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		77002
(Principal executive offices)		(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):

     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 30, 2008, the aggregate market value of the registrant’s Common Stock held by non-affiliates of the registrant was approximately $1,876.6 million based on the closing price of such stock on such date of $68.09.

     At March 2, 2009, the number of shares outstanding of the registrant’s Common Stock was 30,888,635.

     Portions of the definitive proxy statement for the Registrant’s 2009 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, 2008.

 

 

TABLE OF CONTENTS

Forward Looking Statements					3
PART I					4
Item 1.		and Item 2. Business and Properties			4
Item 1A.		Risk Factors			25
Item 1B.		Unresolved Staff Comments			35
Item 3.		Legal Proceedings			37
Item 4.		Submission of Matters to a Vote of Security Holders			37
PART II					39
Item 5.		Market for Registrant’s Common Stock, Related Shareholder Matters and Issuer Purchases of Equity Securities			39
Item 6.		Selected Financial Data			41
Item 7.		Management’s Discussion and Analysis of Financial Condition and Results of Operations			42
Item 7A.		Qualitative and Quantitative Disclosures About Market Risk			57
Item 8.		Financial Statements and Supplementary Data			57
Item 9.		Changes In and Disagreements With Accountants on Accounting and Financial Disclosure			57
Item 9A.		Controls and Procedures			58
Item 9B.		Other Information			60
PART III					60
Item 10.		Directors, Executive Officers and Corporate Governance			60
Item 11.		Executive Compensation			60
Item 12.		Security Ownership of Certain Beneficial Owners and Management and Related Shareholder Matters			60
Item 13.		Certain Relationships and Related Transactions, and Director Independence			60
Item 14.		Principal Accountant Fees and Services			60
PART IV					60
Item 15.		Exhibits and Financial Statement Schedules			60

Forward-Looking Statements.

     The statements contained in all parts of this document, 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 natural gas and oil exploration, acquisition of 3-D seismic data (including number, timing and size of projects), planned evaluation of prospects, probability of prospects having natural gas and oil, 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 2009 exploration and development program, growth in production, development of new drilling programs, participation of our industry partners, funding for our Marcellus Shale operations, 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 the current economic downturn and credit crisis, our dependence on our exploratory drilling activities, the volatility of natural gas and oil prices, the need to replace reserves depleted by production, operating risks of natural gas and oil operations, our dependence on our key personnel, factors that affect our ability to manage our growth and achieve our business strategy, 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, access to pipelines and gathering systems, weather, availability of financing, financial condition of our industry partners and the counterparties to our hedges, ability to obtain permits and other factors detailed herein and in our other filings with the Securities and Exchange Commission (the “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.

PART I

Item 1. and Item 2. Business and Properties

OVERVIEW

General

     Carrizo Oil & Gas, Inc. is an independent energy company which, together with its subsidiaries (collectively, “Carrizo,” the “Company” or “we”) is engaged in the exploration, development, production and transportation of natural gas and oil, principally in the United States. Our current operations are principally focused in proven, producing natural gas plays known as “shale plays” or “resource plays”. Our primary core area is the Barnett Shale area in North Texas (“Barnett Shale” or “Fort Worth Barnett Shale”), with a focus on Southeast Tarrant County, Texas. Through our wholly-owned subsidiary Carrizo (Marcellus) LLC, we are also actively seeking to establish a core area in another emerging resource play, the Marcellus Shale play in Pennsylvania, New York, West Virginia and Virginia. In addition to the Barnett and the Marcellus, we are active in other shale plays, including the Fayetteville in Arkansas, Barnett/Woodford in West Texas/New Mexico, Floyd/Neal in Mississippi, and the New Albany in Kentucky/Illinois. We also explore for, develop and produce natural gas and oil from traditional geologic trends along the onshore Gulf Coast area in Texas, Louisiana and Alabama, primarily in the Miocene, Wilcox, Frio and Vicksburg trends. Our other interests include properties in the U.K. North Sea.

     We seek to grow our production through our 3-D seismic-driven exploratory and development drilling program and by applying proven horizontal drilling and hydraulic-fracturing (known as “fracing”) technology. From our inception through December 31, 2008, we have participated in the drilling of 723 wells (356.1 net) with an apparent success rate of approximately 84%. In the last five years, our apparent success rate has been 100% in the Barnett Shale. Since mid 2003, when we participated in drilling our first Barnett Shale well, we have participated in over 242 wells (173.6 net) in the Barnett Shale play. During 2008, we participated in 80 gross wells (62.8 net) wells in the Barnett Shale, including 66 wells that we operated. As of December 31, 2008, we had grown our proved reserves in the Barnett Shale to 432.1 Bcfe and our net average annual production in the Barnett Shale to 50.4 MMcf/d.

     Since we began focusing a significant portion of our efforts in shale plays, particularly in the Barnett Shale, we have grown our reserves at a compounded annual growth rate (“CAGR”) of 48%, while simultaneously maintaining a CAGR on our production of 28%. During 2008, we added a record 180.6 Bcfe to proved reserves, or a reserve replacement ratio of 705%. Please read “Oil and Natural Gas Reserve Replacement” for more information on our reserve replacement ratio. This reserve replacement ratio was achieved in spite of record production of 25.6 Bcfe, a 47% increase from 2007, including 22.4 Bcfe from wells that we drilled and operated. At year-end 2008, our proved reserves were approximately 78% natural gas and approximately 22% crude oil.

     Our Board of Directors has approved an initial capital and exploration budget of $105.0 million for 2009. This budget reflects our strategy of controlling capital costs and maintaining financial flexibility in light of current economic conditions and represents a substantial decrease from our capital expenditures of $548.8 million, $224.9 million and $187.3 million in 2008, 2007 and 2006, respectively. We currently expect to spend the majority of our capital and exploration budget for 2009 on drilling in our Barnett Shale core area. Where possible in order to maximize our liquidity, while increasing profitability of our projects, we currently intend to defer certain fracing, completion and pipeline costs because we currently expect that the costs of these services will decline significantly over the remainder of 2009. We intend to finance our 2009 capital and exploration budget primarily from cash flow from operations. Other available sources of funding include our senior credit facility and proceeds from the possible selective sale of non-core assets.

Barnett Shale Area

     We began active participation in the Barnett Shale area in the Fort Worth Basin through acquisition of acreage located west of the city of Fort Worth, Texas in mid 2003. By year-end 2008, we had interests in 189 gross (135.0 net) producing wells and 53 gross (38.6 net) non-producing wells that were drilled and waiting on completion and/or pipeline connection in the Barnett Shale. We operate 115 of the gross producing wells in the Barnett Shale that we have interests in and 43 of the gross wells we have drilled but are not yet producing there . During that same period, we increased our acreage holding in the Barnett Shale area to 82,331 gross (59,336 net) mineral acres. In addition we control an additional 864 gross and net mineral acres under lease options.

     During 2008, we drilled 80 additional gross wells (62.8 net) of which we operated 66. Net proved reserves grew by 57% from 276.0 Bcfe on December 31, 2007 to 432.1 Bcfe on December 31, 2008. We currently expect to invest approximately $85 million (representing over 80% of our total 2009 capital and exploration expenditures) to drill an additional 45 gross (30.0 net) wells in this area in 2009. In addition, we plan to frac, complete and bring on production approximately 23 gross (20.7 net) wells during 2009, thereby gradually increasing our significant inventory of drilled, but not yet frac’d and completed wells.

Marcellus Shale Area

     In late 2007, we established a new core area in the Marcellus Shale play, primarily in upstate New York, Pennsylvania, West Virginia and Virginia. The Marcellus Shale formation is located at depths of 4000’ to 9000’, is substantially larger in aerial extent than the Barnett Shale play (over 63 million acres compared to approximately 2.0 million acres in the core areas of the Barnett Shale) and, in general, is found in considerably less densely populated areas than the Barnett Shale. We believe that we can leverage the knowledge and experience that we gained in the Barnett Shale area to effectively explore for and develop natural gas in the Marcellus Shale.

     Effective as of August 1, 2008, our wholly-owned subsidiary Carrizo (Marcellus) LLC entered into a joint venture arrangement with an affiliate of Avista Capital Partners, LP, a private equity fund (Avista Capital Partners, LP, together with its affiliates, “Avista”). See “Footnote to Consolidated Financial Statement — Footnote 9. Related Party Transactions.” Under the terms of the joint venture, we and Avista each committed to contribute up to $150 million in cash and properties to acquire and develop acreage within an area of mutual interest located in the Marcellus Shale play, including the dedication of all of our respective Marcellus leasehold owned at the time of the formation of the joint venture. Because we initially committed acreage with a substantially higher market value to the joint venture than Avista, Avista agreed to fund the first approximately $71.5 million of joint venture expenditures related to the Marcellus Shale play. We currently expect Avista to fund all of the joint venture’s 2009 capital and exploration obligations, as well as the general and administrative expenses of our employees working on this play during the period. After these initial capital obligations have been met, we and Avista will each share all costs of joint venture operations in accordance with our participating interests, which we expect will generally be 50/50.

     As of year-end 2008, we and Avista had dedicated to the joint venture interests in approximately 230,146 gross (183,315 net) acres in the Marcellus Shale, principally in Pennsylvania, West Virginia and New York. In 2008, we participated in our first two vertical wells in the Marcellus Shale, including one in Pennsylvania and the other well in New York, where we also acquired our first 2-D seismic. We currently expect to participate in 12 gross (4.0 net) Marcellus Shale play area wells in 2009, including eleven vertical wells and one horizontal well, all of which we currently expect will be funded by Avista under our joint venture agreement. The actual number of wells that we are able to participate in may be less than this due, in part, to difficulties in obtaining drilling permits. See “Item 1A. Risk Factors — We have limited experience drilling wells in the Marcellus Shale and less information regarding reserves and declining rates in the Marcellus Shale than in other areas of our operations. We may face difficulties in securing and operating under authorizations and permits to drill for and or operate our Marcellus Shale wells.”

Onshore Gulf Coast Area

     In 2008, we drilled six gross (3.3 net) wells, all but one of which were apparent successes, and three of which we operated. During 2009, we currently have budgeted to participate in drilling three gross (1.0 net) wells and also expect to conduct an active workover and intervention program to maintain production while reducing capital expenditures. We currently plan to spend approximately $3.0 million for capital expenditures in the onshore Gulf Coast area during 2009.

U.K. North Sea Area

     We currently hold interests in three licenses in the U.K. North Sea (two in the Central Graben area and one in the Southern Gas Basin). The two licenses in the Central Graben area cover substantially the entire Huntington discovery. On these three licenses, we 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 in the Huntington Field and an apparent gas discovery at our Monterey prospect in the Southern Gas Basin. From inception of our activity in this area in early 2003 through year-end 2006, we have incurred only $1.7 million in total project costs (net of partner reimbursements) in an effort to create value while minimizing front-end cost. In 2008 and 2007, we spent $5.5 million and $9.4 million, respectively, largely for our share in the appraisal drilling and front-end development planning, engineering and studies related to the development of the portion of the Huntington discovery consisting of the Paleocene Forties formation, and to a lesser extent, appraisal drilling on that portion of the Huntington discovery consisting of the Jurassic Fulmar formation. We have currently budgeted $3.0 million to continue work in the Huntington Field in 2009, primarily for predevelopment project costs.

Other Areas

     We have currently budgeted $2.0 million for capital and exploration expenditures in 2009 for all of our other shale plays, including the Fayetteville, Floyd, New Albany and Barnett/Woodford, as well as for our other non-Gulf Coast traditional oil and gas plays, including our Camp Hill Field. Due to current economic conditions, we currently plan to participate in wells where our interest is carried by other partners, wells that we believe have a high probability of success and wells in which we are obligated to participate to maintain our acreage. We will also focus on workover, well intervention and lease maintenance to maintain existing production. We currently expect that lease acquisition will be limited to maintaining and consolidating existing lease positions in these areas.

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

Business Strategy

Measured 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:

	•		Control Capital Costs and Maintain Financial Flexibility. In response to reduced demand for natural gas and lower natural gas prices as a result of the current economic downturn and the current cost of accessing the capital markets, we have reduced our capital and exploration budget for 2009 to $105 million, and we are striving to maintain our financial flexibility and a positive production growth profile. Any further deterioration in commodity prices may cause us to reduce our capital and exploration budget for 2009 even further.
	•		Grow Primarily Through Drilling. We pursue a 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 six years and our 100% drilling success rate in the Barnett Shale area since inception in 2003. During 2009, we plan to drill approximately 45 gross (30.0 net) wells in the Barnett Shale area, and three gross (1.0 net) wells in the onshore Gulf Coast area. We also expect to complete 44 gross (44.0 net) wells in our Camp Hill Field. We have planned approximately $105.0 million for capital expenditures in 2009, approximately $90.0 million of which we expect to use for drilling activities, including $85.0 million in the Barnett Shale area and $3.0 million in the onshore Gulf Coast area. In addition, we currently expect to participate in 12 gross (4.0 net) Marcellus Shale play area wells in 2009, including eleven vertical wells and one horizontal well, all of which we currently expect will be funded by Avista under our joint venture agreement with them.
	•		Focus on Areas Where We Have Experience and a Technical Advantage. We focus our activities in the industry-proven Barnett Shale in which our wells have generally longer-lived reserves and where our management, technical staff and field operations teams have significant experience and, we believe, a technical advantage derived from operating over 150 horizontal wells. We are attempting to leverage this advantage in other shale trends, principally in the Marcellus Shale, by utilizing the knowledge and expertise of our personnel and partnering with Avista, a joint venture partner that has significant financial knowledge, expertise and capital. We plan to focus a majority of our near-term capital expenditures in the Barnett Shale area, where we have acquired a significant acreage position and accumulated a large drillsite inventory, and in the Marcellus Shale, where our joint venture currently controls over 230,000 acres and where we currently expect Avista to fund substantially all of the joint venture’s 2009 capital and exploration program. We also intend to continue to explore in the onshore Gulf Coast area, where members of our staff have been exploring for over 30 years.
	•		Maintain a Conservative Exploration and Development Portfolio. Recently we have sought to more heavily weight our drilling program toward projects with relatively lower risk and moderate potential, such as our development drilling in the Barnett Shale, than to projects that have relatively higher risk, but substantial upside potential such as our onshore Gulf Coast projects.

	•		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 core projects in order to better control drilling costs and the timing of drilling. Our joint venture with Avista in the Marcellus Shale is a recent and prominent example of this strategy.
	•		Retain and Incentivize a Highly Qualified Technical Staff. We employ over 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, as well as other emerging resource plays such as the Marcellus Shale, 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. An additional component of our business strategy, particularly in urban areas within the Barnett Shale play, we first identify and acquire surface tracts or “well pads” from which multiple wells can be drilled. We then seek to acquire contiguous lease blocks in the areas immediately adjacent to these well pads that can be developed quickly from them. We next acquire 3-D seismic data to assist in well placement and in optimizing the development plan for the units surrounding the well pad sites. 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. Finally, we form drilling units and utilize sophisticated horizontal drilling, multi-stage simultaneous fracing programs and micro-seismic techniques designed to maximize the potential flow rate and producible reserves from a unit area. Primarily due to the continuing down turn in natural gas prices, we have chosen to reduce the number of rigs we operate in the Barnett Shale trend, while maintaining our highly experienced staff. To accomplish this, we seek to reduce costs by drilling more wells on units where we hold a lower working interest than our historic average. We are also seeking to maximize the acreage that we can hold by drilling and producing in the Barnett Shale by temporarily drilling fewer wells on each drilling unit in order to permit us to develop more drilling units with comparatively fewer rigs. Where possible, we also seek to maximize our liquidity, while increasing profitability of our projects through deferring certain fracing, completion and pipeline hookup costs during periods of low natural gas prices and while our cost for these services continues to decline.

     We strive to achieve a balance between acquiring acreage, seismic data (both 2-D and 3-D) and timely project evaluation through the drillbit to ensure that we minimize the costs to test for locations for commercial reserves while building a significant lease position. Our first exploration wells in these trends are frequently vertical wells because they allow us to acquire the necessary thermal maturity and rock property data, while also permitting us to test various fracturing and completion techniques without incurring the cost of drilling horizontal wells.

     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 and development 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 fracing and horizontal drilling technologies and the experience of our management in the development, processing and analysis of 3-D projects and data in the Barnett Shale and onshore Gulf Coast, will play a significant part in our future success.

     In our onshore Gulf Coast area, we generally seek to develop prospects consistent with our expertise and based upon our analysis of 3-D seismic data. We currently own the rights to over 8,527 square miles of seismic data in our Gulf Coast area, together with the right to an additional 350 square miles as a result of a data swap with a leading seismic multi-client library provider. After developing a prospect and obtaining the leasehold rights on the acreage where the prospect is located, we generally seek to farm-out a portion of our interest in the prospect and associated leasehold acreage on a promoted basis to reduce our risks and to control our costs.

     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, 2008, we operated 218 gross producing oil and natural gas wells. We generally seek to control operations for most new exploration and development in the Barnett Shale area, taking advantage of our technical staff experience in horizontal drilling and hydraulic fracturing. During 2008, we operated 66 of the 80 gross wells that we participated in drilling in the Barnett Shale.

     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.

SIGNIFICANT PROJECT AREAS

     Our operations are focused primarily in the Barnett Shale trend in North Texas, the Marcellus Shale in New York, Pennsylvania, West Virginia and Virginia and in the onshore Gulf Coast area extending from South Louisiana to South Texas. Our other areas of interest include the U.K. North Sea, other shale trends in West Texas, New Mexico, Mississippi, Kentucky, Illinois, Arkansas, and North Dakota and the Camp Hill Field in Texas. The table below highlights our main areas of activity:

										3-D Seismic				Net				Drilling Capital
		Productive Wells								Data				Leased				Expenditures
		Gross				Net				(Sq. Miles)				Acres				2008				2009 Plan
																		(In millions)
Barnett Shale			189				135.0				524				59,336			$	227.6			$	85.0
Marcellus Shale(1)			1				0.2				—				91,659				1.3				—
Gulf Coast			113				31.4				8,527				40,009				19.9				3.0
U.K. North Sea			—				—				2,057				24,798				4.2				—
Other Shales			14				0.4				18				263,394				1.2				—
Camp Hill			57				55.8				—				928				7.1				2.0
Other			—				—				2,130				45,226				3.3				—
Total			374				222.8				13,256				525,350			$	264.6			$	90.0

Barnett Shale Area

     As of December 31, 2008, we had approximately 82,331 gross and 59,336 net mineral acres under lease and 864 gross and net mineral acres subject to lease options in the Barnett Shale. Nearly 37% of our total Barnett Shale lease acreage, 30,871 gross acres, is either in currently designated producing units, units on which wells have been drilled and are awaiting completion and/or hookup, or will be placed in units that we currently plan to drill in 2009. As of December 31, 2008, we had drilled 53 gross (38.6 net) Barnett Shale wells that were waiting on completion and/or pipeline hook-up, of which we operated 43. Between January 1, 2009 and February 20, 2009, we placed an additional 15 gross (10.3 net) wells on production, while drilling another ten gross (9.5 net) wells, leaving us with an inventory of 47 gross (36.9 net) wells drilled and waiting on completion and/or pipeline hook-up. Eight gross (6.6 net) wells had been frac’d and completed and were waiting on imminent pipeline connection.

     During 2009, we intend to pursue a deliberate strategy of developing an inventory of drilled wells that are waiting on fracing and completion. We are undertaking this strategy due to the recent precipitous decline in natural gas prices, and our expectation that fracing and completion costs will drop significantly over the remainder of the year.

     Since 2005, we have drilled only horizontal wells in the Barnett Shale area. Our Barnett horizontal wells generally have target depths of 8,500 to 12,500 feet including the lateral section. Typical costs to drill and complete a Barnett Shale horizontal well ranged from approximately $2.0 million to $4.2 million during 2008. However, we currently expect the cost of fracing and completion to decline in 2009 due to reduced fracing and completion activity as a result of lower natural gas prices. In 2008, we tested a new drilling strategy called “stagger stack” drilling in which we drill two layers of horizontal wells and simultaneously frac them. We are now observing an extended production test of this technology on one of our well sites. If this strategy ultimately proves successful, we expect it will permit us to more efficiently develop and produce thicker sections of the Barnett Shale and may permit us to achieve a higher density of wells without significantly sacrificing either reserves or production, leading to an increase in the number of potential development locations, and higher ultimate recovery on our Barnett Shale acreage.

     We continue to focus our efforts on our Tarrant County urban drilling program. On our initial urban pad site on the University of Texas at Arlington campus, we brought six wells on production in November 2008. We plan to drill our second set of six to eight wells from this well pad during 2009, with the potential of drilling up to 16 more wells in the future. As of year-end 2008, we were operating four rigs that were drilling exclusively horizontal wells in the Barnett Shale. However, in connection with our reduced capital budget, we have released one of these rigs in early March.

Marcellus Shale Area

     As of December 31, 2008, we owned interests in 230,148 gross (91,659 net) acres in the Marcellus shale trend, principally in Pennsylvania, New York and West Virginia. Our principal joint venture partner in this trend is Avista. We serve as operator of our joint venture with Avista under a joint operating agreement with Avista and provide all geotechnical, land and accounting support to the joint venture. We have also agreed to perform specified management services for the Avista affiliate that is our partner in the joint venture on the same cost and reimbursement bases provided for in the joint operating agreement. An operating committee composed of one representative of each party provides overall supervision and direction of joint operations. Each representative has a vote equal to the participating interest in the properties and operations of the party it represents. Avista or its designee has the right to become a co-operator of the properties if all of its membership interests or substantially all of its assets are sold to an unaffiliated third party or if we default under the terms of any pledge of our interest in the properties.

     Under the terms of the joint venture, each party committed to contribute up to $150 million in cash and properties to acquire and develop acreage in the Marcellus Shale play including the dedication of all of its Marcellus Shale leasehold owned at the time of the formation of the joint venture. In connection with formation of the joint venture last August, Avista contributed certain leasehold interests costing approximately $27.5 million and agreed to fund 100% of the joint venture’s next approximately $71.5 million of expenditures related to the Marcellus Shale play (the “Initial Cash Contribution”). After the Initial Cash Contribution has been funded by Avista, the parties will share all costs of joint venture operations in accordance with their participating interests, which we expect will generally be 50/50. As a result of Avista’s obligation to fund the Initial Cash Contribution, we do not currently expect that we will be required to contribute any cash to fund capital and exploration expenses in the Marcellus Shale during 2009.

     Subject to specified exceptions, net cash flow from hydrocarbon production from the Marcellus joint venture properties and related sales proceeds, if the properties are sold, will be allocated first to the joint venture partners in proportion to their respective investments (with property dedications generally valued on a cost basis) until Avista has recovered its investment, then 100% to us until we recover approximately $33.5 million, and thereafter in accordance with the parties’ participating interests, which we expect will generally be 50/50. We have also agreed to jointly market Avista’s share of the production from the properties with our own until the cash flows and sale proceeds are allocated in accordance with the parties’ participating interests under the joint operating agreement. In addition to our share in the production and sale proceeds from joint venture properties, we also acquired as part of the transaction (through a wholly-owned subsidiary) an interest in the Avista joint venture entity that entitles us to increasing percentages of the Avista entity’s profits if that entity’s members receive a return of their investment and specified internal rates of return on these investments are achieved. Our interest in the Avista entity provides consent rights only in limited, specified circumstances and generally does not entitle us to vote or participate in the management of the Avista entity, which is controlled by its members and affiliates.

     As part of the transaction, and subject to certain exceptions, the parties agreed to enter into an area of mutual interest covering the Marcellus Shale play, wherein any lease, royalty or mineral rights acquired by one party within the area must be proportionately offered to the other on the same terms and conditions. The area of mutual interest will remain in place until the earliest to occur of the following events, at which time the area of mutual interest will only continue to apply to those areas where the joint venture is active: (1) December 31, 2010, (2) the date on which the parties’ collective investment reaches $300 million, (3) upon Avista’s request to be designated (or have its designee designated) as a co-operator of the properties in connection with the sale to an unaffiliated third party of all of its membership interests or substantially all of its assets and (4) upon the required designation of Avista (or its designee) as a co-operator of the properties in connection with our default under the terms of any pledge of our interest in the properties.

     The parties have limited rights to transfer their respective interests in the properties until the Initial Cash Contribution has been satisfied. After that time, each party’s ability to transfer its interest in the joint venture to third parties is subject in most instances to preferential purchase rights for transfers of less than 10% of its interest in joint venture properties, or to “tag along” rights for most other transfers. Avista’s tag along rights do not apply upon a change of control of Carrizo.

Gulf Coast Area

     In recent years, we have drilled wells in the Wilcox, Smackover and Frio/Vicksburg trends where our exploration team has many years of experience. Our Gulf Coast area generally contains geologically complex natural gas objectives well-suited for drilling using 3-D seismic evaluation. We have developed a large inventory of undrilled prospects in the Gulf Coast area, almost all of which are supported by 3-D seismic. We have data licenses for approximately 8,527 square miles of 3-D seismic data and control 40,009 net acres of leasehold in the Gulf Coast area. In 2008, we incurred capital drilling expenditures of $19.9 million and drilled six gross (3.3 net) wells, three of which we operated. We currently have budgeted to drill three gross (1.0 net) wells during 2009 and also expect to conduct an active workover program to maintain production while reducing capital expenditures. These activities are budgeted to cost approximately $3.0 million in 2009. From January 1, 2003 through December 31, 2008, we drilled and completed 101 wells (31.2 net) in the Gulf Coast area on 119 attempts.

U.K. North Sea Region

     We believe our low entry cost U.K. North Sea strategy is a natural extension of our previous experience exploiting hydrocarbons in proven mature regions where significant additional exploration potential exists, through available, large modern 3-D seismic surveys, related technology and proper risk management. We currently hold interests in three licenses (two in the Central Graben area and one in the Southern Gas area) totaling approximately 24,800 net acres and currently expect to be granted interests in four new licenses totaling another 164,518 gross (115,548 net) acres in the 25th licensing round of the U.K. government. The two existing licenses in the Central Graben area cover substantially the entire Huntington discovery.

     Our Huntington discovery well (in which we retained a 15% working interest) was drilled in the second quarter of 2007 in water depths of approximately 300 feet. This exploration well resulted in two independent discoveries, one in the shallower Paleocene Forties reservoir and another in the deeper Upper Jurassic Fulmar objective. A combined maximum test rate of over 11,000 Bbls/d equivalent was measured in the discovery well.

     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 to us of approximately $9.2 million. We and our joint venture partners have been reviewing these well results and have commenced preliminary field development planning for the Forties reservoir, including the refurbishment and manufacture of certain long-lead items such as subsea wellheads. In 2008, we incurred approximately $2.6 million in connection with this pre-development work.

     In late 2008, two wells were drilled by the joint venture in the adjoining block 22/14a, one of which confirmed the extension of a small portion of the Huntington field on their license. This outcome will now require us and our joint venture partners to enter into negotiations with the block 22/14a joint venture to prepare a joint development plan for the field to be submitted for approval to the U.K. government in order to unitize the field. The parties have begun preliminary unitization discussions.

     In January 2009, Oilexco North Sea Limited (“Oilexco”), our largest joint venture partner with respect to the Huntington Field, and at that time the operator of our license, entered into insolvency proceedings in the U.K. We have not suffered a direct material adverse financial impact as a result of Oilexco’s bankruptcy. However, this action resulted in the removal of Oilexco as operator and the subsequent appointment of a subsidiary of E.ON Ruhrgas AG as license operator. We believe that these events have caused some delay in field development planning and unitization discussions. As a consequence, although our joint venture remains committed to timely development of the Huntington Field, we currently believe that production from this field will not commence until at least the end of 2010 or the first half of 2011. The administrators of Oilexco’s insolvency proceeding have announced that they are actively seeking to sell all of Oilexco’s business and assets, including its interest in the Huntington Field. We are also considering the sale of all or a portion of our interest in the Huntington Field, although there can be no assurance that we will be able to sell our interest on terms that are acceptable to us, or at all.

     Following the initial Huntington discovery well, we and our joint venture partners completed an appraisal well in the Huntington Fulmar discovery in early 2008. At least one additional Fulmar appraisal well will likely be necessary prior to the sanctioning of the development of the Fulmar reservoir. We and our joint venture partners have not yet agreed upon the timing for this next well, but it is currently expected to be in early 2010.

     The U.K. government has informed us that we were the successful bidder, along with certain joint venture partners, on four additional licenses in the 25th licensing round conducted in mid 2008. License winners have been announced but no licenses have been formally awarded. Our interests in these blocks vary from 40% to 100%. None of these blocks, if granted, contain firm well commitments, nor would they require us to incur material capital expenditures in the near term.

Other Shale Project Areas

     We continue to evaluate our acreage and seismic and well data in other resource shale projects. Regional mapping of shale extent, depth, thickness, organic content, thermal maturation, mineralogy, as well as cost and availability of acquiring leases, are analyzed to define the project fairways to lease, and to assist in identifying the locations for initial exploratory wells. We have been successful in acquiring approximately 34,400 gross (26,300 net) acres in the Fayetteville Shale in Arkansas, and approximately 76,000 gross (63,000 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 5,323 net acres in the Delaware Basin. We have leased approximately 30,000 net acres in the New Albany shale project located in Illinois and Kentucky. In 2008, we invested $1.2 million dollars to drill nine gross (0.3 net) wells in the Fayetteville Shale. In 2009, we currently plan to further evaluate this acreage position and data in our possession and to participate only in wells that are operated by third parties, particularly in the Fayetteville Shale, where a number of industry partners are active.

Camp Hill Field

     We own interests in approximately 2,630 gross acres in the Camp Hill Field in Anderson County, Texas. We have an average working interest of approximately 92.1% in this field and an average net revenue interest of 71.0%. We currently operate all of these leases. During 2008, we drilled 17 gross (17.0 net) producing wells and 13 gross (13.0 net) injection wells in the field. Our capital and exploration expenditures during 2008 in the Camp Hill Field were $10.4 million. During the year ended December 31, 2008, the project produced an average of 33 Bbls/d of 19 API gravity oil, but was up to 72 barrels of oil per day in December. As a result of our aggressive drilling program in 2008, we converted over 1.4 million Bbls from proved undeveloped to proved developed reserves. During 2009, we currently plan to seek to negotiate lower gas prices (which is used to generate steam in the field) in an attempt to improve field economics, work on upgrades to the field infrastructure, including converting a deep well drilled in 2008 to a water disposal well, perforating and completing 44 of the wells drilled during 2008 and in prior years, hooking the new injectors up to the steam generators and refurbishing two steam generators, and observing the field response to the additional 30 wells drilled in the field during 2008. We do not currently plan to drill any wells in this field in 2009.

     The wells drilled in the Camp Hill Field produce from a depth of 500 feet and 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, 2008 averaged $84.69 per barrel ($14.11 per Mcfe). Costs were high, as expected, because oil production response typically lags the startup of steam injection. The oil produced, although viscous, commands a comparable price to West Texas Intermediate crude (an average premium of $0.15 per Bbl to Flint Hills WTI during the year ended December 31, 2008) due to its suitability as a lube oil feedstock.

     As of December 31, 2008, we had 8.2 MMBbls of proved oil reserves in this project, with 3.2 MMBbls of oil reserves currently developed. These proved reserves are based on an ultimate recovery factor of 49%. The proved undeveloped reserves at the Camp Hill Field constitute 6% of our proved reserves and account for 4% of our present value of net future revenues from proved reserves as of December 31, 2008.

     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 demonstrated a 49% recovery efficiency as of December 31, 2008 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 area and later, the Barnett Shale and other shale plays 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. After the acquisition, we injected steam for much of the period from 1994 to 2000. Since ramping up activity commencing with seven wells in 2005, we have drilled ten wells (including six injection wells) in 2006, 30 wells (including 13 injection wells) in 2007 and 30 wells (including 13 injection wells) in 2008.

     To fully develop the field, we expect to drill an additional approximately 244 gross wells (including 111 injection wells) from 2009 through 2024, at a total estimated cost of approximately $22.7 million and total operating costs, including steam, of approximately $127.2 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.

     The most important reason for our deferral of full development prior to the end of 2005 was the potential for significantly improved profitability that would result from the construction of a nearby cogeneration plant. Cogeneration plants typically provide 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 $114 million in steam costs compared to $22.7 million for drilling and development capital that is needed to fully develop the proved undeveloped reserves in this field.

     We have had difficulties maintaining desired levels of steam injection in the field over the last several years. Originally, 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 acquired a replacement generator in 2008, and this generator commenced steam injection shortly thereafter. Our other two generators were not available for injection in 2007 and 2008 due to unexpected permitting issues and the need for repair work. We received the permits for these two generators to recommence injection in the fourth quarter of 2007. Although these permits 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, 2008 proved reserves) does not reduce our proved reserves from prior estimates. 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. We currently expect that one of these generators will be ready to inject steam by the end of 2009 and the other should be operational in 2010. In addition, we obtained a small portable generator in 2008. This small generator is now also undergoing repairs.

ADDITIONAL OIL AND GAS DISCLOSURES

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, 2008. The reserve data and the present value as of December 31, 2008 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, 2008, 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)			7,869				10,439				18,308
Natural gas (MMcf)			216,229				176,507				392,736
Total proved reserves (MMcfe)			263,443				239,141				502,584
PV-10 Value(1)(2)		$	466,268			$	129,623			$	595,891

     No estimates of proved reserves comparable to those included herein have been included in reports to any federal agency other than the Commission. The reserves data set forth in this Annual Report on Form 10-K represents 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 Commission 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, 2008, 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, 2008. 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 432.1 Bcfe, or 86% of our proved reserves, for the year ended December 31, 2008, which reserves were located on our Barnett Shale properties. Fairchild & Wells, Inc. determined 49.2 Bcfe, or 10% of our proved reserves, for the year ended December 31, 2008, which reserves were located on our properties in the Camp Hill Field. Ryder Scott Company Petroleum Engineers determined 21.3 Bcfe, or 4% of our proved reserves, for the year ended December 31, 2008, 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 has steadily increased to 41.8% in 2008, from 38.2% in 2007, and from 25.0% in 2006. Set forth below is our reserve replacement ratio for the years ended December 31, 2008, 2007 and 2006.

		2008				2007				2006
Reserve Replacement Ratio			705	%			887	%			607	%

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,
		2008				2007				2006
Production volumes
Oil (MBbls)			186				241				255
Natural gas (MMcf)			24,513				16,042				10,176
Natural gas equivalent (MMcfe)			25,632				17,487				11,705
Average sales prices
Oil (per Bbl)		$	99.74			$	71.42			$	63.62
Natural gas (per Mcf)			7.80				6.77				6.56
Natural gas equivalent (per Mcfe)			8.19				7.19				7.09
Average costs (per Mcfe)
Camp Hill operating expenses		$	14.11			$	16.12			$	11.50
Other operating expenses			1.44				1.36				1.33
Total operating expenses(1)			1.48				1.41				1.40

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 $14.4 million, $11.7 million and $10.0 million for the years ended December 31, 2008, 2007 and 2006, respectively. We have also included capitalized overhead in our finding cost of $7.8 million, $4.5 million and $3.5 million for the years ended December 31, 2008, 2007 and 2006, respectively. We have also included non-cash asset retirement obligations of $0.6 million, $2.0 million and $0.3 million for the years ended December 31, 2008, 2007 and 2006, respectively.

		Year Ended December 31,
		2008				2007				2006
		(In thousands)
Acquisition costs:
Other unproved properties		$	271,618			$	54,467			$	48,409
Proved properties			—				—				—
Exploration			235,382				144,402				104,473
Development			49,626				30,562				37,889
Asset retirement obligation			630				1,961				299
Total costs incurred		$	557,256			$	231,392			$	191,070
Total proved reserves added (MMcfe)			180,594				155,139				71,066
Average all-sources finding cost (per Mcfe)		$	3.09			$	1.49			$	2.69
Average all-sources finding cost (per Mcfe) — excluding Marcellus(1)		$	2.75			$	1.49			$	2.69
Average finding and development cost (per Mcfe)(2)		$	1.68			$	1.22			$	2.10
Average drilling finding cost (per Mcfe)		$	1.58			$	1.14			$	2.01

     For the three year period ended December 31, 2008, our total adjusted cost for exploration, development and acquisition activities was approximately $979.8 million. Total exploration, development and acquisition activities for the three year period ended December 31, 2008 have added approximately 406.8 Bcfe of net proved reserves at an all-sources finding cost of $2.41 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 $47.6 million, $75.7 million and $31.4 million at December 31, 2008, 2007 and 2006, respectively, and includes total additions to proved undeveloped reserves of 53.3 Bcfe, 59.6 Bcfe and 28.4 Bcfe for the years ended December 31, 2008, 2007 and 2006, respectively. Accordingly, had we included future development costs in our computations, the average all-sources finding costs would have been $3.35, $1.98 and $3.13 per Mcfe for the years ended December 31, 2008, 2007 and 2006, respectively.

     In order to maintain continued growth and achieve 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,
		2008				2007				2006
		(In thousands)
Acquisition costs
Unproved prospects		$	271,618			$	54,467			$	48,409
Proved properties			—				—				—
Exploration			235,382				144,402				104,473
Development			49,626				30,562				37,889
Asset retirement obligation			630				1,961				299
Total costs incurred(1)		$	557,256			$	231,392			$	191,070

Drilling Activity

     The following table sets forth our drilling activity for the years ended December 31, 2008, 2007 and 2006. 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.

		Year Ended December 31,
		2008								2007								2006
		Gross				Net				Gross				Net				Gross				Net
Exploratory Wells
Productive			83				60.0				65				42.8				47				26.9
Nonproductive			2				0.3				1				0.4				3				0.9
Total			85				60.3				66				43.2				50				27.8
Development Wells
Productive			31				24.2				29				24.0				20				17.1
Nonproductive			3				3.0				1				1.0				—				—
Total			34				27.2				30				25.0				20				17.1

     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, 2008.

		Company
		Operated								Other								Total
		Gross				Net				Gross				Net				Gross				Net
Oil			67.0				59.3				2.0				1.2				69.0				60.5
Natural gas			151.0				122.3				154.0				40.0				305.0				162.3
Total			218.0				181.6				156.0				41.2				374.0				222.8

Acreage Data

     The following table sets forth certain information regarding our developed and undeveloped lease acreage as of December 31, 2008. Developed acres refer 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
Barnett Shale — Texas			30,871				20,144				51,460				39,192				82,331				59,336
Marcellus Shale
New York			—				—				34,642				8,213				34,642				8,213
Pennsylvania			—				—				83,862				31,393				83,862				31,393
West Virginia			—				—				98,405				45,522				98,405				45,522
Virginia and other			—				—				13,239				6,531				13,239				6,531
Marcellus Shale Total			—				—				230,148				91,659				230,148				91,659
Gulf Coast
Texas			30,853				9,616				34,906				13,514				65,759				23,130
Louisiana			1,977				1,024				15,625				14,571				17,602				15,595
Alabama			160				42				1,800				1,242				1,960				1,284
Gulf Coast Total			32,990				10,682				52,331				29,327				85,321				40,009
U.K. North Sea(1)			—				—				110,628				24,798				110,628				24,798
Other Shales(2)			293				54				438,977				263,340				439,270				263,394
Other Texas(3)			2,259				2,042				52,987				42,969				55,246				45,011
Other			—				—				7,618				1,143				7,618				1,143
Total			66,413				32,922				944,149				492,428				1,010,562				525,350

     The table does not include 16,735 gross and 6,200 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, 2008. 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 their primary term or an extension thereof (a period that can be from three to 10 years depending on the area and the age of the lease). If no production is established on our leases that are in their primary term, approximately 7% of our acreage will expire in 2009, 24% will expire in 2010 and 42% will expire in 2011.

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 and transportation, 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, provide nondiscriminatory access to common carrier pipelines 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. Some of the delay in bringing our natural gas to market has been the lack of available pipeline systems in the Barnett Shale, particularly those that would take natural gas production from the lease to the existing infrastructure. In order to partly alleviate this issue, commencing in 2008, certain of our wholly-owned subsidiaries have constructed non-jurisdictional gathering facilities in cases where we have determined that we can construct those facilities more quickly or more efficiently than waiting on an unrelated third-party pipeline company.

     One of our pipeline subsidiaries, Hondo Pipeline Inc., exercises the power of eminent domain and transports gas for third parties and is a regulated public utility within the meaning of Section 101.003 (the “Gas Utility Regulatory Act” or “GURA”) and Section 121.001 (the “Cox Act”) of the Texas Utilities Code. Both GURA and the Cox Act prohibit unreasonable discrimination in the transportation of natural gas and authorize the Texas Railroad Commission (“RRC”) to regulate gas transportation rates. However, GURA provides for negotiated rates with transportation, industrial or similar large-volume contract customers so long as neither party has an unfair negotiating advantage, the negotiated rate is substantially the same as that negotiated with at least two other customers under similar conditions, or sufficient competition existed when the rate was negotiated.

     Although we 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 new regulations that require both interstate pipelines and certain non-interstate pipelines to post daily information regarding their design capacity and daily scheduled flow volumes at certain points on their systems. The Energy Policy Act of 2005 also significantly increased the penalties for violations of the NGA and the FERC’s regulations to up to $1 million per day for each violation.

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 this indexing system or any new FERC regulations on the transportation costs associated with oil production from our oil producing operations.

     There regularly are 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, we cannot predict whether or to what extent the trend toward federal deregulation of the petroleum industry will continue, particularly in light of the change in the U.S. administration in 2009, or what the ultimate effect on our sales of gas, oil and other petroleum products will be.

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.

      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 U.S. Congress is actively considering legislation to reduce emissions of greenhouse gases from sources within the United States between 2012 and 2050. For example, the 110th session of Congress considered various bills that proposed 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. 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 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 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 number of our wells on a non-operated 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. Even then, particularly in urban settings, the cost of performing detailed title work can be expensive. We may choose to forego detailed title examination by title lawyers on a portion of the mineral leases that we place in a drilling unit or conduct less title work than we have traditionally performed. Our senior credit facility is 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 at least 10% of its oil and natural gas revenues as follows:

		Year Ended December 31,
		2008				2007				2006
DTE Energy Trading, Inc.			39	%			—				—
Cokinos Natural Gas Company			11	%			11	%			—
Reichmann Petroleum			—				—				10	%
Chevron/Texaco			—				—				11	%
Houston Pipeline Company			—				11	%			—
Energy Transfer			—				10	%			—
Crosstex Energy			10	%			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, 2008, we had 104 full-time employees. 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 testing. 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 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

The global financial and credit crisis may have impacts on our liquidity and financial condition that we currently cannot predict.

     The continued credit crisis and related turmoil in the global financial system may have a material impact on our liquidity and our financial condition, and we may ultimately face major challenges if conditions in the financial markets do not improve. Our ability to access the capital markets or borrow money may be restricted or made more expensive at a time when we would like, or need, to raise capital, which could have an adverse impact on our flexibility to react to changing economic and business conditions and on our ability to fund our operations and capital expenditures in the future. The economic situation could have an impact on our lenders or customers, causing them to fail to meet their obligations to us, and on the liquidity of our operating partners, resulting in delays in operations or their failure to make required payments. Also, market conditions could have an impact on our natural gas and oil derivatives transactions if our counterparties are unable to perform their obligations or seek bankruptcy protection. Additionally, the current economic situation could lead to further reductions in the demand for natural gas and oil, or further reductions in the prices of natural gas and oil, or both, which could have a negative impact on our financial position, results of operations and cash flows. While the ultimate outcome and impact of the current financial crisis cannot be predicted, it may have a material adverse effect on our future liquidity, results of operations and financial condition.

Natural gas and oil prices are highly volatile and have declined significantly since mid 2008, and lower prices will negatively affect our financial condition, planned capital expenditures and results of operations.

     Since mid 2008, publicly quoted spot natural gas and oil prices have declined significantly from record levels in July 2008 of approximately $145.31 per Bbl (West Texas Intermediate) and $11.87 per Mcfe (WAHA) to approximately $40.07 per Bbl and $2.92 per Mcfe as of March 2, 2009. In the past, some oil and gas companies have curtailed production to mitigate the impact of low natural gas and oil prices. We may determine to shut in a portion of our production as a result of the decrease in prices. The decrease in natural gas and oil prices has had a significant impact on our financial condition, planned capital expenditures and results of operations. Further declines in natural gas and oil prices or a prolonged period of low natural gas and oil prices may materially adversely affect our financial condition, liquidity (including our borrowing capacity under our senior credit facility), ability to finance planned capital expenditures and results of operations.

     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.

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 in the onshore Gulf Coast area 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 Annual Report on 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, 2008, approximately 58.6% 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, 2008 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, since 2005, 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.

We participate in oil and natural gas leases with third parties and these third parties may not be able to fulfill their commitments to our projects.

     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 joint activity obligations of the other working interest owners such as nonpayment of costs and liabilities arising from the actions of the other working interest owners. In addition, the current economic downturn, the credit crisis and the decline in natural gas and oil prices may increase the likelihood that some of these working interest owners, particularly those that are smaller and less established, are not able to fulfill their joint activity obligations. Many of our project partners are experiencing liquidity and cash flow problems. These problems may lead our partners to attempt to delay the pace of drilling or project development in order to preserve cash. A partner may be unable or unwilling to pay its share of project costs. In some cases, an example of which recently occurred in our Huntington Field, a partner may declare bankruptcy. In the event any of our project partners do not pay their share of such costs, we would likely have to pay those costs, and we may be unsuccessful in any efforts to recover these costs from our partners, which could materially adversely affect our financial condition.

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 our existing senior credit facility or new credit facilities may not be available in the future. The current credit crisis has had an adverse impact on our ability to obtain additional financing. 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 drilling program by releasing rigs or deferring fracturing, completion and hookup of the wells to pipelines and thereby adversely affect our production, cash flow, and the recoverability and ultimate value of our natural gas and oil properties, in turn negatively affecting our business, financial condition and results of operations.

Our senior credit facility contains operating restrictions and financial covenants, and we may have difficulty obtaining additional credit.

     Over the past few years, increases in commodity prices and our successful drilling program led to increased proved reserve amounts, and the resulting increase in our estimated discounted future net revenue allowed us to increase the borrowing base under our senior credit facility. However, as a result of the significant decline in natural gas and oil prices that began in mid 2008, or other factors, the lenders under our senior credit facility may adjust our borrowing base downward, thereby reducing our borrowing capacity. Our senior credit facility is secured by a pledge of substantially all of our producing natural gas and oil properties and assets, guaranteed by our subsidiaries CCBM, Inc., CLLR, Inc., Hondo Pipeline, Inc., Carrizo (Marcellus) LLC and Carrizo Marcellus Holding Inc. and contains 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 senior credit facility also requires that specified financial ratios be maintained. Although we currently believe that we can meet all of our financial covenants with the business plan that we have put in place, our business plan is based on a number of assumptions, the most important of which is a relatively stable natural gas price at economically sustainable levels. If the price that we receive for our natural gas production deteriorates significantly from current levels, it could lead to lower revenues, cash flow and earnings, which in turn could lead to a default under certain financial covenants contained in our senior credit facility, including the covenants related to working capital and the ratio of EBITDA to debt coverage. In order to provide a further margin of comfort with regards to these financial covenants, we may seek to further reduce our capital and exploration budget, sell non-strategic assets, opportunistically modify or increase our natural gas hedges, or approach our lenders under our senior credit facility for modification of either or both of the financial covenants discussed above. There can be no assurance that we will be able to successfully execute any of these strategies, or if executed, that they will be sufficient to avoid a default under our senior credit facility if a precipitous decline in natural gas prices were to occur in the future. We may not be able to refinance our debt or obtain additional financing, particularly in view of the restrictions of our senior credit facility on our ability to incur additional debt and the fact that substantially all of our assets are currently pledged to secure obligations under the senior credit facility. The restrictions of our senior credit facility 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 senior credit facility 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 senior credit facility, 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 have limited experience drilling wells in the Marcellus Shale and less information regarding reserves and decline rates in the Marcellus Shale than in other areas of our operations. We may face difficulties in securing and operating under authorizations and permits to drill and/or operate our Marcellus Shale wells.

     We have limited exploration experience and no development experience in the Marcellus Shale. As of February 15, 2009, we have participated in the drilling of only two wells in the Marcellus Shale area. Other operators in the Marcellus Shale area also have limited experience drilling in the area. As a result, we have less information with respect to the ultimate recoverable reserves and the production decline rate in the Marcellus Shale than we have in other areas in which we operate. Moreover, the recent growth in exploration in the Marcellus Shale has drawn intense scrutiny from environmental interest groups, regulatory agencies and other governmental entities. As a result, we may face significant opposition to our operations that may make it difficult or impossible to obtain permits and other needed authorizations to operate or otherwise make operating more costly or difficult than operating elsewhere.

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. 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, some of our wells in the Gulf Coast were shut in following Hurricanes Katrina and Rita in 2005 and Hurricanes Gustav and Ike in 2008. 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.

     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 or could create liability for us for the operator’s failure to properly maintain the well and facilities and to adhere to applicable safety and environmental standards. With respect to properties that we do not operate:

	•		the operator could refuse to initiate exploration or development projects;
	•		if we proceed with any of those projects the operator has refused to initiate, we may not receive any funding from the operator with respect to that project;
	•		the operator may initiate exploration or development projects on a different schedule than we would prefer;
	•		the operator may propose greater capital expenditures than we wish, including expenditures to drill more wells or build more facilities on a project than we have funds for, which may mean that we cannot participate in those projects or participate in a substantial amount of the revenues from those projects; and
	•		the operator may not have sufficient expertise or resources.

Any of these events could significantly and adversely affect our anticipated exploration and development activities.

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. Historically, we have generally delivered 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. Due to the lack of available pipeline capacity in the Barnett Shale, we have recently begun entering into firm transportation agreements in the Barnett Shale, which are more costly to us than the interruptible or short-term transportation 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 many of our key employees as a way to assist in retaining their services and motivating their performance. 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. In addition, the counterparties under our derivatives contracts may fail to fulfill their contractual obligations to us.

Periods of 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.

     During periods when natural gas and oil prices are relatively high, which was recently the case until mid 2008, well service providers and related equipment and personnel may be in short supply. These shortages can cause escalating prices, delays in drilling and other exploration activities and the possibility of poor services coupled with potential damage to downhole reservoirs and personnel injuries. Such pressures may 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.

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 “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.” Once incurred, a write-down of natural gas and oil properties is not reversible at a later date. We recorded a ceiling test limitation write-down at the end of 2008, and we could incur additional write-downs in the future, particularly as a result of a continuation in the decline of natural gas and oil prices. 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 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. Even then, particularly in urban settings, the cost of performing detailed title work can be expensive. We may choose to forgo detailed title examination by title lawyers on a portion of the mineral leases that we place in a drilling unit or conduct less title work than we have traditionally performed. As is customary in our industry, we generally 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 and before drilling a well on a leased tract. We, in some cases, perform curative work to correct deficiencies in the marketability or adequacy 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. The failure of title may not be discovered until after a well is drilled, in which case we may lose the lease and the right to produce all or a portion of the minerals under the property.

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.

     BOE or Barrel of Oil Equivalent. A BOE is 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.

     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.

     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 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			53			President, Chief Executive Officer and Director
Paul F. Boling			55			Chief Financial Officer, Vice President, Secretary and Treasurer
J. Bradley Fisher			48			Vice President and Chief Operating Officer
Gregory E. Evans			59			Vice President of Exploration
Richard H. Smith			51			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. From 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
2008
First Quarter		$	62.47			$	43.11
Second Quarter			76.30				58.26
Third Quarter			69.51				30.75
Fourth Quarter			36.26				11.72
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

     The closing market price of our common stock on March 2, 2009 was $8.73 per share. As of March 2, 2009, there were an estimated 143 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 senior credit facility restricts our ability to pay dividends. See Item 7. “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, 2003 to December 31, 2008, with the cumulative total return of the S&P 500 Index and the American Stock Exchange (AMEX) Natural Resources Industry Index of publicly traded companies over the same period. The graph assumes that $100 was invested on December 31, 2003 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 Commission. Shareholders are cautioned against drawing any conclusions from the data contained therein, as past results are not necessarily indicative of future financial performance.

		S&P				AMEX				COGI
December 31, 2003			100				100				100
December 31, 2004			109				128				157
December 31, 2005			112				196				343
December 31, 2006			128				217				403
December 31, 2007			132				277				760
December 31, 2008			81				142				224

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

     The Company made no repurchases of its common stock in the fourth quarter of 2008.

Item 6. Selected Financial Data

     Our financial information set forth below for each of the five years in the period ended December 31, 2008, 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,
		2008				2007				2006				2005				2004
		(In thousands, except per share data)
Statement Of Operations Data:
Oil and natural gas revenues		$	216,677			$	125,789			$	82,945			$	78,155			$	52,397
Costs and expenses:
Oil and natural gas operating expenses			37,885				24,662				16,428				10,437				8,392
Impairment of oil and natural gas properties			138,591				—				—				—				—
Depreciation, depletion and amortization			58,311				41,899				31,129				21,374				15,464
Third party gas purchase			6,570				—				—				—				—
General and administrative			23,425				18,912				14,909				11,243				8,255
Accretion expense related to asset retirement			154				374				496				70				23
Total costs and expenses			264,936				85,847				62,962				43,124				32,134
Operating income (loss)			(48,259	)			39,942				19,983				35,031				20,263
Gain (loss) on derivatives			37,499				(1,366	)			16,457				(5,882	)			(625	)
Loss on extinguishment of debt			(5,689	)			—				(294	)			(3,721	)			—
Equity in net income/(loss) of Pinnacle Gas Resources, Inc.			—				—				35				(2,542	)			(1,399	)
Interest (expense) income, net of amounts capitalized and interest income			(7,636	)			(13,994	)			(8,127	)			(4,295	)			(622	)
Other income and expenses, net			17				130				427				(457	)			506
Income (loss) before income taxes			(24,068	)			24,712				28,481				18,134				18,123
Income tax expense (benefit)			(6,129	)			9,243				10,233				7,500				7,009
Income (loss) before cumulative effect of change in accounting principle			(17,939	)			15,469				18,248				10,634				11,114
Dividends and accretion of discount on preferred stock			—				—				—				—				350
Net income (loss) available to common shareholders			(17,939	)			15,469				18,248				10,634				10,764
Basic earnings (loss) per common share		$	(0.60	)		$	0.59			$	0.74			$	0.45			$	0.54
Diluted earnings (loss) per common share		$	(0.60	)		$	0.57			$	0.71			$	0.44			$	0.49
Basic weighted average shares outstanding			30,010				26,287				24,827				23,492				19,958
Diluted weighted average shares outstanding			30,010				27,120				25,565				24,361				21,818
Statements of Cash Flow Data:
Net cash provided by operating activities		$	148,754			$	95,231			$	65,437			$	38,839			$	32,501
Net cash used in investing activities			(555,345	)			(227,724	)			(161,576	)			(111,417	)			(80,294	)
Net cash provided by (used in) financing activities			403,749				135,111				72,822				95,635				50,139
Other Operating Data:
Capital expenditures		$	571,291			$	247,003			$	201,773			$	135,156			$	83,891
Debt repayments(1)			498,239				108,258				40,536				101,021				13,737

		As of December 31,
		2008				2007				2006				2005				2004
		(In thousands)
Balance Sheet Data:
Working capital (deficit)		$	(57,602	)		$	(50,053	)		$	(17,014	)		$	10,307			$	(8,937	)
Property and equipment, net			1,021,621				646,810				445,447				314,074				205,482
Total assets			1,108,014				709,670				494,795				383,101				234,345
Long-term debt, including current maturities			533,057				254,501				188,758				149,294				62,974
Total equity			426,986				310,721				212,274				155,385				121,060

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 2008, we recognized record revenues from oil and natural gas production of $209.8 million, record production of 25.6 Bcfe and a record level of oil and gas proved reserves, at December 31, 2008, of 502.6 Bcfe. The key drivers to our success for 2008 included the following:

Drilling program. Our success is largely dependent on the results of our drilling program. During the year ended December 31, 2008, we drilled 119 gross wells (87.6 net wells) with an apparent success rate of 96% that was comprised of: (1) 80 of 80 gross wells (62.8 net wells) in the Barnett Shale area, (2) five of six gross wells (3.0 of 3.3 net wells) in the onshore Gulf Coast area, (3) 17 of 17 gross wells (17.0 net wells) in the Camp Hill Field and (4) 12 of 16 gross wells (1.4 of 4.4 net wells) in other areas. We also drilled 13 gross service wells (13.0 net wells) in the Camp Hill area and one gross appraisal well (0.2 net) in the U.K. North Sea. At December 31, 2008, 56 of these gross wells were awaiting completion or pipeline connections.

Reserve Growth. As a result of our drilling program discussed above, our reserves increased 45 percent to 502.6 Bcfe at December 31, 2008, replacing 705% of 2008 production.

Production. Our 2008 annual production of 25.6 Bcfe, or 70.0 MMcfe/d was a record high. The 2008 production increased 47% from 2007 production of 17.5 Bcfe. The increase was primarily due to the addition of new Barnett Shale wells.

Commodity prices. Our average natural gas price during 2008 was $7.80 per Mcf (excluding the impact of our hedges), $1.03 per Mcf higher than the 2007 price of $6.77. Our average oil price in 2008 was $99.74 per Bbl, or $28.32 higher than in 2007. 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. These prices have declined significantly since mid-2008.

Capital funding. In order to fund our growth, we have taken steps to enhance our liquidity. In February 2008, we received approximately $135.1 million in net proceeds from an underwritten public offering of 2.59 million shares of our common stock. The net proceeds were used in part to pay down the $85.0 million then outstanding under our senior credit facility. In May 2008, we received net proceeds of approximately $365.3 million from the issuance of convertible notes. Part of the proceeds from the convertible notes offering were used to repay $75.0 million of outstanding debt under our senior credit facility and the $219.9 million then outstanding under our second lien credit facility. In December 2008, the borrowing base under our senior credit facility was also increased to $250.0 million. In connection with the formation of our joint venture in the Marcellus Shale play in August 2008, Avista agreed to fund 100% of the joint venture’s next approximately $71.5 million of expenditures related to the play. As of December 31, 2008, Avista still had approximately $40.0 million in funding commitments remaining before we are required to fund any of our Marcellus Shale joint venture capital expenditures. After this amount has been funded, the parties will share all costs on joint venture projects in accordance with their participating interests in the properties, which we expect will be generally 50/50. We currently expect that substantially all of our capital and exploration expenditures of our joint venture in the Marcellus Shale during 2009 will be met through Avista’s funding obligation.

Outlook for 2009

Our outlook for 2009 is challenging, primarily as a result of the decline in natural gas and oil prices that began in mid 2008, but our outlook for the long-term future remains positive. Production growth and stable upward movement in commodity prices are key to our future success, and we believe the following measures will have a positive impact on our results in 2009:

Control capital costs and maintain financial flexibility. In response to reduced demand for natural gas and lower natural gas prices as a result of the current economic downturn and the current cost of accessing the capital markets, we have reduced our approved capital and exploration budget for 2009 to $105.0 million, and we are striving to maintain our financial flexibility and a positive production growth profile. Further deterioration in commodity prices may cause us to reduce our capital and exploration budget for 2009 even further.

2009 drilling and capital program. In 2009 we plan to drill 45 gross (30.0 net) wells in the Barnett Shale area, 12 gross (4.0 net) wells in the Marcellus Shale play area, three gross (1.0 net) wells in the Gulf Coast area and to complete 44 gross (44.0 net) wells in the Camp Hill Field. As mentioned above, our 2009 capital and exploration budget has been reduced to approximately $105 million and includes approximately $90.0 million for drilling, comprised in Barnett Shale ($85.0 million), Gulf Coast ($3.0 million) and Camp Hill ($2.0 million). We also plan to spend $3.0 million in the U.K. North Sea, largely for pre-development project costs, and approximately $12.0 million for land and seismic activities, most of it in the Barnett Shale. We currently expect that our land acquisition, exploration and drilling program in the Marcellus will be funded by Avista under our joint venture agreement. The actual number of wells we drill will vary depending upon various factors, including the availability and cost of drilling rigs, land and industry partner issues, our available cash flow, success of drilling programs, weather delays and other factors.

Results of Operations

Year Ended December 31, 2008 Compared to the Year Ended December 31, 2007

     Revenues from oil and natural gas production for 2008 increased 67% to $209.8 million from $125.8 million in 2007. Production volumes for oil and natural gas in 2008 increased 47% to 25.6 Bcfe from 17.5 Bcfe in 2007. Realized average natural gas sales price for 2008 increased 15% to $7.80 per Mcf compared to $6.77 per Mcf in 2007, and the average oil sales price for 2008 increased 40% to $99.74 per barrel from $71.42 per barrel in 2007. The increase in natural gas production was primarily due to the production from new wells in the Barnett Shale 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, 2008 and 2007:

										2008 Period
										Compared to 2007 Period
		December 31,								Increase				% Increase
		2008				2007				(Decrease)				(Decrease)
Production volumes-
Oil and condensate (Mbbls)			186				241				(55	)			(23	)%
Natural gas (MMcf)(1)			24,513				16,042				8,471				53	%
Average sales prices-
Oil and condensate (per Bbl)		$	99.74			$	71.42			$	28.32				40	%
Natural gas (per Mcf)			7.80				6.77				1.03				15	%
Operating revenues (In thousands) -
Oil and condensate		$	18,598			$	17,197			$	1,401				8	%
Natural gas			191,231				108,592				82,639				76	%
Other			6,848				—				6,848				100	%
Total		$	216,677			$	125,789			$	90,888				72	%

     Oil and natural gas operating expenses for 2008 increased 54% to $37.9 million (or $1.48 per Mcfe) from $24.7 million (or $1.41 per Mcfe) in 2007. The increase in total operating expenses was primarily due to (i) higher transportation gathering and treating costs of $4.5 million, (ii) higher saltwater disposal costs of $1.4 million, (iii) increased compression costs of $1.4 million and (iv) higher ad valorem taxes of $2.9 million.

     The significant decline in oil and natural gas prices, indicated by average prices of $4.99 per Mcf for natural gas and $40.12 per Bbl for oil on December 31, 2008, caused the discounted present value (discounted at ten percent) of future net cash flows from proved oil and gas reserves to fall below the net book basis in the proved oil and gas properties. This resulted in a non-cash ceiling test write-down at the end of the fourth quarter of 2008 of $138.6 million ($90.1 million after tax).

     Depreciation, depletion and amortization (“DD&A”) expense for 2008 increased to $58.3 million from $41.9 million in 2007. 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 2008.

     General and administrative (“G&A”) expense for 2008 increased 24% to $23.4 million from $18.9 million for 2007. The increase in G&A was due primarily to (i) increased employee related and contractor costs of $1.2 million, (ii) increased stock-based compensation expense of $1.0 million and (iii) increased legal and professional fees of $0.8 million.

     The net gain on derivatives of $37.5 million for the year ended December 31, 2008 was comprised of a $41.4 million of unrealized mark-to-market net gain on derivatives that was partially offset by $3.9 million of net realized losses.

     In May 2008, we repaid our outstanding borrowings under the Second Lien Facility and terminated the facility. As a result, we recorded a $5.7 million loss associated with the early extinguishment of debt consisting of a $4.6 million non-cash write-off of deferred loan costs and $1.1 million in penalties paid for early retirement. In connection with the early termination, we settled the interest rate swaps and realized a $3.3 million loss, included in our net loss on derivatives.

     Interest expense and capitalized interest in 2008 were $23.5 million and $15.6 million, respectively, as compared to $26.4 million and $11.7 million in 2007. These decreases was largely attributable to the pay off of the higher cost Second Lien Credit Facility with the proceeds from the issuance of the Convertible Notes, which bore interest at a lower rate, and due to higher capitalized interest as a result of increased unproved leasehold costs in 2008. These decreases were partially offset by increased debt outstanding during 2008.

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)(1)			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 (i) approximately $3.3 million in higher transportation gathering and treating costs in the Barnett Shale, (ii) higher saltwater disposal costs of $2.2 million, (iii) increased compression costs of $1.1 million, (iv) higher severance taxes of $0.9 million and (v) increased workover expenses of $0.4 million.

     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.

     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 (i) increased employee related costs of $2.5 million, (ii) increased stock-based compensation expense of $2.0 million due to additional restricted shares issued in 2007 and higher stock prices (iii) increased office expense of $0.6 million and (iv) increased legal and professional fees of $0.3 million. These increases were partially offset by decreased bad debt expense of $1.4 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 (i) $7.4 million of unrealized mark-to-market net losses on derivatives ($4.6 million loss on oil and gas derivatives and $2.8 million loss on interest rate swaps) and (ii) $6.0 million of net realized gains ($5.8 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 our senior credit facility and higher effective interest rates.

Liquidity and Capital Resources

     2009 Capital Budget and Funding Strategy. For 2009, our Board has established a capital and exploration expenditures budget of $105 million, including (i) $90 million for our drilling program (including $85 million for the Barnett Shale development), (ii) $3 million for pre-development project costs in the U.K. North Sea (iii) $6 million for lease acquisitions, primarily in the Barnett Shale and (iv) $6 million for seismic data acquisition. We intend to finance our 2009 capital and exploration budget primarily from oil and natural gas production sales revenue, supplemented by borrowings under our senior credit facility and the possible selective sale of non-core assets. We may be required to reduce or defer part of our 2009 capital expenditures program if we are unable to obtain sufficient financing from these sources.

     Sources and Uses of Cash. During the year ended December 31, 2008, capital expenditures, net of proceeds from property sales, exceeded our net cash provided by operations. During 2008, we funded our capital expenditures with cash generated from operations, proceeds from the issuance of our common stock and convertible notes, and net additional borrowings under our senior credit facility. 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 our senior credit facility. During the fourth quarter of 2008, the borrowing base under our senior credit facility increased to $250.0 million. At March 2, 2009, $71.0 million was available for borrowing under our senior credit facility. The next borrowing base redetermination is currently scheduled for March 31, 2009.
	•		Other debt and equity offerings. In February 2008, we received $135.1 million of net proceeds from an underwritten public offering of 2,587,500 shares of our common stock priced at $54.50 per share. In May 2008, we received $365.3 million of net proceeds from the issuance of our convertible notes. As situations or conditions arise, we may need to issue debt, equity or other instruments to supplement our cash flows. However, we may not be able to obtain such financing on terms that are acceptable to us, or at all.
	•		Asset sales. In order to fund our capital and exploration budget, we may consider the sale of certain properties or assets that are not part of our core business, can be monetized at a price we find acceptable, or are no longer deemed essential to our future growth.
	•		Project financing in certain limited circumstances.
	•		Lease option agreements and land banking arrangements, such as those we have entered into regarding the Marcellus Shale, the Barnett Shale and other plays.
	•		Joint ventures with third parties through which such third parties fund a portion of our exploration activities to earn an interest in our exploration acreage, such as our recent joint venture in the Marcellus Shale play.
	•		We may consider sale/leaseback transactions of certain capital assets, such as pipelines and compressors, which are not part of our core oil and gas exploration and production business.

     Our primary use of cash is capital expenditures related to our drilling and development programs and, to a lesser extent, our lease and seismic acquisition programs. Our capital expenditures budget in 2009 provides for approximately $90 million for drilling, and approximately $12 million for lease and seismic acquisitions. In 2009 we currently plan to drill 45 gross (30.0 net) wells in the Barnett Shale area, three gross (1.0 net) wells in the Gulf Coast area, and to complete 44 gross (44.0 net) wells in the Camp Hill Field, and to spend approximately $3.0 million on project development in the Huntington Field in the U.K. North Sea and 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.

     Overview of Cash Flow Activities. Cash flows provided by operating activities were $148.8 million, $95.2 million and $65.4 million for the years ended December 31, 2008, 2007 and 2006, respectively. The increase from 2007 to 2008 was primarily due to an increase in revenues largely attributable to a 47% increase in production. Natural gas prices have fallen since the third quarter of 2008 and have generally continued to decline into 2009, having a negative impact on our cash flow from operations and on our 2009 drilling plans. Despite our increase in natural gas production a continued fall in natural gas prices could have a further negative impact on our cash flow from operations and on our 2009 drilling plans.

     Cash flows used in investing activities were $555.3 million for the year ended December 31, 2008 and related primarily to oil and gas property expenditures. 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.

     Net cash provided by financing activities for the year ended December 31, 2008 was $403.7 million and related primarily to net proceeds of $135.1 million from the issuance of common stock in February 2008, net proceeds of $365.3 million from the issuance of senior convertible notes and $401.0 million in additional borrowings under the senior credit facility. These cash proceeds were partially offset by the payoff and termination of the second lien credit facility and partial paydown of the senior credit facility. 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 our 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 our 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 our 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.

Liquidity/Cash Flow Outlook.

     We currently believe that cash generated from operations, supplemented by borrowings under our senior credit facility will be sufficient to fund our immediate needs. Cash generated from operations is primarily driven by production and commodity prices. While we have steadily increased production over the last few years oil and natural gas prices have declined since third quarter of 2008. In an effort to mitigate declining prices, we hedge a portion of our production and, as of March 3, 2009, we have hedged approximately 25,570,000 MMBtu (70 MMcf per day for the year, or 85% of our estimated production from April through December 2009) of our 2009 natural gas production at a weighted average floor or swap price of $6.20 per MMBtu relative to WAHA and Houston Ship Channel prices. We believe the funds available to us under our senior credit facility, $71.0 million at March 2, 2009, will be accessible to us. We are scheduled for a borrowing base redetermination on March 31, 2009 at which time our borrowing base may change. We currently expect that our borrowing base will increase based upon the increase to our proved reserves during the fourth quarter of 2008. However, the borrowing base is also affected by the future sales price assumptions for our oil and natural gas production that our banks use in their calculations and these may result in a lower borrowing base if our banks believe that the price we will receive for our oil and natural gas production is substantially less than what their current assumptions are.

     If cash from operations and funds available under our senior credit facility are insufficient to fund our 2009 capital and exploration budget, we may need to reduce our capital and exploration budget or seek other financing alternatives to fund it. We may not be able to obtain financing needed in the future on terms that would be acceptable to us, or at all. If we cannot obtain adequate financing, we may be required to limit or defer our planned 2009 natural gas and oil exploration and development program, thereby adversely affecting the recoverability and ultimate value of our natural gas and oil properties. The recent worldwide financial and credit crisis has adversely affected our ability to access the capital markets.

Contractual Obligations

     The following table sets forth estimates of our contractual obligations as of December 31, 2008:

		Payments Due by Year
		(In thousands)
																						2013 and
		Total				2009				2010				2011				2012				Thereafter
Long-term Debt		$	533,230			$	173			$	148			$	159			$	159,000			$	373,750
Operating Leases			3,212				1,008				1,102				1,102				—				—
Drilling Contracts			58,937				25,294				25,295				8,348				—				—
Pipeline Volume Commitment(1)			46,976				6,273				7,144				6,479				5,857				21,223
Total Contractual Cash Obligations		$	642,355			$	32,748			$	33,689			$	16,088			$	164,857			$	394,973

Off Balance Sheet Arrangements

     We currently do not have any off balance sheet arrangements.

Financing Arrangements

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. The Senior Credit Facility provided 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 proved oil & gas assets and is guaranteed by our subsidiaries CCBM, Inc., CCLR, Inc., Carrizo (Marcellus) LLC and Carrizo Marcellus Holding Inc.

     In the fourth quarter of 2008, we amended the Senior Credit Facility to (1) increase the borrowing base to $250.0 million; (2) extend the maturity date to October 29, 2012; (3) increase the maximum total net debt to Consolidated EBITDAX to 4.0 to 1.0; (4) change the semi-annual borrowing base redetermination dates to March 31 and September 30; (5) change the interest rate provisions; and (6) replace JPMorgan Chase with Guaranty Bank as the administrative agent bank.

     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 is (a) 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 (b) a margin between 0.75% and 2.25% (depending on the then-current level of borrowing base usage), but such interest rate can never be lower than the adjusted Daily LIBO rate on such day plus a margin between 2.0% to 3.5% (depending on the current level of borrowing base usage). The interest rate on each Eurodollar loan is the adjusted daily LIBO rate plus a margin between 2.0% to 3.5% (depending on the then-current level of borrowing base usage). At February 17, 2009, the average interest rate for amounts outstanding under the Senior Credit Facility was 3.4%.

     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 4.0 to 1.0. Although we currently believe that we can comply with all of our financial covenants with the business plan that we have put in place, our business plan is based on a number of assumptions, the most important of which is a relatively stable, natural gas price at economically sustainable levels. If the price that we receive for our natural gas production deteriorates significantly from current levels, it could lead to lower revenues, cash flow and earnings, which in turn could lead to a default under certain financial covenants in our Senior Credit Facility, including the financial covenants discussed above. In order to provide a further margin of comfort with regards to these financial covenants, we may seek to further reduce our capital and exploration budget, sell non-strategic assets, opportunistically modify or increase our natural gas hedges or approach the lenders under our Senior Credit Facility for modifications of either or both of the financial covenants discussed above. There can be no assurance that we will be able to successfully execute any of these strategies, or if executed, that they will be sufficient to avoid a default under our Senior Credit Facility if a precipitous decline in natural gas prices were to occur in the future. 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, 2008, we were in compliance with all of our debt covenants.

     As of March 2, 2009, we had $179.0 million of borrowings outstanding and a borrowing base availability of $71.0 million.

     Convertible Senior Notes

     In May 2008, we issued $373.8 million aggregate principal amount of 4.375% convertible senior notes due 2028 (“Convertible Senior Notes”). Interest is payable on June 1 and December 1 each year, commencing December 1, 2008. The notes will be convertible, using a net share settlement process, into a combination of cash and our common stock that entitles holders of the Convertible Senior Notes to receive cash up to the principal amount ($1,000 per note) and common stock in respect of the remainder, if any, of our conversion obligation in excess of such principal amount. The notes are convertible into our common stock at a ratio of 9.9936 shares per $1,000 principal amount of notes, equivalent to a conversion price of approximately $100.06. This conversion rate is subject to adjustment upon certain corporate events. In addition, if certain fundamental changes occur on or before June 1, 2013, we will in some cases increase the conversion rate for a holder electing to convert notes in connection with such fundamental change; provided, that in no event will the total number of shares issuable upon conversion of a note exceed 14.7406 per $1,000 principal amount of notes (subject to adjustment in the same manner as the conversion rate). Holders may convert the notes only under the following conditions: (a) during any calendar quarter if the last reported sale price of our common stock exceeds 130 percent of the conversion price for at least 20 trading days in a period of 30 consecutive trading days ending on the last trading day of the immediately preceding calendar quarter, (b) during the five business days after any five consecutive trading day period in which the trading price per $1,000 principal amount of the notes is equal to or less than 97% of the conversion value of such notes, (c) during specified periods if specified distributions to holders of our common stock are made or specified corporate transactions occur, (d) prior to the close of business on the business day preceding the redemption date if the notes are called for redemption or (e) on or after March 31, 2028 and prior to the close of business on the business day prior to the maturity date of June 1, 2028. The holders of the Convertible Senior Notes may require us to repurchase the notes on June 1, 2013, 2018 and 2023, or upon a fundamental corporate change at a repurchase price in cash equal to 100 percent of the principal amount of the notes to be repurchased plus accrued and unpaid interest, if any. We may redeem notes at any time on or after June 1, 2013 at a redemption price equal to 100 percent of the principal amount of the notes to be redeemed plus accrued and unpaid interest, if any.

     The Convertible Senior Notes are subject to customary non-financial covenants and events of default, including a cross default under the Senior Credit Facility, the occurrence and continuation of which could result in the acceleration of amounts due under the Convertible Senior Notes.

     The Convertible Senior Notes are unsecured obligations and rank equal to all future senior unsecured debt but rank second in priority to the Senior Credit Facility.

     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”). The Second Lien Credit Facility, as amended, provided for a term loan facility in an aggregate principal amount of $225.0 million. In May 2008, we repaid in full the $219.9 million outstanding under the Second Lien Credit Facility and terminated the facility in connection with the issuance of the Convertible Senior Notes.

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

     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, raising $135.1 million of net proceeds. With a portion of the proceeds we repaid $85.0 million of borrowings then outstanding under the Senior Credit Facility. We used 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, raising $72.0 million of net proceeds. 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 Commission. 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.

Lease Option Arrangements

     Due to the limited capital available at times to fund all of our ongoing lease acquisition efforts in the Barnett Shale, Marcellus Shale, Fayetteville Shale and other plays, we elect from time to time to enter into various lease purchase option agreements with a number of third parties, including, in 2006, Steven A. Webster, who is the Chairman of our Board of Directors. The lease purchase option arrangement with Mr. Webster expired at the end of 2006. The terms and conditions of the lease purchase option arrangement with Mr. Webster were consistent with the lease purchase option arrangements we entered into with unrelated third parties. These lease purchase option arrangements provide us 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. We paid Mr. Webster fees totaling approximately $250,000 in 2006. In accordance with the lease purchase option agreement, we also assigned to him an overriding royalty interest on any lease we acquired from Mr. Webster under the lease purchase option agreement with him, which overriding royalty interest varied from one-half to one percent of 8/8ths, proportionally reduced to the actual net interest in any given lease acquired from Mr. Webster. We paid Mr. Webster approximately $430 and $50 in 2008 and 2007, respectively, for overriding royalties under these arrangements.

     In order to expand our lease acquisition efforts in the Marcellus Shale play, the Company elected to enter into a lease option agreement effective August 1, 2008 with Avista, our partner in the Marcellus Shale play. See “Business and Properties—Significant Project Areas; Marcellus Shale Area.” The terms and conditions of the lease purchase option arrangement with Avista were generally consistent with lease option arrangements that we have traditionally entered into with other third parties. Avista paid approximately $27.5 million for the oil and gas leases under the lease purchase option agreement and subsequently contributed these properties at their cost to our Marcellus joint venture, effective August 1, 2008.

     We have continued to enter into lease purchase option arrangements with third parties from time to time. We currently have one lease purchase option arrangement with an unrelated third party. Strategically, these leasing arrangements have allowed us to temporarily control important acreage positions during periods that we have lacked sufficient capital to directly acquire such oil and gas leases. We may continue to use these arrangements as a strategic alternative in the future.

Effects of Inflation and Changes in Price

     Our results of operations and cash flows are affected by changing natural gas and oil prices. The dramatic drop in natural gas and oil prices in 2008 has resulted in a significant drop in revenue per unit of production. Although operating costs have come down slightly in recent months, the rate of decline in natural gas and oil prices has been substantially greater. Historically, inflation has had a minimal effect on us. However, with interest rates at historic lows and the government attempting to stimulate the economy through rapid expansion of the money supply in recent months, inflation could become a significant issue in the future.

Recently Issued Accounting Pronouncements

     In March 2008, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 161, Disclosures about Derivative Instruments and Hedging Activities (“SFAS No. 161”). This standard is intended to improve financial reporting by requiring transparency about the location and amounts of derivative instruments in an entity’s financial statements, how derivative instruments and related hedged items are accounted for under SFAS No. 133, and how derivative instruments and related hedged items affect an entity’s financial position, financial performance and cash flows. The provisions of SFAS No. 161 are effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2008. We do not believe the adoption of SFAS No. 161 will have a significant effect on our consolidated financial position, results of operations or cash flows.

     In May 2008, the FASB issued FASB Staff Position (FSP) Accounting Principles Board (APB) 14-1, “Accounting for Convertible Debt Instruments That May Be Settled in Cash upon Conversion (Including Partial Cash Settlement).” This FSP clarifies that convertible debt instruments that may be settled in cash upon conversion, including partial cash settlement, are not addressed by paragraph 12 of APB Opinion No. 14, “Accounting for Convertible Debt and Debt Issued with Stock Purchase Warrants.” Additionally, this FSP specifies that issuers of such instruments should separately account for the liability and equity components in a manner that will reflect the entity’s nonconvertible debt borrowing rate when interest cost is recognized in subsequent periods. This FSP is effective for financial statements issued for fiscal years beginning after December 15, 2008 and early adoption is not permitted. We currently expect to value the 4.375% Senior Convertible Notes due 2028 as $309.6 million of debt and $64.2 million of equity representing the fair value of the conversion premium. Our effective interest rate is expected to be approximately 8%. After implementation of this standard, the FSP requires retrospective application which is expected to increase the Company’s 2008 interest expense by approximately $6 million and increase the Company’s future interest expense by approximately $12 million annually through May 2013 before consideration of any amounts that may be capitalized.

     In June 2008, the FASB issued FSP Emerging Issues Task Force (EITF) 03-6-1, “Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities.” This FSP provides that unvested share-based payment awards that contain non-forfeitable rights to dividends or dividend equivalents, whether paid or unpaid, are participating securities and shall be included in the computation of both basic and diluted earnings per share. We do not currently expect the adoption of this FSP to have a material impact to our consolidated financial statements and disclosures.

     On December 31, 2008, the Securities and Exchange Commission (SEC) adopted major revision to its rules governing oil and gas company reporting requirements. These include provisions that permit the use of new technologies to determine proved reserves and that allow companies to disclose their probable and possible reserves to investors. The current rules limit disclosure to only proved reserves. The new disclosure requirements also require companies to report the independence and qualification of the person primarily responsible for the preparation or audit of reserve estimates, and to file reports when a third party is relied upon to prepare or audit reserves estimates. The new rules also require that the present value of oil and gas reserves be reported and to be used in the full-cost ceiling test calculation be based upon an average price for the prior 12-month period. The new oil and gas reporting requirements are effective for annual reports on Form 10-K for fiscal years ending on or after December 31, 2009, with early adoption not permitted. The Company is in the process of assessing the impact of these new requirements on its financial position, results of operations and financial disclosures.

Recently Adopted Accounting Pronouncements

     We adopted the Statement of Financial Accounting Standards No. 157, “Fair Value Measurement” (“SFAS No. 157”), effective January 1, 2008. SFAS No. 157 provides a framework for measuring fair value and enhances related disclosures. The implementation of SFAS No. 157 did not change our current valuation method and did not have a material effect on our consolidated financial position or results of operations. We included additional disclosures in the Notes to Consolidated Financial Statements with respect to the measurement of our assets and liabilities at fair value on the balance sheet date.

     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 affected 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 $7.8 million, $4.5 million and $3.5 million in 2008, 2007 and 2006, 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 2008, 2007 and 2006 was $2.23, $2.36 and $2.61, 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.

     The Full Cost Ceiling impairment at the end of 2008 of approximately $138.6 million was based upon average realized oil, natural gas liquids and natural gas prices of $40.12 per Bbl, $19.62 per Bbl and $4.99 per Mcf, respectively, or a volume weighted average price of $29.86 per BOE. We would not have had a Full Cost Ceiling write-down at an estimated volume weighted average price of $36.11 per BOE. The Full Cost Ceiling impairment was primarily the result of the decline in commodity prices. The prices used in the ceiling test impairment were the prices in effect at December 31, 2008, as contemplated by current Commission rules that require the use of prices in effect on the last day of the relevant financial period. These rules are expected to change in the future to require the use of an average price over a twelve-month period.

     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 239.1 Bcfe, 185.8 Bcfe and 126.2 Bcfe of proved undeveloped reserves, representing 48%, 53% and 60% of our total proved reserves at December 31, 2008, 2007 and 2006, respectively. As of December 31, 2008, less than 13% of these proved undeveloped reserves, or approximately, 29.9 Bcfe, were 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 non-depleted 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), (6) an estimated $2.0 million in 2007 (due to higher depletion expenses) and (7) an estimated $11.7 million in 2008 (comprised of after-tax charges for a $11.0 million full cost ceiling impairment and a $0.7 million depletion expense increase).

     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, 2008 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 Commission 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 Commission 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, 2008.

     As of December 31, 2008, approximately 58% 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, 2008 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 risk underlying our oil and gas production. We also used derivatives to manage the variable interest rate on the Second Lien Credit Facility prior to its termination in May 2008. 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, 2008, 2007 and 2006 were treated as non-designated derivatives and the unrealized gains 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 have declined significantly since mid-2008, and lower prices will negatively affect our financial condition planned, capital expenditures and results of operations.”

     We periodically review the carrying value of our oil and natural gas properties under the full cost accounting rules of the Commission. See “—Summary of Critical Accounting Policies—Oil and Natural Gas Properties” and “Item 1A. Risk Factors— We may record ceiling limitation write-downs that would reduce our shareholders’ equity.”

     To mitigate some of our commodity price risk, we engage periodically in certain other limited derivative activities including price swaps, costless collars and, occasionally, put options, in order to establish some price floor protection. We do not hold or issue derivative instruments for trading purposes.

     The following table includes oil and natural gas derivative positions settled during the years ended December 31, 2008, 2007 and 2006 and the unrealized gain (loss) associated with the outstanding oil and natural gas derivatives at December 31, 2008, 2007 and 2006.

		December 31,
		2008				2007				2006
Oil positions settled (Bbls)			64,100				52,000				82,200
Natural gas positions settled (MMBtu)			15,733,000				7,846,000				5,481,000
Realized gain ($ millions) (1)		$	0.6			$	5.8			$	6.8
Unrealized gain (loss) ($ millions) (1)		$	38.6			$	(4.6	)		$	8.7

     At December 31, 2008, approximately 69% of our open natural gas hedges were with Credit Suisse and the remaining 31% were with Shell Energy North America (US), L.P. The open oil hedges were with Credit Suisse.

     While the use of hedging arrangements limits the downside risk of adverse price movements, it may also limit our ability to benefit from increases in the prices of natural gas and oil. We enter into the majority of our derivative transactions with two counterparties and have a netting agreement in place with those counterparties. We do not obtain collateral to support the agreements but monitor the financial viability of counterparties and believe our credit risk is minimal on these transactions. Under these arrangements, payments are received or made based on the differential between a fixed and a variable product price. These agreements are settled in cash at expiration or exchanged for physical delivery contracts. In the event of nonperformance, we would again be exposed to price risk. We have additional risk of financial loss because the price received for the product at the actual physical delivery point may differ from the prevailing price at the delivery point required for settlement of the hedging transaction. Moreover, our derivative arrangements generally do not apply to all of our production and thus provide only partial price protection against declines in commodity prices. We expect that the amount of our hedges will vary from time to time.

     Our natural gas derivative transactions are generally settled based upon the average of the reporting settlement prices on the Houston Ship Channel or WAHA index for the last three trading days of a particular contract month. Our oil derivative transactions are generally settled based on the average reporting settlement prices on the West Texas Intermediate index for each trading day of a particular calendar month.

     At December 31, 2008 we had the following open derivative positions:

		Natural Gas Swaps								Natural Gas Collars												Basis Differential Swaps(2)
						Average								Average				Average
Quarter		MMbtu				Fixed Price(1)				MMBtu				Floor Price(1)				Ceiling Price(1)				MMBtu				Price
First Quarter 2009			2,803,000			$	6.13				2,520,000			$	7.37			$	9.10				310,000			$	0.31
Second Quarter 2009			1,547,000				5.40				2,548,000				7.12				8.85				—				—
Third Quarter 2009			—				—				2,576,000				7.16				8.88				920,000				0.31
Fourth Quarter 2009			—				—				2,576,000				7.17				8.90				—				—
First Quarter 2010			—				—				1,620,000				7.92				9.63				—				—
Second Quarter 2010			—				—				1,638,000				7.18				8.89				—				—
Third Quarter 2010			—				—				1,656,000				7.35				9.06				—				—
Fourth Quarter 2010			—				—				1,656,000				7.45				9.16				—				—
First Quarter 2011			—				—				450,000				9.70				11.70				—				—
Second Quarter 2011			—				—				455,000				8.25				10.25				—				—
Third Quarter 2011			—				—				460,000				8.65				10.65				—				—
Fourth Quarter 2011			—				—				460,000				8.85				10.85				—				—
First Quarter 2012			—				—				455,000				9.55				11.55				—				—
Second Quarter 2012			—				—				455,000				8.35				10.35				—				—
TOTAL			4,350,000								19,525,000												1,230,000