agents’ fees but before offering expenses, were approximately $17.2 million. We used the proceeds from the 2005 Private Placement to fund a portion of our 2005 capital expenditure program, including our drilling programs in the Barnett Shale and onshore Gulf Coast areas.

Lease Option Arrangements

     Due to the limited capital available in the first half of 2006 to fund all of the Company’s ongoing lease acquisition efforts in the Barnett Shale and Other Shale plays, the Company elected to enter into several lease option agreements with a number of third parties and with Steven A. Webster, the Company’s chairman (collectively, the “counterparties”). The terms and conditions of the leasing arrangement (agreement terms are described below) with Mr. Webster are consistent with the leasing arrangements the Company has entered into with the other third parties. These leasing arrangements provide the Company the option to purchase leases from the counterparties, over an option period, generally 90 days, for the counterparties’ original cost of the leases plus an option fee. Strategically, these leasing arrangements have allowed the Company to temporarily control important acreage positions during periods that the Company has lacked sufficient capital to directly acquire such oil and gas leases.

     Since May 2006, the Company has acquired certain oil and gas leases through the aforementioned lease option arrangement with Mr. Webster. The acquisitions were made pursuant to a land option agreement between Mr. Webster and the Company dated January 25, 2006. The terms and conditions of this leasing arrangement with Mr. Webster are consistent with leasing arrangements the Company has entered into with the other third parties. Under the option agreement, Mr. Webster agreed to acquire oil and gas leases in areas where the Company is actively leasing or that it deems prospective. On or before the 90th day from the date that Mr. Webster acquires any lease in these areas, the Company has the option to acquire these leases from Mr. Webster for 110% of Mr. Webster’s purchase price or, on the 90th day, pay a non-refundable 10% option extension fee to add a second 90-day option period. On or before the end of this second 90-day option period, the Company has the option to pay Mr. Webster 110% of his original purchase price to acquire the lease. If, at the end of the second option period, the Company has not exercised its purchase option, Mr. Webster will retain ownership of the oil and gas leases. In addition to the cash payments described above, the Company will assign a one-half of one percent of 8/8ths overriding royalty interest (proportionally reduced to the actual net interest in any given lease acquired) on any lease it acquires from Mr. Webster in the first 90-day option period and a one percent of 8/8ths overriding royalty interest (also proportionally reduced) on any lease acquired from Mr. Webster in the second 90-day option period. As of December 31, 2006, Mr. Webster had acquired oil and

gas leases for approximately $4.2 million, the Company had paid approximately $4.4 million for leases from Mr. Webster and the Company had made option extension payments of approximately $48,000 to Mr. Webster. During 2007, there was no lease option activity under this arrangement. There are currently no outstanding lease options under our arrangement with Mr. Webster. The Company may continue to use these arrangements as a strategic alternative.

Effects of Inflation and Changes in Price  

     Our results of operations and cash flows are affected by changing oil and natural gas prices. If the price of oil and natural gas increases (decreases), there could be a corresponding increase (decrease) in the operating cost that we are required to bear for operations, as well as an increase (decrease) in revenues. Inflation has had a minimal effect on us.

Recently Issued Accounting Pronouncements  

     In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements.” SFAS No. 157 defines fair value, establishes a framework for measuring fair value under generally accepted accounting principles and requires enhanced disclosures about fair value measurements. It does not require any new fair value measurements. SFAS No. 157 is effective for financial statements issued for fiscal years beginning after November 15, 2007 and interim periods within those fiscal years. In February 2008, the FASB issued FASB Staff Position No. FAS157-2, “Effective Date of FASB Statement No. 157,” which delays the effectiveness for nonfinancial assets and nonfinancial liabilities to fiscal years beginning after November 15, 2008. We do not expect a material impact from SFAS No. 157 on our consolidated financial statements.

     In February 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities,” which permits entities to choose to measure many financial instruments and certain other items at fair value.  The objective is to improve financial reporting by providing entities with the opportunity to mitigate volatility in reported earnings caused by measuring related assets and liabilities differently without having to apply complex hedge accounting provisions.  SFAS No. 159 applies to all entities and is effective for fiscal years beginning after November 15, 2007.  We do not expect a material impact from SFAS No. 159 on our financial statements.

     In December 2007, the FASB issued SFAS No. 141 (revised 2007), “Business Combinations (“SFAS No. 141(R)”). SFAS No. 141(R) establishes principles and requirements to recognize the assets acquired and liabilities assumed in the acquisition transaction and determines what information to disclose to investors regarding the business combination. SFAS No. 141(R) is effective for business combinations for which the acquisition date is on or after the beginning of the first annual period beginning after December 15, 2008.

     In December 2007, the FASB issued SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements – an amendment of ARB No. 51” (“SFAS No. 160”). SFAS No. 160 establishes accounting and reporting standards with respect to the disclosure of the noncontrolling ownership in the statement of financial position within equity requires the presentation of the share of consolidated net income attributable to the parent and noncontrolling interest on the consolidated statement of income. The accounting treatment of changes in a parent’s ownership interest while the parent retains controlling interest and the accounting for the deconsolidation of a subsidiary. SFAS No. 160 is effective for fiscal years, and interim periods within those fiscal years, beginning on or after December 15, 2008. We currently have no noncontrolling interests in consolidated subsidiaries.

Recently Adopted Accounting Pronouncements

     We adopted the Financial Accounting Standards Board’s Interpretation No. 48, “Accounting for Uncertainty in Income Taxes, an Interpretation of FASB Statement No. 109” (“FIN 48”), effective January 1, 2007. FIN 48 clarifies the accounting for uncertainty in income taxes recognized in financial statements and requires the impact of a tax position to be recognized in the financial statements if that position is more likely than not of being sustained by the taxing authority.  The adoption of FIN 48 did not have a material effect on our consolidated financial position or results of operations.

     Summary of Critical Accounting Policies  

     The following summarizes several of our critical accounting policies. See a complete list of significant accounting policies in Note 2 to our consolidated financial statements.  

Use of Estimates

     The preparation of financial statements in conformity with U.S. generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of

contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting periods. Actual results could differ from these estimates. The use of these estimates significantly affects our natural gas and oil properties through depletion and the full cost ceiling test, as discussed in more detail below.

       Significant estimates include volumes of oil and natural gas reserves used in calculating depletion of proved oil and natural gas properties, future net revenues and abandonment obligations, impairment of undeveloped properties, future income taxes and related assets/liabilities, the collectability of outstanding accounts receivable, fair value of derivatives, stock-based compensation expense, contingencies and the results of future and current litigation. Oil and natural gas reserve estimates, which are the basis for unit-of-production depletion and the ceiling test, have numerous inherent uncertainties. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Subsequent drilling results, testing and production may justify revision of such estimate. Accordingly, reserve estimates are often different from the quantities of oil and natural gas that are ultimately recovered. In addition, reserve estimates are vulnerable to changes in wellhead prices of crude oil and natural gas. Such prices have been volatile in the past and can be expected to be volatile in the future.  

     The significant estimates are based on current assumptions that may be materially effected by changes to future economic conditions such as the market prices received for sales of volumes of oil and natural gas, interest rates, the market value of our common stock and corresponding volatility and our ability to generate future taxable income. Future changes to these assumptions may affect these significant estimates materially in the near term.  

Oil and Natural Gas Properties  

     We account for investments in natural gas and oil properties using the full-cost method of accounting. All costs directly associated with the acquisition, exploration and development of natural gas and oil properties are capitalized. These costs include lease acquisitions, seismic surveys, and drilling and completion equipment. We proportionally consolidate our interests in natural gas and oil properties. We capitalized compensation costs and other costs for employees working directly on exploration activities of $4.5 million, $3.5 million and $2.1 million in 2007, 2006 and 2005, respectively. We expense maintenance and repairs as they are incurred.  

     We amortize natural gas and oil properties based on the unit-of-production method using estimates of proved reserve quantities. We do not amortize investments in unproved properties until proved reserves associated with the projects can be determined or until these investments are impaired. We periodically evaluate, on a property-by-property basis, unevaluated properties for impairment. If the results of an assessment indicate that the properties are impaired, we add the amount of impairment to the proved natural gas and oil property costs to be amortized. The amortizable base includes estimated future development costs and, where significant, dismantlement, restoration and abandonment costs, net of estimated salvage values. The depletion rate per Mcfe for 2007, 2006 and 2005 was $2.36, $2.61 and $2.22, respectively.  

     We account for dispositions of natural gas and oil properties as adjustments to capitalized costs with no gain or loss recognized, unless such adjustments would significantly alter the relationship between capitalized costs and proved reserves. We have not had any transactions that significantly alter that relationship.  

     The net capitalized costs of proved oil and natural gas properties are limited to a “ceiling test” based on the estimated future net revenues, discounted at a 10% per annum, from proved oil and natural gas reserves based on current economic and operating conditions (the “Full Cost Ceiling”). If net capitalized costs exceed this limit, the excess is charged to earnings.  

     In connection with our year-end 2007 Full Cost Ceiling test computation, a price sensitivity study also indicated that a 10 percent increase or decrease in commodity prices at December 31, 2007 would have increased or decreased the Full Cost Ceiling test cushion by approximately $80 million. The aforementioned price sensitivity is as of December 31, 2007 and, accordingly, does not include any potential changes in reserves due to subsequent performance or events, such as commodity prices, reserve revisions and drilling results.  

     The Full Cost Ceiling cushion at the end of 2007 of approximately $238.1 million was based upon average realized oil, natural gas liquids and natural gas prices of $92.04 per Bbl, $56.67 per Bbl and $5.99 per Mcf, respectively, or a volume weighted average price of $47.20 per BOE. This cushion, however, would have been zero on such date at an estimated volume weighted average price of $33.06 per BOE. A BOE means one barrel of oil equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of oil, condensate or natural gas liquids, which approximates the relative energy content of oil, condensate and natural gas liquids as compared to natural gas. Prices have historically been higher or substantially higher, more often for oil than natural gas on an energy equivalent basis, although there have been periods in which they have been lower or substantially lower.

     Under the full cost method of accounting, the depletion rate is the current period production as a percentage of the total proved reserves. Total proved reserves include both proved developed and proved undeveloped reserves. The depletion rate is applied to the net book value of our oil and natural gas properties (excluding unevaluated costs) and estimated future development costs less net salvage value to calculate the depletion expense. Proved reserves materially impact depletion expense. If the proved reserves decline, then the depletion rate (the rate at which we record depletion expense) increases, reducing net income.  

     We have a significant amount of proved undeveloped reserves. We had 185.8 Bcfe, 126.2 Bcfe and 97.9 Bcfe of proved undeveloped reserves, representing 53%, 60% and 65% of our total proved reserves at December 31, 2007, 2006 and 2005, respectively. As of December 31, 2007, 2006 and 2005, a portion of these proved undeveloped reserves, or approximately, 38.1 Bcfe, 32.8 Bcfe and 38.1 Bcfe, respectively, are attributable to our Camp Hill properties that we acquired in 1994. See “Business and Properties — Significant Project Areas — Camp Hill Area” for further discussion of the Camp Hill properties. The estimated future development costs to develop our proved undeveloped reserves on our Camp Hill properties are relatively low, on a per Mcfe basis, when compared to the estimated future development costs to develop our proved undeveloped reserves on our other oil and natural gas properties. Furthermore, the average depletable life (the estimated time that it will take to produce all recoverable reserves) of our Camp Hill properties is considerably longer, or approximately 15 years, when compared to the depletable life of our remaining oil and natural gas properties of approximately 10 years. Accordingly, the combination of a relatively low ratio of future development costs and a relatively long depletable life on our Camp Hill properties has resulted in a relatively low overall historical depletion rate and DD&A expense. This has resulted in a capitalized cost basis associated with producing properties being depleted over a longer period than the associated production and revenue stream, causing the build-up of nondepleted capitalized costs associated with properties that have been completely depleted. This combination of factors, in turn, has had a favorable impact on our earnings, which have been higher than they would have been had the Camp Hill properties not resulted in a relatively low overall depletion rate and DD&A expense and longer depletion period. As a hypothetical illustration of this impact, the removal of our Camp Hill proved undeveloped reserves starting January 1, 2002 would have reduced our net income by, (1) an estimated $11.2 million in 2002 (comprised of after-tax charges for a $7.1 million full cost ceiling impairment and a $4.1 million depletion expense increase), (2) an estimated $5.9 million in 2003 (due to higher depletion expense), (3) an estimated $3.4 million in 2004 (due to higher depletion expense), (4) an estimated $6.9 million in 2005 (due to higher depletion expense), (5) an estimated $0.7 million in 2006 (due to higher depletion expense) and (6) an estimated $2.0 million in 2007 (due to higher depletion expenses).  

     We expect our relatively low historical depletion rate to continue until the high level of nonproducing reserves to total proved reserves is reduced and the life of our proved developed reserves is extended through development drilling and/or the significant addition of new proved producing reserves through acquisition or exploration. If our level of total proved reserves, finding cost and current prices were all to remain constant, this continued build-up of capitalized costs increases the probability of a ceiling test write-down.  

     We depreciate other property and equipment using the straight-line method based on estimated useful lives ranging from five to 10 years.  

Oil and Natural Gas Reserve Estimates  

     The proved reserve data as of December 31, 2007 included in this document are estimates prepared by Ryder Scott Company, LaRoche Petroleum Consultants, Ltd., and Fairchild & Wells, Inc., Independent Petroleum Engineers. Reserve engineering is a subjective process of estimating underground accumulations of hydrocarbons that cannot be measured in an exact manner. The process relies on judgment and the interpretation of available geologic, geophysical, engineering and production data. The extent, quality and reliability of this data can vary. The process also requires certain economic assumptions regarding drilling and operating expense, capital expenditures, taxes and availability of funds. The SEC mandates some of these assumptions such as oil and natural gas prices and the present value discount rate.  

     Proved reserve estimates prepared by others may be substantially higher or lower than our estimates. Because these estimates depend on many assumptions, all of which may differ from actual results, reserve quantities actually recovered may be significantly different than estimated. Material revisions to reserve estimates may be made depending on the results of drilling, testing, and rates of production.  

     You should not assume that the present value of future net cash flows is the current market value of our estimated proved reserves. In accordance with SEC requirements, we based the estimated discounted future net cash flows from proved reserves on prices and costs on the date of the estimate, using a discount rate of 10%.  

     Our rate of recording depreciation, depletion and amortization expense for proved properties is dependent on our estimate of proved reserves. If these reserve estimates decline, the rate at which we record these expenses will increase. A 10%

increase or decrease in our proved reserves would have increased or decreased our depletion expense by nine percent for the year ended December 31, 2007.  

     As of December 31, 2007, approximately 62% of our proved reserves were proved undeveloped and proved nonproducing. Moreover, some of the producing wells included in our reserve reports as of December 31, 2007 had produced for a relatively short period of time as of that date. Because most of our reserve estimates are calculated using volumetric analysis, those estimates are less reliable than estimates based on a lengthy production history. Volumetric analysis involves estimating the volume of a reservoir based on the net feet of pay of the structure and an estimation of the area covered by the structure based on seismic analysis. In addition, realization or recognition of our proved undeveloped reserves will depend on our development schedule and plans. Lack of certainty with respect to development plans for proved undeveloped reserves could cause the discontinuation of the classification of these reserves as proved. We have from time to time chosen to delay development of our proved undeveloped reserves in the Camp Hill Field in East Texas in favor of pursuing shorter-term exploration projects with higher potential rates of return, adding to our lease position in this field and further evaluating additional economic enhancements for this field’s development. The average life of the Camp Hill proved undeveloped reserves is approximately 15 years, with 50% of these reserves being booked over ten years ago. Although we have increased the pace of the development of the Camp Hill project, there can be no assurance that the aforementioned discontinuance will not occur.  

Derivative Instruments 

     We use derivatives, typically fixed-rate swaps and costless collars, to manage price and interest rate risk underlying our oil and gas production and the variable interest rate on the Second Lien Credit Facility. We have elected to account for our derivative contracts as non-designated derivatives that will be marked-to-market. For a discussion of the impact of changes in the prices of oil and gas on our hedging transactions, see “Volatility of Oil and Natural Gas Prices” below.

     Our Board of Directors sets all of our risk management policies and reviews volume limitations, types of instruments and counterparties, on a quarterly basis. These policies require that derivative instruments be executed only by either the President or Chief Financial Officer after consultation and concurrence by the President, Chief Financial Officer and Chairman of the Board. The master contracts with the approved counterparties identify the President and Chief Financial Officer as the only representatives authorized to execute trades. The Board of Directors also reviews the status and results of derivative activities quarterly.

     Upon entering into a derivative contract, we either designate the derivative instrument as a hedge of the variability of cash flow to be received (cash flow hedge) or the derivative must be accounted for as a non-designated derivative. All of our derivative instruments at December 31, 2007, 2006 and 2005 were treated as non-designated derivatives and the unrealized gain/(loss) related to the mark-to-market valuation was included in our earnings.  

Income Taxes  

     Under Statement of Financial Accounting Standards No. 109 (“SFAS No. 109”), “Accounting for Income Taxes,” deferred income taxes are recognized at each year end for the future tax consequences of differences between the tax bases of assets and liabilities and their financial reporting amounts based on tax laws and statutory tax rates applicable to the periods in which the differences are expected to affect taxable income. We routinely assess the realizability of our deferred tax assets. We consider future taxable income in making such assessments. If we conclude that it is more likely than not that some portion or all of the deferred tax assets will not be realized under accounting standards, it is reduced by a valuation allowance. However, despite our attempt to make an accurate estimate, the ultimate utilization of our deferred tax assets is highly dependent upon our actual production and the realization of taxable income in future periods.  

Contingencies  

     Liabilities and other contingencies are recognized upon determination of an exposure, which when analyzed indicates that it is both probable that an asset has been impaired or that a liability has been incurred and that the amount of such loss is reasonably estimable.  

Volatility of Oil and Natural Gas Prices  

     Our revenues, future rate of growth, results of operations, financial condition and ability to borrow funds or obtain additional capital, as well as the carrying value of our properties, are substantially dependent upon prevailing prices of oil and natural gas. See “Item 1A. Risk Factors—Natural gas and oil prices are highly volatile, and lower prices will negatively affect our financial results.”

     

48

(1)		Included in gain (loss) on derivatives, net in the Consolidated Statements of Operations.

49

(1)		Based on Houston Ship Channel and WAHA spot prices.
(2)		Based on West Texas intermediate index prices.

50

51

52

53

(1)		Relates primarily to an adjustment of the 2006 bankruptcy filing by an outside operator.
(2)		Relates primarily to a bankruptcy filing by an outside operator.

54